Annual Information Form for the year ended December 31, 2011

EX-99.1 2 d298140dex991.htm ANNUAL INFORMATION FORM FOR THE YEAR ENDED DECEMBER 31, 2011 Annual Information Form for the year ended December 31, 2011

Exhibit 99.1

LOGO

ALGONQUIN POWER & UTILITIES CORP.

ANNUAL INFORMATION FORM

March 30, 2012

TABLE OF CONTENTS


	Page

1. CORPORATE STRUCTURE		1

1.1 Name, Address and Incorporation		1
1.2 Intercorporate Relationships		1
(a) Subsidiaries		1
(b) Other Interests in Energy Related Developments		7

2. GENERAL DEVELOPMENT OF THE BUSINESS		8

2.1 General		8

(a) The Unit Exchange		8
(b) Business Strategy		8

2.2 Three Year History		10

(a) Fiscal 2009		10
(b) Fiscal 2010		11
(c) Fiscal 2011		13

2.3 Recent Developments - 2012		16
2.4 Significant Acquisitions and Investments - 2011		22

3. DESCRIPTION OF THE BUSINESS		24

3.1 General Description of the Regulatory Regimes in which the Business Operates		24

(a) Power Generation Regulatory Regimes		24
(b) Water Utility Services Regulatory Regimes		26
(c) Electrical Utility Services Regulatory Regimes		26

3.2 Production Method, Principal Markets, Distribution Methods and Material Facilities		27

(a) Power Generation: Renewable - Hydroelectric		27
(b) Power Generation: Renewable - Wind Power		34
(c) Power Generation: Thermal - Energy From Waste		36
(d) Power Generation: Thermal - Cogeneration		37
(e) Power Generation: Algonquin Energy Services		42
(f) Power Generation: Development		43
(g) Utilities: Water and Wastewater		47
(h) Liberty Utilities: Electrical Distribution		51

3.3 Revenues for 2011 and 2010		54
3.4 Specialized Skill and Knowledge		54
3.5 Competitive Conditions		55
3.6 Environmental Protection		56
3.7 Employees		57
3.8 Foreign Operations		57
3.9 Cycles and Seasonality		58
3.10 Customers		59
3.11 Economic Dependence		59
3.12 Social or Environmental Policies		59

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TABLE OF CONTENTS

(continued)


	Page

4. RISK FACTORS		60

4.1 Treasury Risk Management		60

(a) Foreign currency risk		60
(b) Market price risk		61
(c) Credit/Counterparty risk		61
(d) Interest rate risk		62
(e) Liquidity risk		63
(f) Commodity price risk		64
(g) Risk of Default under Senior Credit Facility		65

4.2 Operational Risk Management		66

(a) Mechanical and Operational Risks		66
(b) Asset Retirement Obligations		67
(c) Environmental Risks		69
(d) Cycles and Seasonality Risk		70
(e) Specific Environmental Risks		71
(f) Litigation risks and other contingencies		74
(g) Tax Related Risks		74
(h) Tax Risks Associated with the Unit Exchange		74
(i) Obligations to Serve		75

4.3 Regulatory Climate and Permitting Risks		75
4.4 Dependence upon APUC Businesses		76
4.5 Safety Considerations		77
4.6 Labour Relations		77
4.7 Dependence Upon Key Customers		78
4.8 Potential Conflicts of Interest		78
4.9 Construction / Development Risk		78
4.10 Acquisitions and Divestitures		78

5. DIVIDENDS		79

5.1 Dividend Reinvestment Plan		79

6. DESCRIPTION OF CAPITAL STRUCTURE		80

6.1 Common Shares		80
6.2 Preferred Shares		81
6.3 Convertible Debentures		81

(a) Series 1A Debentures		81
(b) Series 2A Debentures		81
(c) Series 3 Debentures		82

6.4 Employee Share Purchase Plan		87
6.5 Directors Deferred Share Units		87
6.6 Performance Share Units		88
6.7 Shareholders’ Rights Plan		88
6.8 Stock Option Plan		88

7. MARKET FOR SECURITIES		92

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TABLE OF CONTENTS

(continued)


	Page

7.1 Trading Price and Volume		92

(a) Common Shares		92
(b) Series 1A Debentures		93
(c) Series 2A Debentures		93
(d) Series 3 Debentures		93

7.2 Prior Sales		94
7.3 Escrowed Securities and Securities Subject to Contractual Restrictions on Transfer		95

8. DIRECTORS AND OFFICERS		95

8.1 Name, Occupation and Security Holdings		95
8.2 Audit Committee		98

(a) Audit Committee Charter		98
(b) Relevant Education and Experience		98
(c) Pre-Approval Policies and Procedures		99

8.3 Corporate Governance and Compensation Committees		99
8.4 Bankruptcies		100
8.5 Potential Material Conflicts of Interest		100

9. LEGAL PROCEEDINGS AND REGULATORY ACTIONS		100

9.1 Legal Proceedings		100

(a) Trafalgar		100
(b) Côte Ste-Catherine Water Lease Dues		101
9.2 Regulatory Actions		101

10. INTEREST OF MANAGEMENT AND OTHERS IN MATERIAL TRANSACTIONS		101

11. TRANSFER AGENTS AND REGISTRARS		102

12. MATERIAL CONTRACTS		102

13. INTERESTS OF EXPERTS		104

14. ADDITIONAL INFORMATION		104

SCHEDULE A		A-1

SCHEDULE B		B-1

SCHEDULE C		C-1

SCHEDULE D		D-1

SCHEDULE E		E-1

SCHEDULE F		F-1

SCHEDULE G		G-1

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All information contained in this Annual Information Form (“AIF”) is presented as at March 30, 2012, unless otherwise specified. In this AIF, all dollar figures are in Canadian dollars, unless otherwise indicated.

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1.	CORPORATE STRUCTURE

1.1

Name, Address and Incorporation

Algonquin Power & Utilities Corp. (“APUC” or the “Corporation”) was originally incorporated under the Canada Business Corporations Act (“CBCA”) on August 1, 1988 as Traduction Militech Translation Inc. Pursuant to articles of amendment dated August 20, 1990 and January 24, 2007, the corporation amended its articles to change its name to Societe Hydrogenique Incorporée – Hydrogenics Corporation and Hydrogenics Corporation – Corporation Hydrogenique, respectively. Pursuant to a certificate and articles of arrangement dated October 27, 2009, the corporation, among other things, created a new class of common shares (the “Common Shares”), transferred its existing operations to newly formed independent corporation and changed its name to Algonquin Power & Utilities Corp. The head and principal office of APUC is located at 2845 Bristol Circle, Oakville, Ontario, L6H 7H7. APUC contemporaneously acquired all of the outstanding trust units of Algonquin Power Co. (“APCo”) (See General Development of the Business—The Unit Exchange).

APUC’s principal holdings are its trust units (“Trust Units”) of APCo and shares of Liberty Utilities Co. (“Liberty Utilities”). Liberty Utilities’ businesses operate under two separately managed regions – Liberty Utilities (South) and Liberty Utilities (West).

Unless the context indicates otherwise, references in this AIF to “APUC” include, for reporting purposes only, the direct or indirect subsidiaries of APUC and partnership interests held by APUC and its subsidiaries. Such use of “APUC” to refer to these other legal entities and partnership interests does not constitute a waiver by APUC or such entities or partnerships of their separate legal status, for any purpose.

1.2

Intercorporate Relationships

(a)

Subsidiaries

The subsidiaries of APUC are grouped into the independent power generation and the utilities businesses. The principal holding for APUC’s independent power generation business is an investment in 100% of the issued and outstanding Trust Units of APCo. The principal holding for APUC’s utilities business is an investment in 100% of the issued and outstanding common shares of Liberty Utilities (Canada) Corp., a federal corporation, which in turn owns all of the issued and outstanding common shares of Liberty Utilities (America) Co., which in turn owns all of the issued and outstanding common shares of Liberty Utilities, a Delaware corporation, which in turn owns and operates the entities within the Liberty Utilities (South) and Liberty Utilities (West) regions. Each of APCo, the Liberty Utilities (South) region and the Liberty Utilities (West) region have their own subsidiaries and ownership chains.

The subsidiaries of APCo include the ownership chains of Algonquin Power Trust (“APT”), and Algonquin Power Fund (Canada) Inc. (“APFC”). APT’s subsidiaries include the ownership chain of Algonquin Power Operating Trust (“APOT”), APFC’s subsidiaries include the ownership chain of and Algonquin Power Fund (America) Inc. (“APFA”). The Liberty Utilities (West) region is currently structured to hold the electric utility assets located in California and acquired January 1, 2011, and the Liberty Utilities (South) region is structured to hold the water distribution and wastewater treatment assets located in the United States.

The following chart summarizes the principal operating subsidiaries of the Corporation and their major lines of business.

LOGO

The major chains are defined below, including a detailed description of the legal entities that comprise these chains and the facilities they own. Additional information on the facilities is described in Schedules A, B, C and D.

(i)

Independent Power Generation Business – APCo Chain

APCo Chain Entities

APCo is the sole beneficiary of APT. APCo also owns Algonquin Holdco Inc., an Ontario corporation, which owns 52.5% of APFC and 62.5% of the issued and outstanding shares of Cornwall Solar Inc.

APT Group

APT forms part of the APCo business unit. APT is an unincorporated open ended trust created by a declaration of trust dated June 30, 2000 in accordance with the laws of the Province of Ontario. APT owns all the Trust Units of APOT.

APT controls the entities that own some of the Canadian hydroelectric facilities, and indirectly owns the energy-from-waste facility (the “EFW Facility”) located in the Regional Municipality of Peel, Ontario (“Peel”) by virtue of owning all the Trust Units in KMS Power Income Fund, an unincorporated open ended trust created by a declaration of trust dated February 18, 1997 in accordance with the laws of the Province of Alberta. This trust owns Algonquin Power Energy From Waste Inc. (“APEFW”), an Ontario corporation that owns the EFW Facility.

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APT also holds interests in certain of APCo’s Canadian hydroelectric Facilities. It directly owns the hydroelectric Hydraska Facility and the Arthurville Facility, and owns both the general partnership and the limited partnership interests in Algonquin Power (Campbellford) Limited Partnership (“Campbellford LP”), an Ontario limited partnership which operates a 4 megawatt (“MW”) hydroelectric generation station on the Trent River near Campbellford, Ontario (the “Campbellford Facility”). APT also holds a 42% limited partnership interest in the Algonquin Power (Mont-Laurier) Limited Partnership (the “Mont-Laurier Partnership”), a Québec limited partnership, which owns the Mont-Laurier and the Côte Ste.-Catherine Facilities. APEFW owns the remaining 58% partnership interests, comprised of a 46.5% limited partnership interest and an 11.5% general partnership interest.

APT owns Corporation D’Investissements Éoliennes Algonquin Power (“Éoliennes”), a Canadian corporation. Éoliennes indirectly owns St. Ulric Wind Energy Investments L.P. (“St. Ulrich LP”), a Québec limited partnership, through its ownership of the limited partnership of St. Ulrich LP and Société en Commandite Algonquin (Éoliennes), a Québec limited partnership, and its direct ownership of the general partner of St. Ulrich LP, named Corporation D’Investissements Éoliens St-Laurent Inc. (“Corporation St-Laurent”), a Québec corporation. Corporation St-Laurent is the 50% owner of Saint-Damase Wind Energy Fleur de Lis General Partner Corporation, a federal corporation, which is the general partner of the partnership known as Saint-Damase Wind Energy Fleur de Lis Limited Partnership (“Fleur de Lis LP”). Fleur de Lis LP has an interest in the Saint—Damase wind energy project and described below in “Description of the business – Production Method, Principal Markets, Distribution Methods and Material Facilities – Power Generation: Development—Current Development Projects”. St. Ulrich LP owns a 49.995% equity interest in the Fleur de Lis LP, the general partner owns a .02% equity interest, and a non-Algonquin, Saint-Damase party owns the remaining 49.995% equity interest. APT also has an interest in Société Éoliennes Belle- Rivière, société en commandite (“Belle Rivière”), a Quebec partnership and the owner of the Val- Éo wind energy project, also described below in “Description of the business – Production Method, Principal Markets, Distribution Methods and Material Facilities – Power Generation: Development—Current Development Projects”. It owns a 25% equity interest in the general partner, 9231-5498 Québec Inc. and it also holds a 24.9975% limited partner interest.

APOT Group

APOT is an unincorporated open ended trust created by an amended and restated trust indenture effective January 2, 1997, in accordance with the laws of the Province of Alberta.

APOT controls the entities that own the Canadian cogeneration facility located at Brampton, Ontario (the “BCI Facility”). The BCI Facility is owned by Brampton Cogeneration Limited Partnership, an Ontario partnership, the partners of which are Brampton Cogeneration Inc. (“BCI”), which is the general partner and holds one general partnership unit, and APOT, which owns 100% of the Class A Units (entitled to vote on all matters) and 50% of the Class B Units (vote on only specific matters) in the limited partnership. BCI is an Ontario corporation and is owned by APOT.

APOT controls the entities that own the 104 MW wind facility located at St. Leon, Manitoba (the “St. Leon Facility”). The APOT entity that owns the St. Leon Facility is St. Leon Wind Energy LP, an Ontario partnership (“St. Leon LP”). It is owned by the general partner, St. Leon Wind Energy GP Inc. (“St. Leon GP”), by St. Leon Wind Energy Trust, a Manitoba trust (“St. Leon Trust”) and by AirSource Power Fund I LP, a Manitoba limited partnership (“AirSource”). St.

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Leon LP holds a 47.5% interest in APFC. St. Leon LP has issued 100 Class B limited partnership units. Two executives of APUC, Ian Robertson and Christopher Jarratt (the “Senior Executives”) indirectly each own 18 of the 100 Class B units. St. Leon Trust is owned 100% by AirSource, the limited partner of which is Algonquin (AirSource) Power LP (“AAP LP”) which holds a 99.99% interest in the limited partnership, and which in turn is owned 99.99% by APOT as limited partner. APOT also controls the general partner of AAP LP, AirSource Power Fund GP Inc, a Canadian corporation. AirSource is also the 100% owner of St. Leon GP. St. Leon GP is a Canadian corporation and St. Leon Trust is a trust created by a declaration of trust dated June 28, 2005 in accordance with the laws of the Province of Manitoba. The AirSource and AAP LP limited partnerships were formed in Manitoba and Ontario, respectively.

APOT is the sole limited partner in St. Leon II Wind Energy LP (“St. Leon II”), a Manitoba partnership, the general partner of which is St. Leon II Wind Energy GP Inc. which is also owned by APOT. St. Leon II owns the 16.5 MW wind facility (the “St. Leon II Facility”), an expansion of the St. Leon Facility, located at St. Leon, Manitoba.

APOT is the sole limited partner in Red Lily Wind Power II Limited Partnership, a Saskatchewan limited partnership, the general partner of which is Red Lily Wind Power II GP Inc., a Saskatchewan corporation, which is also owned by APOT. APOT also owns Loyalist Wind Project GP Inc., an Ontario corporation, which is the general partner of Loyalist Wind Project LP (“Loyalist LP”), an Ontario limited partnership. APUC is the majority limited partner of Loyalist LP, holding a 87.49125% interest. The remaining limited partner of Loyalist LP is an unrelated third party, holding a 12.49875% interest.

APOT has two ownership interests in Alberta. First, it is the beneficial owner of one hydroelectric facility in Alberta (the “Dickson Dam Facility”). APOT owns 50% of Valley Power Corp., an Ontario corporation, which holds a 0.0001% limited partnership interest partner in Valley Power LP, an Alberta limited partnership which owns the Alberta biomass facility (the “Valley Power Facility”). APOT also directly holds a 49.9995% limited partnership interest in Valley Power LP.

APFC Group

APFC was incorporated in Nova Scotia and it controls the entities that own the majority of the hydroelectric facilities in Canada. APFC owns Algonquin Power (America) Inc., (“APA”) a Delaware corporation, which is the parent company of APCo’s operations in the United States.

In Ontario, APFC directly owns the Burgess and Hurdman Facilities, and has an agreement in place to buy ownership interests in the parties to the joint venture that owns the interests in the Long Sault Rapids Facility. In Québec, APFC directly owns the facilities known as Rawdon, Hydro Snemo, St. Raphael, Belleterre and St. Brigette Facilities. APFC also holds a direct interest in Société Hydro-Donnacona, S.E.N.C. (the “S.E.N.C.”), the owner of the Donnacona Facility. The S.E.N.C. is a Québec general partnership, and is owned 99.99% by APFC and 0.01% by Donnacona Holdings Inc., an Ontario corporation 100% owned by APFC. In Newfoundland, APFC holds a 45% partnership interest in the Algonquin Power (Rattlebrook) Partnership, a Newfoundland partnership that owns the Rattlebrook Facility. APFC also 100% owns Algonquin Power Services Canada Inc., a Canadian corporation that provides purchasing services to Canadian APCo entities.

APFC also 1631667 Alberta ULC, an Alberta unlimited liability corporation.

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APFA Group

APFA, a Delaware corporation, is owned by APA. APFA owns and controls the U.S. hydroelectric entities, and also controls the entities that own the U.S. thermal cogeneration facilities.

APFA owns Algonquin Power Sanger LLC (“Sanger LLC”), a California limited liability company, and Algonquin Power Windsor Locks LLC (“Windsor LLC”), a Connecticut limited liability company. These entities own the U.S. cogeneration Sanger and Windsor Locks facilities. Sanger LLC directly owns 100% of Dyna Fibers Inc., a California corporation that operates a hydro-mulch business at the Sanger Facility site. APFA also owns KMS Crossroads, LLC, a Delaware limited liability corporation.

APFA indirectly owns numerous hydroelectric facilities through majority interests ranging from 99.7 to 99.99% in the subsidiaries described in this paragraph, with Algonquin Power Fund (America) Holdco Inc. (“Algonquin Holdco”), a Delaware corporation owned by APFA, holding the remaining interests. The New York general partnerships Burt Dam Power Company and Hollow Dam Power Company own the Burt Dam and Hollow Dam Facilities, respectively. The Vermont partnership Moretown Hydro Energy Company owns the Moretown Facility. The New Hampshire limited partnerships Gregg Falls Hydroelectric Associates Limited Partnership, Pembroke Hydro Associates Limited Partnership and Mine Falls Hydroelectric Limited Partnership own the Gregg Falls, Pembroke and Mine Falls Facilities, respectively.

APFA owns the New Hampshire limited liability company Clement Dam Hydroelectric, LLC which owns the Clement Dam Facility. The Franklin, Beaver Falls and Lakeport Facilities are owned by, respectively, Franklin Power, LLC, a New Hampshire company, Algonquin Power (Beaver Falls) LLC, a Delaware corporation and Lakeport Hydroelectric Corp., a New Hampshire corporation. The Otter Creek and Kings Falls Facilities are owned by Tug Hill Energy, Inc. a New York corporation, which is owned by Court Street Investments, Inc. (“Court Street”), a Massachusetts corporation, which in turn is owned 100% by APFA. Court Street also owns CSI Oswego Corp., a Delaware corporation, which is a partner in Oswego Hydro Partners L.P., the Delaware partnership that owns the Phoenix Facility. The other partner in this partnership is Oswego Energy Corp., a Delaware corporation, which is 100% owned by Oswego Power Company, Inc., a Massachusetts corporation, which in turn is 100% owned by APFA. The remaining hydroelectric facilities in the United States are the Great Falls and Lochmere Facilities. The Great Falls Facility is owned by the Great Falls Hydroelectric Company Limited Partnership, a Maryland limited partnership in which APFA holds a 98% limited partner interest. Great Falls Energy, LLC holds the remaining 2% general partner interest. Great Falls Energy, LLC is a Maryland limited liability company wholly owned by APFA. The Lochmere Facility is owned by the Indiana general partnership HDI Associates I, which is held 0.1% by Algonquin Holdco and 99.9% by APFA.

APFA owns Algonquin Tinker Gen Co. (“Tinker Gen Co.”) and Algonquin Northern Maine Gen Co. (“Northern Maine Gen Co.”), both Wisconsin companies. Tinker Gen Co. is also registered in New Brunswick, and Northern Maine Gen Co. is also registered in Maine. Tinker Gen Co. operates the 36.8MW of electrical generating assets in New Brunswick (the “Tinker Assets”), and Northern Maine Gen Co. is the owner of the Caribou and Squa Pan diesel facilities. APFA also 100% owns Algonquin Energy Services Inc., a Delaware corporation (“AES”) that is also registered in Connecticut, District of Columbia, Maine, Maryland, New Brunswick and Ohio.

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AES provides the electrical energy requirements for commercial and industrial customers in northern Maine.

In addition, APFA owns 100% of Algonquin Power Acquisition Inc., a Delaware corporation that was incorporated as an acquisition vehicle for proposed acquisitions by APCo in the United States. It currently has no assets. APFC also 100% owns Algonquin Power Services America LLC, a Delaware corporation that provides purchasing services to U.S. APCo entities.

(ii)

Utilities Business

Liberty Utilities (South) Region

Liberty Water Co. (“Liberty Water”), a Delaware company, is the parent company of the entities within the Liberty Utilities (South) region. On December 22, 2010, APCo completed a corporate reorganization involving Liberty Water wherein 100% of the issued and outstanding common shares of Liberty Water Co. were transferred from APCo to Liberty Utilities.

Liberty Water indirectly owns the water and wastewater businesses located in Arizona, Texas, Missouri and Illinois, in each case through a 100% wholly-owned subsidiary, with the exception of Northwest Sewer Inc., which it owns directly and the Entrada Del Oro Sewer Company, Inc. (“Entrada”) which it currently operates and in which it holds a beneficial interest in the shares of the company pending regulatory approval of its acquisition by Liberty Water. All of these 100% wholly-owned subsidiaries (except Northwest Sewer, Inc.) are currently conducting business as “Liberty Water”; however the actual legal names of the relevant entities are set out below.

In Arizona, the following Arizona corporations own the following facilities: Bella Vista Water Co., Inc. owns the Bella Vista Facility; Black Mountain Sewer Corporation owns the Black Mountain Facility; Gold Canyon Sewer Company owns the Gold Canyon Facility; Litchfield Park Service Company owns the Litchfield Facility; Northern Sunrise Water Company, Inc. owns the Northern Sunrise Facility; Rio Rico Utilities, Inc. owns the Rio Rico Facility; and Southern Sunrise Water Company, Inc. owns the Southern Sunrise Facility. Northwest Sewer, Inc., an Arizona corporation, has undertaken to a group of developers and homeowner’s associations located to the west of Phoenix to apply for a Certificate of Convenience and Necessity and, if successful, operate a wastewater treatment utility in those areas. Entrada, discussed above, is an Arizona corporation, and it owns the beneficial interest in the Entrada Del Oro Facility. In Texas, the following Texas corporations own the following facilities: Tall Timbers Utility Company, Inc. owns the Tall Timbers Facility; Woodmark Utilities, Inc. owns the Woodmark Facility; and Algonquin Water Resources of Texas, LLC, a Texas limited liability company, owns water and water treatment assets at the resorts of Seaside, Holly Lake Ranch, Hill County, Piney Shores and The Villages (also known as “Big Eddy”). In Missouri, Algonquin Water Resources of Missouri, LLC, a Missouri limited liability company, owns assets associated with the Holiday Hills, Ozark Mountain, Timber Creek resorts, the water utility in Noel, Missouri and a utility in eastern Missouri. In Illinois, Algonquin Water Resources of Illinois, LLC, an Illinois limited liability company, owns assets for the Fox River resort. All water and wastewater utilities are operated under the Liberty Water brand.

In addition, Algonquin Water Services LLC (“Water Services”) is a company established to manage and operate water distribution and wastewater treatment facilities in Arizona and Texas. It is an Arizona limited liability company owned 99% by New Spring Acquisition Partnership, an Ontario partnership, which in turn is owned 50% by APCo. Algonquin Environmental Services LLC, a Delaware limited liability company owned 100% by Liberty Water, was also established to service various entities.

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Liberty Utilities (West) Region

Liberty Energy Utilities Co. (“Liberty Energy”) is owned by Liberty Utilities and forms the top of the Liberty Utilities (West) region. Liberty Energy is a Delaware corporation. It owns 50.001% of California Pacific Utilities Ventures, LLC, a California limited liability company (“CPUV”), which in turn owns California Pacific Electric Company, LLC, a California limited liability company (“Calpeco”). Calpeco owns an electricity distribution utility in the Lake Tahoe basin and surrounding areas in California.

Liberty Utilities (East) Region

Liberty Energy also owns Liberty Energy Utilities (New Hampshire) Corp. (“Liberty Energy (NH)”), a Delaware corporation registered in New Hampshire. Liberty Energy Utilities (NH) is the named purchaser of the shares of Granite State Electric Company (“Granite State”) and EnergyNorth Natural Gas Inc. (“EnergyNorth”) currently owned by of National Grid USA (“National Grid”).

Liberty Utilities (Central) Region

Liberty Energy also owns Liberty Energy (Midstates) Corp. (“Liberty Midstates”), a Missouri corporation. Liberty Midstates is the named purchaser of certain natural gas distribution utility assets in Missouri, Iowa and Illinois (the “Midwest Gas Utilities”) currently owned by ATMOS Energy Corporation (“Atmos”).

(iii)

Other

Outside of the APCo, Liberty Utilities (South) and Liberty Utilities (West) described above, APUC beneficially owns, directly or indirectly 100% of the following: 3793257 Canada Inc. (“3793257”), a holding company incorporated under the CBCA; and Windlectric Inc. (“Windlectric”), a federal corporation that is developing various wind projects including one in Saskatchewan and one in Ontario.

APUC also owns the following group of special purpose financing companies, including 90% of Liberty Utilities Finance GP 1 (“LU GP1”), a Delaware general partnership. LU GP1 owns 99.9% of Liberty Utilities Finance GP 2 (“LU GP2”), a Delaware general partnership. The minority partner in both LU GP1 and LU GP2 is 3793257. LU GP2 owns Liberty Utilities Finance (Canada) ULC, an Alberta unlimited liability corporation which in turn owns Liberty Utilities Finance (US) LLC, a Delaware limited liability company. The above entities were formed as special purpose financing entities to be used in future Liberty Utilities financings.

(b)

Other Interests in Energy Related Developments

The Corporation also has notes receivable and equity in companies owning generating facilities as described below. APT owns 25% of the Class B non-voting shares issued by Cochrane Power Corporation, the owner of a combined cycle cogeneration facility located in Cochrane, Ontario. APT also owns 32.4% of the Class B non-voting shares in Kirkland Lake Power Corporation, an entity which burns natural gas and wood waste to generate electricity. APT

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also owns a 12.1% interest in Tranche A and Tranche B term loan interests issued by Chapais Energie, Société en Commandité (“Chapais”) which owns a wood waste facility in Chapais, Québec. It also owns a 33.9% interest in the Class B non-voting preferred shares of Chapais. The loans bear interest at the rate of 10.789% and 4.91%, respectively.

In addition, APUC is entitled to a royalty in the form of cash flows generated by the Long Sault Rapids Facility (the “LSR Royalty Interest”). It is also the owner of a 14.14% secured, subordinated note (the “LSR Subordinate Note”) in the principal amount of $2,000,000 issued jointly and severally by Algonquin Power (Long Sault) Corporation Inc., Energy Acquisition (Long Sault) Ltd., Nicholls Holdings Inc. and Radtke Holdings Inc. The LSR Subordinate Note was acquired by APCo on April 17, 1998.

2.	GENERAL DEVELOPMENT OF THE BUSINESS

2.1

General

(a)

The Unit Exchange

On October 27, 2009, APCo (formerly, Algonquin Power Income Fund) completed a transaction (the “Unit Exchange”) in which APCo’s unitholders exchanged their Trust Units of APCo, on a one-for-one basis, for Common Shares of the Corporation (formerly Hydrogenics Corporation). As a result of the Unit Exchange, APCo itself became a wholly-owned subsidiary of the Corporation and all of the unitholders of APCo became shareholders of the Corporation. The Unit Exchange did not result in any change to the underlying business operations of APCo and accordingly, for accounting purposes, the Corporation is considered a continuation of APCo. Through subsequent internal reorganizations Algonquin Power Income Fund has since changed its name to Algonquin Power Co. and remains a subsidiary of APUC.

(b)

Business Strategy

APUC is incorporated under the Canada Business Corporations Act. APUC’s business strategy is to maximize long term shareholder value as a dividend paying, growth-oriented corporation in the independent power and rate regulated utilities business sectors. APUC is committed to delivering a total shareholder return comprised of dividends augmented by capital appreciation arising through dividend growth supported by increasing cash flows and earnings. Through an emphasis on sustainable, long-view renewable power and utility investments, over a medium-term planning horizon, APUC strives to deliver annualized per share earnings growth of more than 5% and continued growth in its dividend supported by these increasing cash flows, earnings and additional investment prospects.

APUC’s current quarterly dividend to shareholders is $0.07 per share or $0.28 per share per annum. APUC believes its annual dividend payout allows for both an immediate return on investment for shareholders and retention of sufficient cash within APUC to fund growth opportunities, reduce short term debt obligations and mitigate the impact of fluctuations in foreign exchange rates. Additional increases in the level of dividends paid by APUC are at the discretion of the APUC Board of Directors (the “Board”) and dividend levels shall be reviewed periodically by the Board in the context of available cash and earnings together with an assessment of the growth prospects available to APUC. APUC strives to achieve its results in the context of a moderate risk profile consistent with top-quartile North American power and utility operations.

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APUC produces stable earnings through a diversified portfolio of renewable power and utility businesses owned and operated by its subsidiary entities. APUC conducts its operations primarily through two businesses: independent power generation and utilities (water, gas and electric). These businesses of APUC are herein referred to as the “APUC Businesses”.

Independent Power Generation: APCo generates and sells electrical energy through a diverse portfolio of renewable power generation and clean thermal power generation facilities across North America. APCo seeks to deliver continuing growth through development of greenfield power generation projects, accretive acquisitions of electrical energy generation facilities as well as development of expansion opportunities within APCo’s existing portfolio of independent power facilities. APCo’s Renewable Energy division develops and operates APCo’s hydroelectric, solar and wind power facilities. APCo’s Thermal Energy division develops and operates co-generation, energy-from-waste, and steam production facilities.

The renewable power and thermal energy generation business of APCo is managed with an emphasis on growth through the development of green-field projects and opportunities within APCo’s existing portfolio. This is achieved through the Development division which seeks to build on APCo’s expertise in the origination of greenfield renewable energy projects, expanding APCo’s existing portfolio of renewable and thermal energy assets for further growth, and capitalizing on new opportunities as they arise.

APCo’s Renewable Energy division generates and sells electrical energy through a diverse portfolio of clean, renewable power generation and thermal power generation facilities across North America. APCo owns or has interests in hydroelectric facilities operating in Ontario, Québec, Newfoundland, New Brunswick, Alberta, New York State, New Hampshire, Vermont, Maine and New Jersey with a combined generating capacity of approximately 165 MW.

APCo also owns wind powered generating stations in Manitoba with a combined generation capacity of 120 MW and holds debt securities in a 26 MW wind powered generating station in Saskatchewan.

All of the wind energy facilities’ electrical output is sold pursuant to long term power purchase agreements (“PPAs”) with major utilities which have a weighted average remaining contract life of 20 years. Approximately 80% of the electrical output from the hydroelectric facilities is sold pursuant to long term PPAs with major utilities which have a weighted average remaining contract life of 8.5 years.

APCo owns thermal energy facilities including an energy-from-waste facility in Ontario, diesel generating facilities in Maine and New Brunswick and natural gas-fired cogeneration facilities in each of California, Connecticut, and Ontario. APCo also holds ownership interests in three facilities in Ontario and Quebec. Approximately 67% of the electrical output from the owned thermal facilities is sold pursuant to long term PPAs with major utilities and which have a weighted average remaining contract life of 11 years. Detailed information on the facilities owned and operated by APCo is set out in Schedules A and B.

Utilities: Liberty Utilities owns and operates utilities through two regions, Liberty Utilities (West) and Liberty Utilities (South). Liberty Utilities (West) is in the electricity distribution, transmission and generation sector. Liberty Utilities (South) is in the water distribution and wastewater treatment sector. The underlying business strategy is to be a leading provider of safe, high quality and reliable utility services while providing stable and predictable earnings from utility

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operations. In addition to encouraging and supporting organic growth within its service territories, Liberty Utilities is focused on delivering continued growth in earnings by identifying acquisition opportunities which provides accretive expansion of its business portfolio.

Liberty Utilities (South) provides water and wastewater utility services to approximately 76,000 customers through 21 water distribution and wastewater collection and treatment utility systems located in Arizona, Illinois, Missouri and Texas. These utilities generally operate under rate regulation, overseen by the public utility commissions of the States in which they operate. Detailed information on the water distribution and wastewater utility systems owned and operated by Liberty Utilities is set out in Schedule C.

Liberty Utilities (West) provides local electrical utility services to approximately 47,000 customers in the Lake Tahoe region of California. Detailed information on the electrical utilities system owned and operated by Liberty Utilities (West) is set out in

Schedule D.

As the currently committed growth initiatives are completed, additional management regions will be created. The Liberty Utilities (East) region will be formed to deliver electrical and natural gas distribution services upon completion of the acquisitions of Granite State and EnergyNorth. The Liberty Utilities (Central) region will be formed to manage natural gas distribution services upon completion of the Midwest Gas Utilities acquisition.

2.2

Three Year History

The following is a description of the general development of the business of the Corporation over the last three fiscal years.

(a)

Fiscal 2009

Corporate

Conversion to a Corporation

On October 27, 2009, APCo and the Corporation completed the Unit Exchange. See “General Development of the Business – General – The Unit Exchange”. As part of the Unit Exchange, on October 27, 2009, the trustees of APCo became the directors of APUC.

Also on October 27, 2009, in connection with the Unit Exchange, the debentureholders of APCo exchanged their convertible debentures for convertible debentures of the Corporation or Common Shares. As a result, the debentureholders of APCo became debentureholders and shareholders of the Corporation. See “Description of Capital Structure – Convertible Debentures”.

ii)

Equity and Convertible Debenture Offering

On December 2, 2009, APUC completed a public offering of (i) 5,980,000 Common Shares at a price of $3.35 per Common Share for gross proceeds of approximately $20 million and (ii) approximately $55 million principal amount of 7% convertible unsecured subordinated debentures due June 30, 2017 (the “Series 3 Debentures” or the “APUC Debentures”). The underwriters of the offering also exercised in full an over-allotment option to purchase an additional 897,000 Common Shares and approximately $8.2 million principal amount of Series 3 Debentures resulting in aggregate gross proceeds of approximately $86.2 million. See “Description of Capital Structure—Convertible Debentures”.

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iii)

Internalization of Management

On December 21, 2009, the Board reached agreement with the shareholders of Algonquin Power Management Inc. (“APMI”) to internalize all management functions of APCo which were previously provided by APMI. APMI was the manager of APCo and APUC up to December 22, 2009 and two executives of APUC, the Senior Executives, are principals of APMI. APUC acquired the interest previously held by APMI in the management services agreement, with consideration paid in the form of issuance of 1,158,748 Common Shares of APUC.

(b)

Fiscal 2010

Corporate

At the annual general meeting on June 23, 2010 (the “Meeting”), APUC adopted a Shareholders’ Rights Plan (the “Rights Plan”). See “Description of Capital Structure—Shareholders’ Rights Plan”.

APCo

– Power Generation

Tinker Facility

On January 12, 2010, APCo completed the acquisition of three hydroelectric generating stations, a 34.5MW hydroelectric generating facility with sufficient reservoir storage capability to move significant amounts of energy from off-peak to on-peak generation located on the Aroostook River near the Town of Perth-Andover, New Brunswick (the “Tinker Facility”), a 0.9MW run-of-river hydroelectric generating facility located in Northern Maine (the “Caribou Facility”) and a 1.4MW run-of-river hydroelectric generating facility located in Northern Maine (the “Squa Pan Facility”).

APCo also acquired certain thermal generating facilities in Northern Maine and New Brunswick utilized for installed reserve capacity, not continuous generation, and New Brunswick Public Utilities Board regulated transmission lines and interconnections which allow direct and indirect access to multiple electricity markets (Northern Maine ISA, New Brunswick ISO and ISO-NE).

(ii)

AES

In connection with the acquisition of the Tinker Facility, on February 4, 2010, APCo acquired an energy marketing company which markets the energy generated from the Tinker Facility. AES is managing this business and it is anticipated that the majority of the energy sold by AES will be supplied through generation from the Tinker Assets, based on historical long term average levels of hydroelectric energy generation of these facilities. AES primarily involves standard offer contracts for the supply of energy to commercial and industrial customers in northern Maine, as well as energy purchase obligations with the ISO-NE required to supplement self-generated energy.

AES’ business consists of a series of short-term energy supply agreements. These include energy sales to a town in New Brunswick, standard offer service contracts with three local electric utilities in northern Maine, and a series of direct energy contracts with commercial buyers also in northern Maine.

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(iii)

EFW

A capital upgrade at the EFW Facility was completed in July 2010 and has resulted in higher throughput and lower operating costs per tonne at the Facility in 2011 as compared to periods prior to the upgrade.

Liberty Utilities

(i)

California Utility

On April 23, 2009, APUC announced plans to co-acquire an electrical generation and regulated distribution utility (the “California Utility”) in partnership with Emera, pursuant to the asset purchase agreement by and between Sierra Pacific Power Company d/b/a NV Energy and Calpeco dated April 22, 2009 (the “Purchase Agreement”).

On January 1, 2011, APUC, in partnership with Emera, completed the transaction and acquired the assets comprising the California Utility for a gross purchase price of U.S. $136.1 million, subject to certain working capital and other closing adjustments. Liberty Utilities owns 50.001% and Emera owns 49.999% of California Pacific Utility Ventures LLC, which owns 100% of the purchaser of the California Utility assets, Calpeco.

For a more detailed discussion of this acquisition, see “General Development of the Business—Significant Acquisitions – 2011 – Liberty Utilities – California Utility Acquisition”.

(ii)

New Hampshire Utility

On December 9, 2010, APUC announced that Liberty Energy had entered into agreements to acquire all issued and outstanding shares of Granite State, a regulated electric distribution utility, and EnergyNorth, a regulated natural gas distribution utility from National Grid, as outlined in the share purchase agreements by and between National Grid and Liberty Energy entered into on December 8, 2010 and amended and restated on January 11, 2011 (the “Purchase Agreements”).

For a more detailed discussion of this acquisition, see “General Development of the Business—Significant Acquisitions – 2011: New Hampshire Utility Acquisition”.

(iii)

Liberty Utilities (South) – Rate Cases

Liberty Utilities (South) had ongoing rate cases at a number of its utilities which were processed throughout 2010. See “Description of the business – Production Method, Principal Markets, Distribution Methods and Material Facilities – Utilities: Water and Wastewater – Rate Cases—General” for further discussion of the status of these rate cases. During the year ended December 31, 2010, Liberty Utilities (South) completed rate case proceedings at nine utilities in Arizona and Texas which on an annualized basis were expected to contribute an additional U.S. $10.2 million in revenue in the Liberty Utilities (South) region. As these rate cases were settled at various times throughout the year ended December 31, 2010, approximately U.S. $2.3 million of the overall annualized revenue increase from rate cases completed in Arizona and Texas was achieved in the year. One additional rate case requesting U.S. $1.1 million in annual revenue requirement was concluded in the first quarter of 2011.

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(iv)

Liberty Utilities (West) – Senior Debt Financing

The acquisition of the California Utility was funded in part with the proceeds of a U.S. $70 million senior unsecured private debt placement at the utility entered into on December 29, 2010. The private placement is a senior unsecured private placement with U.S. institutional investors, and is an obligation solely of the California Utility. The notes are fixed rate and split into two tranches, U.S. $45 million of ten year 5.19% notes and U.S. $25 million of 5.59% fifteen year notes.

(v)

Liberty Utilities (South) – Senior Debt Financing

On December 22, 2010, Liberty Water completed a private placement financing of senior unsecured 5.6% notes for gross proceeds of approximately U.S. $50 million. The private placement is a senior unsecured private placement with U.S. institutional investors, and is an obligation solely of Liberty Water. The notes have a 10 year term bear interest until June 2016 when annual principal repayments of U.S. $5.0 million annually commence. The funds were used to reduce outstanding indebtedness under APCo’s senior credit facility.

(c)

Fiscal 2011

Corporate

(i)

Strengthened Liquidity—Issuance of $95.3 million of Common Shares

On October 27, 2011, APUC completed a public offering (the “Offering”) of 15,100,000 common shares at a price of $5.65 per share, for gross proceeds of approximately $85.3 million. On November 14, 2011, the underwriters exercised a portion of the over-allotment option granted with the Offering and an additional 1,769,000 common shares were issued on the same terms and conditions of the Offering. As a result, APUC issued an aggregate of 16,869,000 common shares under the Offering for the total gross proceeds of approximately $95.3 million.

The net proceeds of the Offering will be used to fund a portion of the investment related to previously announced growth initiatives for both Liberty Utilities and APCo, to partially repay existing indebtedness and for other general corporate purposes.

(ii)

Strengthened Balance Sheet—Conversion of Convertible Debentures to Equity

Effective May 16, 2011 (“Redemption Date”), APUC redeemed $2.1 million, all of the remaining issued and outstanding principal amount, of Series 1A 7.5% convertible unsecured subordinated debentures due November 30, 2014 (the “Series 1A Debentures”) and issued 430,666 Common Shares of APUC upon the redemption. Between January 1, 2011 and the Redemption Date, $60.339 million principal amount of Series 1A Debentures were converted by debentureholders into 14,788,976 shares of APUC.

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(iii)

Strategic Investment Agreement with Emera

On April 29, 2011, APUC entered into a strategic investment agreement (the “Strategic Agreement”) with Emera which establishes how APUC and Emera will work together to pursue specific strategic investments of mutual benefit. The Strategic Agreement builds on the strategic partnership effectively established between the two companies in April 2009.

The Strategic Agreement outlines “areas of pursuit” for each of APUC and Emera. For APUC, these include investment opportunities relating to unregulated renewable generation, small electric utilities and gas distribution utilities. For Emera, these include investment opportunities related to regulated renewable projects within its service territories and large electric utilities. These “areas of pursuit” are intended to represent investment areas in which there is potential overlap between Algonquin and Emera and are not exhaustive of either company’s business focus and do not limit in any way the activities which either APUC or Emera can undertake. Each of APUC or Emera are free to undertake independently investments within their own “area of pursuit” and outside the other party’s “areas of pursuit”. Under the Strategic Agreement, to the extent either APUC or Emera encounter opportunities which fall within the other’s “areas of pursuit”, they are committed to work with the other party in the development of such investment opportunities.

As an element of the Strategic Agreement, Emera’s allowed common equity interest in APUC will be increased from 15% to 25%. The Strategic Agreement was approved by shareholders at the annual and special general meeting held on June 21, 2011.

APCo—Power Generation

(i)

AES Standard Offer Contract

In 2011, AES entered into a three year contract with Maine Public Service Company (“MPS”), a regulated electric transmission and distribution utility serving approximately 36,000 electricity customer accounts in Northern Maine starting March 1, 2011 to provide standard offer service to multiple commercial and industrial customers in Northern Maine. The anticipated customer load associated with the standard offer service is approximately 135,000 MW-hrs.

(ii)

Windsor Locks Repowering

The Windsor Locks facility is a 56 MW natural gas powered electrical and steam energy generating station located in Windsor Locks, Connecticut. This facility delivers 100% of its steam capacity and a portion of its electrical generating capacity to Ahlstrom pursuant to an energy services agreement (“ESA”).

APCo has entered into an agreement to extend the ESA with Ahlstrom from 2017 to 2027. As a result, APCo is in the process of acquiring a new combustion gas turbine which is more appropriately sized to meet the electrical and steam requirements of the steam host. The new cogeneration equipment is in construction with commercial operation expected in July 2012. The total expected capital cost for this project is estimated at approximately U.S. $25 million. APCo believes it is eligible to receive a one-time non-recurring grant from the State of Connecticut equivalent to U.S. $450/KW to a maximum of U.S. $6.6 million which would offset the cost of such re-powering. APCo also believes that this project would qualify for a combined heat and power investment tax credit (“ITC”) sponsored by the U.S. Federal Government. The benefit of the ITC grant is approximately U.S. $1 million in addition to the Connecticut DPUC grant would offset the cost of such re-powering.

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For a more detailed discussion of this, see “Description of the business – Production Method, Principal Markets, Distribution Methods and Material Facilities – Power Generation: Thermal— Cogeneration – Material Facilities – Windsor Locks Facility”.

(iii)

APCo Senior Unsecured Debentures

On July 25, 2011, APCo issued $135 million in senior unsecured debentures (the “Senior Unsecured Debentures”) by way of private placement. The net proceeds from the Senior Unsecured Debentures were used to repay the outstanding senior project debt financing related to the St. Leon facility (the “AirSource Senior Debt”) and to reduce amounts outstanding under APCo’s senior revolving credit facility. The Senior Unsecured Debentures mature on July 25, 2018, and bear interest at a rate of 5.50% per annum, calculated semi-annually payable on January 25 and July 25 each year, commencing on January 25, 2012.

(iv)

APCo Facility Renewal

On January 14, 2011, APCo received commitments from a syndicate of Canadian banks for a new $142 million credit facility with a three year term (the “APCo Facility”). The APCo Facility matures on February 14, 2014. APCo reduced the amount of the APCo Facility to $120 million following the completion of the Senior Unsecured Debenture private placement by APCo in July 2011.

As at March 30, 2012, APCo had used the APCo Facility to post (i) a letter of credit in the approximate amount of U.S. $19.5 million in respect of the Sanger Facility; (ii) a $1.0 million letter of credit in respect of the Dickson Dam Facility; (iii) letters of credit for the EFW Facility totalling $5.4 million; (iv) letters of credit pursuant to the BCI Facility totalling $2.4 million; (v) letters of credit in connection with the St. Leon Facility totalling $1.8 million; (vi) letters of credit in connection with the Long Sault Rapids Facility totalling $1.2 million; (vii) letters of credit in connection with the St. Leon II Wind Project totalling $3.4 million; (viii) letters of credit in connection with the Cornwall Solar Project totalling $0.5 million; (ix) letters of credit in connection with the various wind development projects totalling $6.9 million; and (viii) various other letters of credit required by APCo entities totalling $0.3 million.

Liberty Utilities

(i)

California Utility

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bearing promissory notes, one in the amount of $22,608,800 and one in the amount of $16,147,120. The proceeds of this subscription receipt transaction will be used to fund the acquisition by Liberty Utilities of Emera US Holdings Inc.’s interest in the California Utility. 4,790,000 subscription receipts will convert into APUC shares on a one-for-one basis following regulatory approval of the transfer of 100% of the California Utility to Liberty Utilities (expected in early 2012), at which time the $22,608,800 promissory note delivered by Emera to APUC to satisfy the subscription price of the first tranche of subscription receipts become due and payable. The remaining 3,421,000 subscription receipts will convert into APUC shares on a one-for-one basis following completion of the California Utility’s first rate case, expected to be completed in early 2013, at which time the $16,147,120 promissory note delivered by Emera to APUC to satisfy the subscription price of the second tranche of subscription receipts become due and payable. In the event of termination of the Subscription Agreement (Calpeco), the promissory notes will be returned to Emera for cancellation, the subscription receipts will be returned to APUC for cancellation, and the parties will have no further obligations under the Subscription Agreement (Calpeco).

2.3

Recent Developments—2012

Corporate

(i)

Strengthened Balance Sheet—Conversion of Convertible Debentures to Equity

Effective February 24, 2012 (“Series 2A Redemption Date”), APUC redeemed $57.0 million, representing the remaining issued and outstanding principal amount, of 6.35% convertible unsecured subordinated debentures due November 30, 2016 (the “Series 2A Debentures”) at a price of $1,000 per debenture by issuing and delivering an aggregate of 9,836,520 APUC shares. Between January 1, 2012 and the Series 2A Redemption Date, $2.9 million principal amount of Series 2A Debentures were converted by debentureholders into 485,998 shares of APUC.

(ii)

Business Associations with APMI and Senior Executives.

There have been a number of business relationships between the Senior Executives (being Ian Robertson and Chris Jarratt), APMI and related affiliates (collectively the “Parties”) and APUC. These relationships include joint ownership of certain generating facility assets, business relationships between the parties and payment of fees associated with previous transactions. In 2011, the Board conducted a process to review all of the remaining business associations with the Parties in order to reduce, streamline and simplify these relationships. The Board formed a special committee and engaged independent consultants to assist with this process.

The co-owned assets and remaining business associations as at December 31, 2011 are listed below. Subsequent to December 31, 2011, APUC and the Parties reached an agreement to resolve a number of the business associations and relationships (the “Agreement”). A more detailed description of the Agreement has been set out below in Settlement of Other Business Associations.

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Rattlebrook hydroelectric generating facility

Rattlebrook is a 4 MW hydroelectric generating station owned 45% by APUC and 27.5% by Senior Executives and the remaining percentage by third parties. This relationship was addressed pursuant to the Agreement. See Settlement of Other Business Associations below for more details.

St. Leon wind power generating facility

St. Leon is a 104 MW wind power generating facility which has issued Class B units to external parties and Senior Executives. APUC and the Class B unit holders have simplified the relationship by amalgamating the previous partnership agreement and two amending agreements into an amended and restated agreement. In addition, APUC and the Class B holders have executed an agreement which outlines the relationship of the parties in relation to the St. Leon II expansion of the St Leon facility (“Expansion Agreement”). The terms of the Expansion Agreement allow APUC to expand the St Leon project on a “no-net-harm-basis” to the Class B holders and provide APUC with the full economic benefit of such expansion.

Brampton Cogeneration Inc.

BCI is an energy supply facility which sells steam produced from APCo’s EFW facility. APMI maintains a carried interest equal to 50% of the annual returns on the project greater than 15%. No amounts have ever been paid under this carried interest. In 2008, APMI earned a construction supervision fee of $100 in relation to the development of this project. In 2008, APUC accrued $100 as an estimate of the final fee owed to APMI. This relationship and corresponding liability was addressed pursuant to the Agreement.

Long Sault Rapids hydroelectric generating facility

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

Chartered aircraft

APUC utilizes chartered aircraft owned by an affiliate of APMI. APUC entered into an agreement and remitted $1.3 million to the affiliate as an advance against expense reimbursements. At December 31, 2011, $279 of the advance remained. The Board has undertaken an independent review of the relationship and believes that continuing the original arrangement is beneficial to the company. The current arrangement is expected to end in approximately 2016 when the advance will be fully utilized.

Office lease

APUC has leased its head office facilities on a triple net basis from an entity partially owned by Senior Executives. The original lease was due to expire in December 31, 2012. Effective April 1, 2011, a subsidiary of APUC leased its head office facilities from a third party in a new stand alone building immediately adjacent to APUC’s head office for a term of 5 years ending December 31, 2015 with an additional 5 year renewal option. APUC has amended its lease at

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its existing premises to be co-terminus with its subsidiary’s new lease. The majority of terms in the amended lease are identical. Based on a review of the real estate leasing market in the fall of 2010, APUC believes the amended lease is on terms equivalent to fair market value for prime office space of similar size and quality.

Operations services

Staff managed by APUC have historically operated an additional three hydroelectric generating facilities where Senior Executives hold an interest. Effective January 1, 2011, management of these facilities is now being undertaken by an affiliate of APMI. APUC and the APMI affiliate had agreed to provide some transition services to each other until December 31, 2011. Costs for providing such transition services are intended to be on a cost recovery basis with no mark-up for profit. APUC agreed to provide supervisory management on a cost recovery basis for one of the facilities until December 31, 2012 to provide sufficient time for APMI to make alternative arrangements to manage the facility.

Sanger construction management

As part of the project to re-power the Sanger facility, APUC entered into an agreement with APMI to undertake certain construction management services on the project for a performance based contingency fee. In 2008, APUC accrued U.S. $0.6 million as an estimate of the final fee owed to APMI. This liability was settled pursuant to the Agreement.

Clean Power Income Fund

During 2007, Algonquin allowed its offer to acquire Clean Power Income Fund to expire and earned a termination fee of $1.8 million. As part of its role in the process, APUC has agreed to pay APMI a fee of $0.1 million. As of December 31, 2011 this amount is accrued and included in accounts payable on the consolidated balance sheet. This liability was settled pursuant to the Agreement.

Red Lily I

APMI was an early developer of the 26 MW Red Lily I wind power generation facility. As such it is entitled to a royalty fee based on a percentage of operating revenue and a development fee from Red Lily I. APUC has acquired APMI’s interest in these royalties for an amount of $0.6 million. APMI is also entitled to a development fee of up to $0.4 million following commercial operation of the project and has agreed to permit the Board to determine whether it will retain this fee following commercial operation of the facility. This liability was settled pursuant to the Agreement.

Trafalgar

APCo owns debt on seven hydroelectric facilities owned by Trafalgar Power Inc. and an affiliate (“Trafalgar”). In 1997, an affiliate of APMI moved to foreclose on the assets, and subsequently Trafalgar went into bankruptcy. Trafalgar was previously awarded a U.S. $10.0 million claim in respect of a lawsuit related to faulty engineering in the design of these facilities, and these funds are held in the bankruptcy estate. As previously disclosed, Trafalgar, APUC and an affiliate of APMI are involved in litigation over, among other things, a civil proceeding on the foreclosure on the assets and in bankruptcy proceedings. APMI funded the initial $2 million in legal fees. An

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agreement was reached in 2004 between APMI and APUC whereby APUC would reimburse APMI 50% of the legal costs to date in an amount of approximately $1 million, and going forward APUC would fund the legal fees, third party costs and other liabilities with the proceeds from the lawsuits being shared after reimbursement of legal fees, third party costs and other liabilities. The Board has determined that any proceeds from the lawsuit will be shared between APMI and APUC proportionally to the quantum of such costs funded by each party. The Second Circuit Court of Appeals dismissed all the claims against APCo in the civil proceedings and remanded one issue to the District Court. The bankruptcy proceedings are continuing.

Settlement of Other Business Associations.

Subsequent to December 31, 2011, APUC and the Parties reached an Agreement to resolve a number of the historic joint business associations between APUC and the Parties. The transaction is subject to finalization of definitive agreements which are expected to be completed in the second quarter of 2012.

Under this term sheet, it is proposed that APUC will exchange its 45% interest in the 4MW Rattlebrook hydroelectric facility (including a $0.5 million positive working capital adjustment) in return for the Parties’ residual partnership interest in the Long Sault Rapids hydroelectric facility and the equity interest in the Brampton cogeneration plant. The agreement also terminates outstanding fees potentially owing to APMI in respect of the following: the historic transactions including Sanger repowering project, the offer to acquire Clean Power Income Fund and the development of the Red Lily I wind project.

The special committee of the Board retained the services of an independent advisor to review the historic financial performance of the Rattlebrook and Long Sault Rapids facilities, provide a valuation of these assets and to provide advice to APUC in respect thereof.

APCo—Power Generation

(i)

Acquisition of U.S. Wind Farms

On March 9, 2012, APCo entered into an agreement to acquire a 51% majority interest in a 480 MW portfolio of four wind power projects in the United States (the “Projects”) from Gamesa Corporación Tecnológica, S.A. (“Gamesa”) for total consideration of approximately U.S. $888 million.

APCo will contribute U.S. $269 million to partially fund the acquisition of the Projects; tax assisted equity investors will contribute U.S. $360 million. APCo intends to finance its investment with approximately 45% debt and 55% equity. The portfolio will be acquired in two stages; closing of two existing wind farms is expected to occur promptly following receipt of regulatory approval and the acquisition of the remaining two wind farms following their respective commissioning near the end of 2012.

The Projects consist of four facilities, Minonk (200MW), Senate (150MW), Pocahontas Prairie (80MW) and Sandy Ridge (50MW) located in the states of Illinois, Texas, Iowa and Pennsylvania, respectively. Pocahontas Prairie and Sandy Ridge have recently reached their commercial operation dates (“COD”) in February 2012, and Senate and Minonk are in construction with COD anticipated in Q4 2012. Total annual energy production from the four facilities is expected to be 1,644 GW-hrs per year. The Projects are comprised of 240 Gamesa

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G9X-2.0 MW wind turbines. The Projects each have entered into a 20 year contract with Gamesa to provide operations, warranty and maintenance services for the wind turbines and balance of plant facilities.

The Projects have long term, fixed price power sales contracts (the “Power Sales Contracts”) with a weighted average life of 11.8 years (Minonk and Sandy Ridge 10 years, Senate 15 years). Approximately 73% of energy revenues would be earned under the Power Sales Contracts. All energy produced in excess of that sold under the Power Sales Contracts, together with ancillary services including capacity and renewable energy credits, will be sold into the energy markets in which the facilities are located.

(ii)

St. Leon Facility Expansion

On July 18, 2011, APCo entered into a 25-year PPA with Manitoba Hydro in respect of the St. Leon II Facility located in the Province of Manitoba.

Construction of this project commenced on August 30, 2011. The final turbine was erected in February 2012 and the project is generating energy on all units as of March 1, 2012. The total capital cost of the project is expected to be $29.5 million. The project is expected to achieve commercial operation early in the second quarter of 2012 with revenues in the first full year of operating following commissioning expected to be $3.8 million.

(iii)

New Projects under Development

As of March 7, 2012, APCo had been awarded or acquired interests in 7 major power development projects that significantly expands the company’s electrical generation capacity by 350 MW and once completed will increase the company’s annual generation production by over 1,200 GWhrs. Each project has a PPA with a Canadian provincial utility and has a contract length of 20 years or longer.

The following summarizes a number of projects under development and for which PPA’s have been awarded since December 2010.


Project Name (Location)	Location	Size (MW)	Estimated Capital Cost	Commercial Operation	PPA Term	Production GWhr
Chaplin Wind	Saskatchewan	177	$355.0	2016	25	720.0
Amherst Island	Ontario	75	$230.0	2014	25	247.0
Morse Wind ¹	Saskatchewan	25	$70.0	2014	20	93.0
St. Damase	Quebec	24	$70.0	2013	20	86.0
Val Eo	Quebec	24	$70.0	2015	20	66.0
St. Leon II	Manitoba	17	$30.0	2012	25	58.0
Cornwall Solar	Ontario	10	$45.0	2013	20	13.4

Total		352	$870.0			1,283.4

¹	The Morse Wind Project is comprised of three contiguous projects with 25 MW in aggregate installed generating capacity. The two 10 MW PPA’s were awarded in May 2010 and the 5 MW PPA was awarded in June 2011.

For a more detailed discussion of these projects, see “Description of the business – Production Method, Principal Markets, Distribution Methods and Material Facilities – Power Generation: Development – Current Development Projects”.

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Liberty Utilities

New Hampshire Utility Acquisition update

On December 9, 2010 Liberty Utilities entered into agreements to acquire all issued and outstanding shares of Granite State and EnergyNorth. For a more detailed discussion of this acquisition, see “General Development of the Business – Significant Acquisitions – 2011 – New Hampshire Utility Acquisition”.

The closing of the transaction is subject to approval by the New Hampshire Public Utilities Commission (“NHPUC”). Liberty Utilities is currently proceeding through the regulatory approval process. A series of technical sessions with the NHPUC have been held to review the merits of the transaction, identify key transitional issues and resolve issues raised by commission staff, the consumer advocate and other interveners. Liberty Utilities and National Grid are now working with the NHPUC Staff and Consumer Advocate to prepare a settlement recommendation to present to the Commissioners of the NHPUC for consideration and ultimate approval. The current regulatory hearing schedule should allow for a public hearing early in the second quarter of 2012, with a commission decision expected shortly thereafter. This would likely to result in closing occurring towards the end of the second quarter of 2012.

ii)

Midwest Utility Acquisition update

On May 13, 2011, Liberty Utilities entered into an agreement with Atmos to acquire their regulated natural gas distribution utility assets (the “Midwest Gas Utilities”) located in Missouri, Iowa, and Illinois. Total purchase price for the Midwest Gas Utilities is approximately U.S. $124 million, subject to certain working capital and other closing adjustments. Liberty Utilities expects to acquire assets for rate making purposes of approximately U.S. $112 million. For a more detailed discussion of this acquisition, see “General Development of the Business – Significant Acquisitions – 2011 – Midwest Gas Utilities Acquisition”.

The closing of the transaction is subject to approval by the Missouri Public Service Commission (“MPSC”), Iowa Utilities Board (“IUB”), and Illinois Commerce Commission (“ICC”). Liberty Utilities has received approval from the IUB and has entered a unanimous stipulation with the MPSC. Liberty Utilities is currently proceeding through the regulatory approval process with the ICC which requires the Company, Atmos and the ICC staff to review the merits of the transaction. A hearing on a limited set of issues was held in Illinois in January 2012, and a proposed ICC decision is expected in the second quarter of 2012. Management expects closing to occur towards the end of the second quarter of 2012.

iii)

Liberty Utilities Credit Facility

On January 19, 2012, Liberty Utilities entered into an agreement for a U.S. $80 million senior unsecured revolving credit facility (the “Liberty Facility”) with a three year term. Initially, U.S. $25 million will be available immediately to support the operations of Liberty Utilities and its current subsidiaries. The additional U.S. $55 million will be automatically available to Liberty Utilities to support operations and working capital requirements of all committed regulated utility acquisitions following the closing of the previously announced acquisition of Granite State and EnergyNorth. The Liberty Facility can be increased to accommodate future working capital needs or other requirements.

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As at March 25, 2012, Liberty Utilities had used the Liberty Facility to post (i) four letters of credit in the approximate amount of U.S. $1.2 million in respect of Liberty Utilities (South).

2.4

Significant Acquisitions and Investments—2011

APCo—Power Generation

Cornwall Solar

APCo entered into a share purchase agreement with EffiSolar Energy Corporation (“EffiSolar”) to acquire all of the issued and outstanding shares of Cornwall Solar Inc. based upon the achievement of specific milestones. On December 30, 2011 OPA approval was received and the transaction closed on January 4, 2012. Cornwall Solar owns the rights to develop a 10 MWac solar project located near Cornwall, Ontario. In addition to the Cornwall project, APCo has acquired an option to acquire 10 additional Ontario based solar projects. Projects in the Feed-in-Tariff (“FIT”) pipeline have submitted FIT applications for an additional 100MWac.

For a more detailed discussion of this acquisition, see “Description of the business – Production Method, Principal Markets, Distribution Methods and Material Facilities – Power Generation: Development—Current Development Projects”.

ii)

Red Lily Wind Project

On February 28, 2011 the 26.4 MW wind generation facility in southeastern Saskatchewan (“Red Lily I”) commenced commercial operation under the PPA. APUC’s investment in Red Lily I has been initially structured in the form of senior and subordinated debt investment of approximately $19.6 million with returns to APUC from the project coming in the form of interest payments and other fees in 2011.

Project construction costs at Red Lily I were approximately $71.2 million. APUC and APCo earned $1.6 million in interest income and $1.9 million in other payments and fees in 2011, representing approximately 75% of the expected net cash flows from Red Lily I. APUC has the option to formally exchange its debt investment and fee interest in the project for a 75% equity interest in Red Lily I, exercisable in February 2016.

Liberty Utilities

California Utility Acquisition

On April 23, 2009, APUC agreed to co-acquire an electrical generation and regulated distribution utility in partnership with Emera. APUC and Emera would own 50.001% and 49.999%, respectively, of CPUV, which owns 100% of Calpeco. Calpeco was formed to acquire the California-based electricity distribution and related generation assets of NV Energy for the purchase price of approximately US $132 million, subject to certain working capital and other closing adjustments, as outlined in the Purchase Agreement.

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In October 2009, an application was filed with the CPUC requesting approval of the transaction in which NV Energy had agreed to sell its California electric distribution and generation assets to Calpeco. The transaction was subject to State and Federal regulatory approval. On January 1, 2011, following receipt of all U.S. State and Federal regulatory approvals, Calpeco acquired the assets comprising the California Utility. The California Utility provides electric distribution service to approximately 47,000 customers in the Lake Tahoe region.

As an element of the California Utility partnership, pursuant to a subscription and unitholder agreement dated April 22, 2009 (the “Subscription Agreement”), Emera agreed to a conditional treasury subscription of approximately 8.5 million Trust Units of APCo at a price of $3.25 per unit. Subsequent to the completion of the Unit Exchange, the Subscription Agreement was amended to reflect a subscription of Common Shares rather than Trust Units of Algonquin. Upon closing, Emera exchanged these subscription receipts into 8.523 million Common Shares at a purchase price of $3.25 per Common Share. The proceeds of the subscription receipts were utilized to fund Liberty Utilities (West)’s ownership share of the cost of acquisition of the California Utility.

The acquisition was also funded in part with the proceeds of a U.S. $70 million senior unsecured private debt placement at the utility entered into on December 29, 2010. The private placement is a senior unsecured private placement with U.S. institutional investors, and is solely an obligation of the California Utility. The notes are fixed rate and split into two tranches, U.S. $45 million of ten year 5.19% notes and U.S. $25 million of 5.59% fifteen year notes.

ii)

New Hampshire Utility Acquisition

On December 9, 2010, APUC announced that Liberty Energy had entered into agreements to acquire all issued and outstanding shares of Granite State, a regulated electric distribution utility, and EnergyNorth, a regulated natural gas distribution utility from National Grid for total consideration of U.S. $285.0 million, subject to certain working capital and other closing adjustments, as outlined in the NH Purchase Agreements.

Granite State provides electric service to over 43,000 customers in 21 communities in New Hampshire. EnergyNorth provides natural gas services to over 83,000 customers in five counties and 30 communities in New Hampshire. Granite State and EnergyNorth are anticipated to have regulatory assets at closing of approximately U.S. $72.0 million and U.S. $178.8 million, respectively.

Closings of the transactions are subject to certain conditions including state and federal regulatory approval, and are expected to occur in 2012. Financing of the acquisitions is expected to occur simultaneously with the closing of the transactions. Liberty Energy is targeting a capital structure with not more than 50% debt to total capital, consistent with investment grade utilities.

As an element of the EnergyNorth and Granite State acquisitions and pursuant to a subscription agreement dated March 25, 2011 (the “Subscription Agreement (National Grid)”), Emera subscribed for 12,000,000 subscription receipts of APUC at a price of $5.00 per subscription receipts. Payment for the subscription receipts was satisfied by delivery by Emera of a non-interest bearing promissory note in the amount of $60,000,000. Upon satisfaction of the conditions precedent to the closing of the National Grid transactions (other than payment of the purchase price), including the receipt of all necessary regulatory approvals, the promissory note

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will become due and payable and the rights evidenced by the subscription receipts will be deemed to have been satisfied by the delivery of Common Shares from APUC on a one-for-one basis, subject to customary anti-dilution adjustments. Delivery of Common Shares of APUC upon conversion of the subscription receipts is conditional on and is planned to occur simultaneously with the closing of the acquisition of Granite State and EnergyNorth. In the event of termination of the Subscription Agreement (National Grid), the promissory note will be returned to Emera for cancellation, the subscription receipts will be returned to APUC for cancellation, and the parties will have no further obligations under the Subscription Agreement (National Grid).

iii)

Midwest Gas Utility Acquisition

On May 13, 2011, Liberty Utilities entered into an agreement with Atmos to acquire their regulated natural gas distribution utility assets (the “Midwest Gas Utilities”) located in Missouri, Iowa, and Illinois. Total purchase price for the Midwest Gas Utilities is approximately U.S. $124 million, subject to certain working capital and other closing adjustments, as outlined in the share purchase agreements by and between Atmos and Liberty Midstates entered into on May 12, 2011 (the “Midwest Purchase Agreements”).

Liberty Utilities expects to acquire assets for rate making purposes of approximately U.S. $112 million.

3.	DESCRIPTION OF THE BUSINESS

3.1

General Description of the Regulatory Regimes in which the Business Operates.

(a)

Power Generation Regulatory Regimes

(i)

Canada

In Canada, the provinces have legislative authority over the supply of energy. The majority of the electrical supply within the Canadian provinces is provided by large Crown corporations such as Ontario Power Generation Inc. and Hydro-Québec or smaller, investor-owned utilities. These large utilities have been primarily responsible for the generation, transmission and distribution of electricity.

“Green Power” is considered electricity generated from renewable energy sources that do not contribute to greenhouse gas emissions. Green Power includes technologies such as small hydroelectric (generally defined as facilities of less than 20 MW in capacity), bioenergy, landfill gas, wind and photovoltaic technologies. Since 1997, both the federal and provincial governments in Canada have provided various incentives to stimulate the production of Green Power in Canada. The incentives have varied from direct subsidies, to tax credits to higher than market rates for electricity generated from renewable energy sources.

In 2007, the Canadian Federal government established a new Renewable Power Production Incentive program (“RPPI”) called “ecoEnergy for Renewable Power” that was created to stimulate up to 14.3 terawatt hours of other new renewable energy. The RPPI provides for an incentive of $10 per MW-Hr of production for the first ten years of operations for eligible projects commissioned after April 1, 2007 and before March 31, 2011. Eligible technologies include waterpower, advanced, innovative and highly efficient biomass, combustion technologies using

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biogas and other renewable technologies. Although no new contribution agreements will be signed after March 31, 2011, signed agreements will continue to receive payments as outlined in contribution agreements up to March 31, 2021

(ii)

United States

The power generation industry in the United States is regulated by the United States Federal Energy Regulatory Commission (“FERC”) under the U.S. Federal Power Act (“FPA”) and Public Utilities Regulatory Policies Act (“PURPA”).

Rate Regulation

While Qualifying Facilities (“QFs”), which comprise the majority of APCo’s US facilities, were previously exempt from rate regulation under the FPA, due to changes in PURPA, QFs are now subject to rate regulation under Section 205 and 206 of the FPA, subject to certain exceptions. Sales of energy or capacity made by QFs 20 MW or smaller, or made pursuant to a contract executed on or before March 4, 2006, or made pursuant to a state regulatory authority’s implementation of PURPA are exempt from regulation under sections 205 and 206 of the FPA. All relevant APCo facilities had PPAs in place predating March 4, 2006, and as such have not been impacted.

The APCo facilities that are not QFs have market-based rate authority under the FPA and thus are subject to less regulation than cost of service based entities.

PURPA Regulatory Structure

The purpose of PURPA is to encourage the development of small independent power production. To accomplish this, FERC requires electric utilities to purchase energy and capacity from QFs at the utility’s avoided cost. “Avoided Costs” means costs a utility does not incur to add new generating capacity to the system by purchasing electricity from an independent or parallel generator.

As a result of the Energy Policy Act of 2005, electric utilities are no longer required to purchase energy or capacity from a QF if the utility can prove the QF has nondiscriminatory access to:

(1)(i) Independently administered, auction-based day ahead and real time wholesale markets for the sale of electric energy; and

(ii) Wholesale markets for long-term sales of capacity and electric energy; or

(2)(i) Transmission and interconnection services that are provided by a Commission-approved regional transmission entity and administered pursuant to an open access transmission tariff that affords nondiscriminatory treatment to all customers; and

(ii) Competitive wholesale markets that provide a meaningful opportunity to sell capacity, including long-term and short-term sales, and electric energy, including long-term, short-term and real-time sales, to buyers other than the utility to which the

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qualifying facility is interconnected. In determining whether a meaningful opportunity to sell exists, the Commission shall consider, among other factors, evidence of transactions within the relevant market; or

(3) Wholesale markets for the sale of capacity and electric energy that are, at a minimum, of comparable competitive quality as markets described in paragraphs (a)(1) and (a)(2) of this section.

There is a rebuttable presumption that QFs have non-discriminatory access to the market if they are eligible for service under a Commission-approved open access transmission tariff (“OATT”) and are subject to Commission-approved interconnection rules. There is, however, also a rebuttable presumption that QFs with capacity at or below 20 MWs do not have non-discriminatory access to the market. Because all the APCo QFs have 20 MWs or less of capacity or are on a long term PPA, they qualify for this rebuttable presumption.

(b)

Water Utility Services Regulatory Regimes

(i)

United States Water Services Industry

Investor-owned utilities are subject to regulation by the public utility commissions of the states in which they operate. The respective public utility commissions typically have jurisdiction over rates, service, accounting procedures, issuance of securities, acquisitions and other matters. The utilities generally operate under cost-of-service regulation as administered by these state authorities, using a test year in the establishment of rates for the utility and pursuant to this method the determination of the rate of return on approved rate base and deemed capital structure, together with all reasonable and prudent costs, establishes the revenue requirement upon which each utility’s customer rates are determined. Rates charged by these utilities are determined such that rates are set so as to provide the utilities with sufficient revenues to generate after-tax equity returns of approximately 8% to 12%.

Generally, water and wastewater providers in the United States operate as geographic monopolies within the areas in which they serve. A water or wastewater company is provided a service territory defined by a Certificate of Convenience and Necessity which imposes an exclusive right and duty to serve in the service territory. A Certificate of Convenience and Necessity is typically granted by a State agency, which also serves as an economic and service quality regulator for these water or wastewater service providers. Such agencies are charged with ensuring that water and wastewater services are provided at reasonable rates and quality to the company’s customers. The agency must balance the interests of the rate payers as well as companies and their shareholders. Rates are approved by the agency to provide the water or wastewater company the opportunity, but not the guarantee, to earn a reasonable return on its investment after recovering its prudently incurred operating expenses.

(c)

Electrical Utility Services Regulatory Regimes

(i)

United States Electric Services Industry

Investor-owned electricity utilities are subject to regulation by the public utility commissions of the States in which they operate. The respective public utility commissions typically have jurisdiction over rates, services, accounting procedures, issuance of securities, acquisitions and

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other matters. The utilities generally operate under cost-of-service regulation as administered by these state authorities, using a test year in the establishment of rates for the utility and pursuant to this method the determination of the rate of return on approved rate base and deemed capital structure, together with all reasonable and prudent costs, establishes the revenue requirement upon which each utility’s customer rates are determined. Rates charged by these utilities are determined such that rates are set so as to provide the utilities with sufficient revenues to generate after-tax equity returns of approximately 8% to 12%.

Generally, electricity providers in the United States operate as geographic monopolies within the areas in which they serve. An electricity distribution company is provided a service territory which imposes an exclusive right and duty to serve in the service territory. The approval to serve is typically granted by a State agency, which also serves as an economic and service quality regulator for these electric service providers. Such agencies are charged with ensuring that electric services are provided at reasonable rates and quality to the company’s customers. The agency must balance the interests of the rate payers as well as companies and their shareholders. Rates are approved by the agency to provide the electric services company the opportunity, but not the guarantee, to earn a reasonable return on its investment after recovering its prudently incurred operating expenses.

The electricity industry remains perhaps the most highly regulated in the United States. The industry is regulated under strict standards at multiple levels—federal, state and sometimes local. Under the Federal Power Act, FERC regulates interstate transmission, wholesale sales of electricity, corporate acquisitions and dispositions, securities and debt issuances, debt acquisitions, and reliability. State utility commissions perform a similar role, regulating sales of electricity to end-use customers, as well as financial stability and reliability. This oversight also includes cost-of-service regulation to establish 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 in order to determine the revenue requirement upon which each utility’s customer rates are set. Rates charged by these utilities are determined such that rates are set so as to provide the utilities with sufficient revenues to generate after-tax equity returns of approximately 8% to 12%. This oversight and other rules set by the state utility commissions are intended to ensure reliable service and adequate supplies of electricity together with financial security, transparency in the rate setting process and reasonable prices.

3.2

Production Method, Principal Markets, Distribution Methods and Material Facilities

(a)

Power Generation: Renewable—Hydroelectric

(i)

Production Method

A hydroelectric generating facility consists of a number of components, including a dam, headrace canal or penstock, intake structure, electromechanical equipment consisting of a turbine(s), a generator(s), draft tube and tailrace canal. In addition, there are electrical switchgear and controls equipment which are necessary to interconnect the facility with the receiving electrical grid system.

A dam structure is required to create or increase the natural elevation difference between the upstream reservoir and the downstream tailrace (referred to as “head”), as well as to provide sufficient depth within the reservoir for an intake. Dam structures are also used to create an upstream reservoir which allows water to be stored within a headpond.

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Water flows are conveyed from the upstream reservoir to the generating equipment via a penstock or headrace canal. A penstock is a pipeline capable of operating under pressure, and is normally constructed of steel or other suitable materials. A headrace canal is a channel which conveys water from the reservoir to the intake in a hydraulically efficient manner. The intake structure is a water intake located at the entrance to a penstock or at the end of a headrace canal. The purpose of the intake structure is to collect water from the upstream reservoir. Turbine(s) and generator(s) transform the hydraulic energy into electrical energy.

The water which has flowed through the hydraulic turbine(s) is discharged back to the natural watercourse. A transmission line is often required to interconnect a facility with the grid. The majority of hydroelectric generating facilities are also equipped with remote monitoring equipment, which allows the facility to be monitored and operated from a remote location.

(ii)

Principal Markets and Distribution Methods

The principal markets in which APCo operates in Canada are Alberta, Ontario, New Brunswick and Québec. In the US, the principal markets are Maine, New York State and New Hampshire. The majority of generated hydroelectricity is conveyed from the relevant APCo facility to the purchasers under the terms of long term PPAs. The electricity is generally transferred by transmission line from the generating facility to the delivery point for the purchaser, and it is distributed through the grid to end user customers of the purchaser. A summary of the PPAs for APCo’s Renewable Energy division is set out in Schedule A.

(1)

Alberta

The electrical power industry in Alberta is regulated by the Electric Utilities Act (Alberta)(the “EUA”). The Power Pool of Alberta (the “Power Pool”) was established under the EUA to provide a competitive, real-time spot market for electric energy. The Power Pool is non-discriminatory and open to any generator, marketer, distributor, importer or exporter that satisfies the qualification requirements established under the EUA and the rules and codes of practice of the Power Pool.

The EUA has also established the Alberta Electric System Operator (the “AESO”) to operate and manage the Power Pool in a manner that promotes the fair, efficient and openly competitive exchange of electric energy in Alberta . The AESO is governed by an independent board appointed by the Alberta Minister of Energy.

The AESO spot market, or pool price, is determined by market forces. The AESO accepts offers to sell power and bids to buy power through its Energy Trading System. The AESO then dispatches electricity in accordance with an economic merit order based on the lowest cost offers to supply demand in real time. All energy traded through the Power Pool is financially settled each hour at a single spot market price.

Three categories of sellers are eligible to offer and sell electricity through the Power Pool: marketers, importers and independent power producers. There are also three categories of eligible purchasers who may bid to acquire electricity from the Power Pool: retailers, direct access customers and exporters.

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(2)

Ontario

The Ontario government develops the regulatory framework for wholesale and retail competition through the Ontario Energy Board (the “OEB”). While transitional issues such as pricing and metering continue to be considered by the OEB, full competition in the wholesale and retail electricity market commenced on May 1, 2002.

The Ontario Electricity Financial Corporation (“OEFC”) holds all rights, obligations and liabilities under, and purchases the energy generated by the Ontario facilities in which APCo has an interest pursuant to, the existing contracts. APCo has also received a licence to generate from the OEB as required by the Ontario Energy Board Act, 1998 (Ontario).

(3)

New Brunswick and Northern Maine

In 2003 the New Brunswick government amended the provincial Electricity Act (New Brunswick) (the “Electricity Act”) which resulted in the start of competition in the generation business.

As a result of the Electricity Act, which took effect in October of 2004, New Brunswick Power Corporation (“NB Power”) was divided into separate businesses. The distribution and customer service division of NB Power now functions as a regulated monopoly and serves all the residential and industrial power consumers in the province, with the exception of those in Saint John, Edmundston and Perth-Andover which are served by Saint John Energy, City of Edmundston Electric and the Perth-Andover Electric Light Commission, respectively.

One of the separate entities created by the Electricity Act is the New Brunswick System Operator (“NBSO”), an independent not-for-profit statutory corporation. NBSO is responsible for the adequacy and reliability of the integrated electricity system, and for facilitating the development and operation of the New Brunswick electricity market. These responsibilities take the form of operation of the NBSO-controlled grid and administration of the Open Access Transmission Tariff and the New Brunswick Electricity Market Rules.

The NBSO is the Balancing Authority for New Brunswick, Prince Edward Island, and Northern Maine, and the Transmission Provider for New Brunswick. NBSO provides load following and regulation service to the system in order to supply customer load in the province while maintaining scheduled flows on interconnections within established limits. NBSO is the authority responsible for the operation of the Bulk Power System in New Brunswick, Nova Scotia, Prince Edward Island, and a portion of northeastern Maine.

(4)

Québec

Similar to Ontario, the Québec government develops the regulatory framework for wholesale and retail competition. Since 1991 Hydro-Québec has procured some of its power requirements from private producers on terms and rates negotiated with each producer. The province continues to introduce various programs to stimulate renewable power from hydroelectric and wind powered facilities as well as cogeneration plants fuelled by biomass and natural gas.

In April 2002, the Québec government adopted the Dam Safety Act (Quebec) and corresponding regulations. The Dam Safety Act (Quebec) imposes a series of safety measures governing the construction, alteration and operation of high-capacity dams. It requires dam owners to maintain their facilities in good repair and monitor their hydraulic works. As a result of

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this legislation, APCo’s Renewable Energy division was required to undertake technical assessments of eleven of the twelve hydroelectric facility dams owned or leased by APCo within the Province of Québec.

APCo has spent approximately $1.5 million to date on dam safety evaluations, engineering, permitting and civil works related to the Bill C93 requirements. APCo currently estimates further capital expenditures of approximately $16.9 million related to compliance with the legislation. It is anticipated that these expenditures will be invested over a period of several years approximately as follows:

Total

2012

2013

2014

2015

Estimated future Bill C-93 Capital Expenditures

16,900

1,100

5,300

7,700

2,800

The majority of these capital costs are associated with the Donnacona, St. Alban, Belleterre, and Mont-Laurier facilities.

•

The dam safety evaluation for the Mont Laurier facility was completed in 2008 and APCo’s proposed remediation plan has now been accepted by the Quebec government. APCo has been performing engineering and permitting since 2010 and received the Certificate of Authorization from the Quebec government in November 2011. APCo anticipates completing the on-site remediation work in 2012.

•

In respect of the Donnacona facility, APCo completed the dam safety evaluation in 2007 and has been investigating alternative engineering designs to minimize the cost of the remediation work. APCo is now pursuing a design that may result in a cost savings of 20% of the original estimates. APCo anticipates completing the engineering in 2012 and performing the remedial work in 2013 and 2014.

•

The dam safety study for the St. Alban facility was completed in 2010 followed by a detailed condition assessment in 2011. APCO will review the results of the condition assessment and finalize the remediation plan for this dam in 2012. APCo anticipates engineering and regulatory review to be performed in 2012 and 2013, with remedial work in 2014 to 2015.

•

APCo is presently reviewing options with respect to the Belleterre facility including the removal of several small dams that are not required for power generation. APCo has been corresponding with the Quebec government and other stakeholders about these options since 2007. APCo anticipates completion of any required work on these dams by 2015.

•

The dam remediation work related to Chute Ford will be completed in 2012 while the work related to the St. Raphael and Riviere-du-Loup facilities is anticipated to be completed in 2013. No dam remediation work is required at the Arthurville, Hydraska, and Ste-Brigitte facilities.

•

The dam remediation work related to the Rawdon facility was completed in 2011.

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In addition to the C-93 related dam remediation work, APCo has implemented a dam condition monitoring program at some of the above facilities following recommendations specified in the dam safety reviews.

(iii)

Material Facilities

(1)

Long Sault Rapids Facility

The Long Sault Rapids Facility is an 18 MW hydroelectric generating facility located on the Abitibi River, 19 kilometres north of the Town of Cochrane, in northern Ontario. The Facility was commissioned on April 1, 1998.

The Facility was developed by a joint venture between Algonquin Power (Long Sault) Partnership and N-R Power Partnership. The Facility is owned by the co-owning joint venturers (the “Co-Owners”) as tenants-in-common and not as joint tenants, with the co-owners each having an undivided 50% interest in the facility. The partners in the Algonquin Power (Long Sault) Partnership, Algonquin Power (Long Sault) Corporation Inc. and Energy Acquisition (Long Sault) Ltd., are wholly-owned subsidiaries of Algonquin Power Corporation Inc. (“APC”), a corporation affiliated with APMI. The partners in the N-R Power Partnership are Nicholls Holdings Inc. and Radtke Holdings Inc., companies controlled by two independent businessmen. There are two non-recourse loans outstanding which are secured against the facility and the Co-Owners’ interest therein (see “Hydroelectric – Long Sault Rapids Facility—Credit Agreements” below).

APCo’s interest in the Facility was acquired by way of subscribing to two notes from the original developers. The notes receivable have a face value of approximately $17 million and bear interest at 9%. APCo earns interest income on the notes and is entitled to 100% of any incremental after tax cash flows from the facility up to 2013, 65% of any incremental after tax cash flows from 2014 to 2027 and 58% of any incremental after tax cash flows thereafter. APCo also has the right to acquire 58% of the equity in the facility at the end of the term of the notes in 2038.

The Facility is a “run of the river” facility, which means there is a continuous discharge of water from the facility with no storage and release of water. The powerhouse is an integrated structure, housing four 4,500 kilowatt pit turbine generating units.

PPA

Pursuant to the terms of the PPA, the Co-Owners sell power produced by the Facility exclusively to OEFC. The PPA terminates 50 years from the commercial in-service date, April 1, 1998, and may be renewed for a further term upon request by either party on terms and conditions to be mutually agreed. The rates are escalated annually based on an index figure tied to the greater of OEFC’s Total Market Cost index (a minimum of 1% to a maximum of 8%).

The Co-Owners receive a monthly capacity payment when the Facility delivers an average of at least 1,800 kilowatts of power delivered to the delivery point in each fifteen minute interval to OEFC during at least 85% or more of the On-peak period fifteen minute intervals for that month. The “On-peak” period is between 7:00 a.m. and 11:00 p.m., local time, Monday to Friday, inclusive, but excluding public holidays, and “Off-peak” is the other remaining hours. Monthly energy in excess of 115% of target generation is subject to an additional payment.

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ii)

Waterpower Lease

The waterpower lease with the Province of Ontario in respect of the dam site expires in 2048. The lease provides for an annual land rental and an annual water rental charge. The annual water rental charge commenced in January 2008.

iii)

Co-Owners Agreement and Management Agreement

The Co-Owners have entered into an agreement concerning, among other things, their holding of undivided interests in the facility. Upon the occurrence of specified events of default, the non-defaulting Co-Owner may purchase the defaulting Co-Owner’s interest for 90% of the fair market value. The Co-Owners have entered into a management agreement with NR-Algonquin Energy Management Inc. to manage the Facility on their behalf for nominal consideration.

iv)

Credit Agreements

There is an outstanding senior loan against the Facility in the amount of $39.0 million at December 31, 2011. The loan was provided by a syndicate comprised of The Clarica Life Insurance Company (“Clarica”), The Canada Life Assurance Company and the Maritime Life Assurance Company. Clarica acts as agent for the syndicate. The loan has a term of 30 years, maturing in January 2028 and bears interest at an interest rate of 10.16% for the first 15 years and 10.21% thereafter, compounded annually. Blended payments of principal and interest are made monthly. The loan is non-recourse to APCo and is secured by the Facility and the ownership interests therein.

Under the terms of the credit agreement, a debt reserve is required. In 2008, APCo issued an irrevocable letter of credit in an amount of $1.2 million to replace the debt service escrow deposit. At December 31, 2011, the debt reserve was fully funded using the irrevocable letter of credit.

In addition, APCo owns the LSR Subordinate Note.

APMI Residual Ownership Interest

APCo’s interest in Long Sault is by way of subscribing to two notes from the original developers, which effectively entitles it 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.

An affiliate of APMI is one of the original partners in the facility and is entitled to receive 5% of the equity cash flows commencing in 2014. Subsequent to December 31, 2012, APCo reached an agreement with the affiliate of APMI to acquire residual partnership interest in the Long Sault Rapids hydroelectric facility as part of an agreement to resolve a number of the historic business relationships between APCo and APMI. (See “Recent Developments – 2012: Business Associations with APMI and Senior Executives”).

(2)

Côte Ste-Catherine Facility

The Côte Ste-Catherine Facility is a hydroelectric generating facility located at the Côte Ste-Catherine lock of the Lachine section of the St. Lawrence Seaway. The bypass canal upon

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which the facility is located was constructed as part of the St. Lawrence Seaway in 1958. The Facility has a total installed capacity of 11.1 MW. The Facility is owned by the Mont-Laurier Partnership.

The land and water rights necessary for the operation of the Facility have been obtained from the St. Lawrence Seaway Authority by way of a lease agreement with the Province of Québec. In 2009, the water rights lease was renewed for a term of 21 years commencing March 1, 2009. Although the Facility is located on a federal waterway, the Province of Quebec has asserted jurisdiction over the water rights to this Facility and has also asserted a claim against a predecessor by amalgamation to APFC for payment of revenues paid to the federal authority. See “Legal Proceedings and Regulatory Actions – Legal Proceedings”.

(3)

Mont Laurier Facility

The Mont Laurier Facility is a 2.7 MW hydroelectric generating facility located on the Rivière-du-Lièvre in the Town of Mont Laurier, Québec. The Facility is owned by the Mont-Laurier Partnership.

The Facility is constructed on lands owned by the Mont-Laurier Partnership. Water rights necessary for the operation of the facility have been leased from the Ministry of Natural Resources (Québec) pursuant to a lease agreement dated March 23, 1988 and assigned to the Mont Laurier Partnership on October 31, 1994. The term of the lease expires on December 31, 2023.

(4)

Côte Ste-Catherine and Mont Laurier, PPAs—General

Each of the Côte Ste-Catherine and Mont Laurier Facilities have PPAs with Hydro-Québec under which all power generated by the facilities is sold to Hydro-Québec. The standard Hydro-Québec PPA stipulates annual minimum energy production requirements in each contract year. Under most Hydro-Québec PPAs, if a facility produces less energy than the minimum, a penalty is payable to Hydro-Québec. The facility can opt to reduce any energy production shortfall over a two year period using energy produced in excess of the minimum requirement, after which, a penalty is payable on any outstanding amounts at the current year prices.

Power purchase rates under the Hydro-Québec agreements (other than for the Mont Laurier and Côte Ste-Catherine (Phase I) Facilities) increase in accordance with the Consumer Price Index for the Montréal Urban Community, as published by Statistics Canada, with a minimum annual escalation of 3% and a maximum annual escalation of 6%. The Mont Laurier Facility is subject to a fixed annual escalation of 1.8%. The Côte Ste-Catherine Facility (Phase I) power purchase rate increases at a fixed annual index of 1.1% for the first four years and 1.8% thereafter.

(5)

Tinker Hydro Facility

The Tinker Facility is located 5 miles north of Perth-Andover, New Brunswick and is situated near the mouth of the Aroostook River. The Facility consists of five hydro units and a 1 MW diesel generator; the total nameplate capacity of the station equals 34.5 MW. Unit 5 of the Facility is currently operating as a fixed bladed runner. Historical gross generation from the station averages 120,000 MW-hrs per year. The Facility benefits from the flow regulation of the Squa Pan Facilities, both of which are also owned and operated by APCo.

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Transmission facilities

As part of the generation assets in New Brunswick and Northern Maine, APCo owns and operates an electrical transmission system consisting of 14.7 km of 69 kV transmission line facilities. These facilities are used to interconnect the Tinker Facility to the New Brunswick transmission network, provide transmission service to Perth Andover Electric Light Commission, and provide export/import capacity between Maine and New Brunswick. The transmission facilities are currently included in the Open Access Transmission Tariff of the NBSO.

ii)

PPA

The Facility supplies approximately 31,000 MW-hrs per year to the municipal utility of Perth-Andover under a PPA expiring in 2021. The remaining generation from the plant, approximately 89,000 MW-hrs per year, is sold to AES for resale to commercial and industrial customers in the northern Maine and New Brunswick markets, as well as energy and capacity to the Maine and New Brunswick electricity markets.

(6)

Dickson Dam Facility

The Dickson Dam Facility is located 20 kilometres west of the Town of Innisfail, Alberta. The Facility is a 15.0 MW hydroelectric generating facility utilizing the infrastructure located at the Dickson Dam and powered by the water flows of the Red Deer River. The Facility consists of three horizontal Francis type turbines and was commissioned into commercial operation on January 16, 1992. The facility is owned by APOT.

PPA

The Dickson Dam PPA with TransAlta Utilities Corporation ended on January 16, 2012. Since January 17, 2012, the Facility is participating in the Alberta Power Pool selling electricity at the real time market price. APCo is exploring options to sell power to a third party and expects to put a fixed price contract in place for the output from the Facility in the second quarter of 2012.

ii)

Use of Works Agreement

The Facility is subject to a Use of Works Agreement with the Government of Alberta under which it has the right to utilize available water flows for generating power until March 31, 2030. The Use of Works Agreement provides certain rights in favour of the Minister of Environment (Alberta) in connection with the Minister’s water management objectives.

(b)

Power Generation: Renewable—Wind Power

(i)

Production Method

The energy of the wind can be harnessed for the production of electricity through the use of wind turbines. A wind energy system transforms the kinetic energy of wind into electrical energy that can be delivered to the electricity distribution system for use by energy consumers. When the wind blows, large rotor blades on the wind turbines are rotated, generating energy that is converted to electricity. Most modern wind turbines consist of a rotor mounted on a shaft connected to a speed increasing gear box and high speed generator. Monitoring systems control the angle of and power output from the rotor blades to ensure that the rotor blades are turned to face the wind direction, and generally to monitor the wind turbines installed at a facility.

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(ii)

Principal Markets and Distribution Methods

The principal market for APCo’s St. Leon Facility is Manitoba. The electricity generated by the wind turbines at the St. Leon Facility is transmitted via underground distribution lines to the facility’s substation for subsequent delivery to the transmission system of the purchaser, Manitoba Hydro-Electric Board (“Manitoba Hydro”). The purchaser then distributes the electricity to its customers or to other endpoints via the grid.

(1)

Manitoba

Historically, Manitoba Hydro had been exclusively responsible for the production of electricity in the province. Manitoba Hydro is a net exporter of electricity, mainly to Ontario and certain states of the United States. To date, the province has been able to utilize its large hydroelectric resources to satisfy internal and export requirements.

The Manitoba government and Manitoba Hydro have independently undertaken studies to determine the potential of wind power generation in Manitoba. As a result of such studies, the Manitoba Government has advised it plans to have additional capacity of approximately 1,000 MW of wind power, to be constructed, using in part, independent power producers by 2014.

(2)

Saskatchewan

Saskatchewan’s electricity market remains under provincial government control and has not undergone any significant deregulation. SaskPower, the primary electricity utility in Saskatchewan, is wholly-owned by the province through Crown Investments Corporation. SaskPower anticipates requiring 1,700 MW of additional supply by 2020 and 3,700 MW by 2030 to accommodate load growth and the retirement of generation facilities. As part of this, SaskPower has a number of programs to encourage and solicit wind and other renewable power from independent producers.

(iii)

Material Facilities

(1)

St. Leon Facility

The St. Leon Facility is a 104 MW wind energy facility located near St. Leon, Manitoba, 150 km southwest of Winnipeg. The facility is owned by St. Leon LP.

On September 18, 2007, the St. Leon Facility achieved commercial operation pursuant to a turn-key construction contract dated November 12, 2004. In January 2010, APCo executed an Operation and Maintenance Service Agreement with Vestas-Canadian Wind Technology, Inc. (“Vestas”) whereby Vestas provides operation, maintenance and repair services at a contracted rate to the St. Leon Facility for approximately 20 years.

PPA

St. Leon LP and St. Leon GP have entered into a PPA with Manitoba Hydro dated as of October 28, 2004 under which all electricity produced at the St. Leon Facility is sold to Manitoba Hydro.

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As of June 17, 2006, the facility achieved commercial operation status under the PPA with Manitoba Hydro. The term of the PPA is 20 years, with a price renewal term of up to an additional 5 years. Under the terms of the PPA, security in an amount of $1.8 million is required and as at December 31, 2011, the security was fully funded using an irrevocable letter of credit.

St. Leon LP entered into a Wind Power Production Incentive (“WPPI”) agreement with the Ministry of Natural Resources—Canada which entitles the St. Leon Facility to receive an incentive from the Federal Government of $10.00 per MW-hr to a maximum of $3.7 million annually for a period of ten years ending March 2016. APCo anticipates that the facility will earn WPPI of approximately $3.0 million annually based on the current estimated long term wind resource.

ii)

Credit Facility

A banking syndicate provided the AirSource Senior Debt to St. Leon Trust to finance construction of the St. Leon Facility. The AirSource Senior Debt had an amount of $67.8 million outstanding as at August 2011 when it was repaid. There is currently no debt agreement with external third parties associated with this facility.

(c)

Power Generation: Thermal—Energy From Waste

(i)

Production Method

In North America and elsewhere, the combination of increasing population and stricter environmental regulations has imposed increasing limitations upon the development of new municipal landfills and on the expansion of existing landfills. Energy-from-waste facilities are considered a viable option to reduce the total tonnage of municipal waste being directed to landfills and to extend the useful life of existing landfills. The establishment of energy-from-waste facilities is now a licensed process in certain states of the United States and Canadian provinces.

The incineration process reduces the waste to an ash which is less than one third of the original volume of waste. The residual ash is then transported to a land fill. The heat recovered from municipal solid waste is used to make steam which can be used to provide thermal energy or can be used to drive turbines and generate electricity.

(1)

Principal Markets and Distribution Methods

See “Material Facilities” immediately below.

(ii)

Material Facilities

(1)

EFW Facility

The EFW Facility is a 10 MW generating station located in Brampton, Ontario which produces electricity from incinerating non-recyclable materials, including municipal solid waste. The facility is designed to incinerate over 500 tonnes per day of municipal solid waste from five incinerators to produce an average of approximately 60,000 pounds per hour of steam which is the excess of the steam required for production of internally consumed electricity. It is owned by APEFW which forms part of the APCo ownership chain.

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The principal customer of the EFW facility is the Region of Peel (the “Region”). The facility is currently permitted to accept domestic waste from the Region of Peel and non-hazardous commercial/industrial waste from the Regions of Peel, Halton, York, Durham and the City of Toronto. In addition the facility is permitted to accept international airport waste from Pearson and Hamilton International Airports. The facility is currently working to amend its permits to accept domestic waste from all of Ontario and expects to conclude this process in 2012.

The majority of the EFW steam is diverted to the BCI Facility. See “Description of the business – Production Method, Principal Markets, Distribution Methods and Material Facilities – Thermal: Cogeneration – Material Facilities – BCI Facility”. A portion of the EFW Facility steam is used by the EFW Facility to generate electricity in a steam turbine generator, the electricity from which is used to supply internal operations with any excess generation being sold to OEFC.

PPA

The EFW Facility is selling electricity at the Hourly Ontario Energy Price (“HOEP”). The HOEP is the hourly price that is charged to local distribution companies, other non-dispatchable loads and self-scheduling generators. APCo is currently negotiating with the OPA to enter into a new long term contract for the power output from the EFW Facility.

ii)

Fuel Supply

Under a “tip or pay” waste supply agreement, the Region supplies the facility with a minimum of 127,900 tonnes per year of acceptable municipal solid waste. The EFW facility “tip or pay” waste supply agreement with the Region expires in April 2012. On February 23, 2012, the Peel Regional Council decided to seek competitive proposals from several waste management companies, including APCo. APCo is participating in this proposal process. In addition, the facility is currently permitted to accept commercial and industrial waste from certain other jurisdictions outside of the region of Peel. APCo is actively sourcing alternative supply options with respect to municipal solid waste from other jurisdictions to ensure a continued supply of waste for the facility.

(d)

Power Generation: Thermal–Cogeneration

(i)

Production Method

Cogeneration is the simultaneous production of electricity and thermal energy such as hot water or steam from a single fuel source. Often natural gas is used to produce both electricity and steam. The steam produced is normally required by an associated or nearby commercial facility, while the electricity generated is sold to a utility or used within the facility. Cogeneration provides facilities with greater efficiency, greater reliability and increased process flexibility than conventional generation methods. Examples of industries using cogeneration facilities include food processing, pulp and paper and chemical plants.

Where both electrical and thermal energy are generated separately, typically one third to one half of the fuel’s energy content is converted into useful energy output such as steam or electricity. The remainder is wasted energy which escapes as unused heat. By producing electricity and steam simultaneously, cogeneration uses a higher proportion of the fuel’s energy content. Depending on the degree of steam and/or useful heat utilization, 55% to 80% of the fuel’s energy content is converted into useful energy output, which produces significant fuel savings over conventional arrangements.

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Cogeneration compared to conventional processes also has environmental benefits as it results in burning less fuel and producing less carbon dioxide. Furthermore, in cogeneration facilities which use fuels such as natural gas or oil, sulphur dioxide and nitrous oxide emissions are greatly reduced compared to other technologies and fuels.

(ii)

Principal Markets and Distribution Methods

The principal markets of APCo’s cogeneration facilities are California and Connecticut. The electricity produced from these facilities is conveyed from the relevant facility to the electricity markets either under the terms of long-term contracts or according to Independent System Operator rules. In addition, electrical capacity and other ancillary services are sold either under the terms of a long term contract or according to the Independent System Operator rules. A summary of the contracts for the Cogeneration facilities is attached in Schedule B. In addition to grid sales of electricity and power, electricity and thermal energy is also sold to nearby third party purchasers for use in their production facilities.

(1)

California

The electric transmission system and wholesale markets in California are primarily regulated by the California Energy Commission and FERC. The California Independent System Operator administers the wholesale electricity market place for the region.

(2)

Connecticut

Connecticut Light and Power Company (“CL&P”) is part of the North East Utilities System which is located in the New England Power Pool. The Independent System Operator New England (“ISO-NE”) was established as a not-for-profit, private corporation on July 1, 1997 following its approval by FERC. The organization immediately assumed responsibility for managing the New England region’s electric bulk power generation and transmission systems and administering the region’s open access transmission tariff.

Since May 1, 1999, ISO-NE has also administered the wholesale electricity marketplace for the region. Six electricity products are bought and sold by market participants on an internet-based market system.

(iii)

Material Facilities

(1)

Sanger Facility

The Sanger Facility is a 56MW natural gas-fired generating facility located in Sanger, California. The Facility is a combined cycle generating station comprised of a 44 MW General Electric LM6000 natural gas fired turbine, commissioned in 2008, and a 12.5 MW Westinghouse steam turbine, commissioned in 1991. The Facility is owned by Algonquin Power Sanger LLC, a subsidiary of APFA.

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PPA

Output of the Facility is governed by the terms and conditions of a firm capacity and energy PPA with Pacific Gas & Electric Company (“PG&E”). The agreement has a term of 30 years, expiring in 2022, and calls for delivery of 38 MW of firm capacity.

ii)

Fuel Supply

Natural gas for the Facility is delivered under the terms of a gas supply agreement dated August 1, 2006 with Constellation NewEnergy for the purchase and sale of all natural gas required for the facility. The expected gas requirement for the subsequent month is bought at the market rates available on the gas nomination date, which is typically the 20th day of each month. Gas above or below the nomination requirement can be bought or sold at the applicable spot prices.

iii)

Energy Lease

Pursuant to a lease, energy supply and common services agreement with Dyna Fibers Inc., a wholly-owned subsidiary of Sanger LLC, Dyna Fibers Inc. leases a portion of the facility site in order to carry on its hydro mulch business and purchases certain energy at a cost equal to a percentage of the fuel costs incurred by the Facility, to offset the incremental cost of fuel to supply such energy. The water consumption, exhaust heat and steam consumption by the hydro mulch operations are metered and recorded for FERC qualifying facility calculations that are submitted to PG&E on an annual basis.

iv)

Credit Facility

There is an outstanding senior loan against the Facility in the amount of US $19.2 million as at December 31, 2011. The loan is a California Pollution Control Finance Authority Variable Rate Demand Resource Recovery Revenue Bond, due September 1, 2020. The senior loan bears interest at variable rates, reset monthly. Interest is payable monthly with no principal repayments. The effective interest rate in 2010 was 1.33%. The loan is secured solely by the Facility, the ownership interests therein and an irrevocable letter of credit in an amount of US $19.5 million.

(2)

Windsor Locks Facility

The Windsor Locks Facility is a 56 MW natural gas-fired generating facility located in Windsor Locks, Connecticut. The Facility is a combined cycle generating station comprised of a 40 MW General Electric natural gas fired turbine and a 16 MW General Electric steam turbine and was commissioned in 1990. The Facility is owned by Windsor LLC.

Prior to April 2010, the Facility ran at capacity, providing the steam and power requirements of Ahlstrom pursuant to the ESA with the remainder of the electrical generation being sold to CL&P. With the expiry of the PPA with CL&P, APCo determined that the existing gas turbine is not appropriately sized to meet the electrical and steam requirements of Ahlstrom.

APCo has entered into an extension of the ESA with Ahlstrom, the extended term continues until 2027, and supports the installation of a new 14 MW Solar Titan combustion gas turbine which is more appropriately sized to meet the electrical and steam requirements of the steam host. The new cogeneration equipment is being installed with commercial operation expected in

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July 2012. The total expected capital cost for this project is estimated at approximately U.S. $25 million. APCo believes it is eligible to receive a one-time non-recurring grant from the State of Connecticut equivalent to U.S. $450/KW to a maximum of U.S. $6.6 million which would offset the cost of such re-powering. An additional benefit of the State of Connecticut grant program is that local distribution charges for natural gas used by the new turbine are waived, with an estimated benefit to the Facility of approximately U.S. $500,000/year.

In addition to installing the new gas turbine, APCo would expect to continue to operate the existing electrical generating equipment in the ISO NE market when it is commercially profitable to do so. APCo also believes that this project would qualify for a combined heat and power investment tax credit (“ITC”) sponsored by the U.S. Federal Government. The benefit of the ITC grant is approximately U.S. $1 million in addition to the Connecticut DPUC grant would offset the cost of such re-powering.

Energy Services Agreement and Ground Lease

The Facility supplies thermal steam energy and a portion of electrical generation to Ahlstrom, a leading paper and non woven materials manufacturer, pursuant to a ground lease and the ESA. Pursuant to the ESA, Ahlstrom leases the facility site to Windsor LLC and utilizes thermal steam energy and a portion of electrical generation of the Facility for use at its specialty fibers composites mill located adjacent to the Facility. APCo has entered into an extension of the ESA with Ahlstrom, the extended term continues until 2027. Payments under the ESA are fully indexed to the cost of natural gas consumed by the Facility.

ii)

PPA

The electrical output of the Facility not used to meet Ahlstrom’s requirements is committed to the ISO-NE electricity market. Since April 2010, the Facility has bid its remaining available capacity of approximately 40 MW into the thirty minute forward operating reserve market. APCo’s AES group manages the off-take sales from this Facility into the ISO-NE market.

iii)

Fuel Supply

Natural gas for the facility continues to be delivered under a gas supply agreement with Yankee Gas Service Company (“Yankee Gas”). Gas is supplied by Yankee Gas at a percentage of its weighted average cost of gas for the month. The gas contract contains minimum annual consumption requirements with associated penalties for shortfalls. The Yankee Gas agreement was scheduled to terminate coincident with the PPA. APCo has agreed with Yankee Gas that the arrangements under the existing contract will be maintained until the new turbine is installed.

APCo and Yankee Gas continue to negotiate a new agreement that will allow the Facility to use Yankee Gas as a local distribution company which will enhance the Facility’s purchase options for its natural gas requirements. It is expected that once the new turbine is installed the existing contract will be replaced by individual contracts for each of the new combustion turbine, the auxiliary boilers and the existing Frame 6 turbine. Yankee Gas is currently upgrading the gas service to accommodate the new combustion turbine.

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(3)

BCI Facility

The BCI Facility is a cogeneration facility located in Brampton, Ontario on the EFW Facility site. It was commissioned and became operational in June 2008. The project was established to meet the steam requirements of a nearby recycled paper board manufacturing mill that requires approximately 90,000 pounds of steam per hour in its manufacturing activities.

The Facility consists of a 150,000 pound per hour gas-fired boiler, a water treatment system, pumps to support the boiler, a twelve inch diameter pipeline to supply a nearby recycled paper board manufacturing mill with steam and a six inch diameter pipeline for condensate return. The majority of the steam supplied to the mill is produced by the EFW Facility with the gas-fired auxiliary boiler supporting peak steam demand and providing full standby capacity during normal downtime periods at the EFW Facility and where operations at the EFW Facility cannot provide sufficient volume of steam.

(4)

Kirkland Facility

The Kirkland Facility is a 132MW combined cycle integrated fuels generation station located in Kirkland Lake, Ontario owned by Kirkland Lake Power Corp. (“Kirkland”) which burns natural gas and wood waste to generate electricity using four gas turbines and two steam turbines. The Facility was developed in two phases: the first 102MW was commissioned in 1991, operating in baseload, and the remaining 30MW was added in 2004 as a dispatchable or peaking plant. Northland Power Inc. (“Northland”) manages the operations. Electricity produced by the Facility is sold to OEFC pursuant to a 40 year contract, which expires in 2030. Natural gas used by the Facility is supplied under 20 year supply contracts. Price increases under such gas supply agreements are generally tied to price increases under the PPAs with OEFC. Wood waste consumed by the Facility is supplied by local forest product companies under contracts of varying terms with the longest being 25 years.

APT owns 32.4% of the Class B non-voting shares issued by Kirkland. It is Kirkland’s policy to declare and pay quarterly dividends on its shares equal to substantially all of its after-tax income. Kirkland had a put option to sell the Facility to Northland with an exercise date of February 28, 2011 at an exercise price of $10 million. Further to a shareholder meeting on November 12, 2009, the Kirkland shareholders decided not to exercise the put option as the present value of the expected future dividends from this investment were expected to exceed funds they would receive from the put option. As a result, subsequent to February 28, 2011, 75% of operating income of the Facility is paid to Northland under the management agreement.

(5)

Cochrane Facility

The Cochrane Facility is a 40MW combined cycle integrated fuels generating station located in the Town of Cochrane, Ontario. The Facility is owned by Cochrane Power Corporation (“Cochrane”) which burns natural gas and wood waste to generate power using a gas turbine and a steam turbine. The Facility was commissioned in 1990 and is currently managed by Northland. Electricity produced by the Facility is sold to OEFC pursuant to a 25 year contract, which expires in 2014. The majority of the natural gas used by the Facility is supplied under a supply contract which expires in 2016. Price increases under such gas supply agreements are generally tied to price increases under the PPA with OEFC. Wood waste consumed by the facility is supplied by local forest product companies under contracts of varying terms with the longest being 25 years.

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APT owns 25% of the Class B non-voting shares issued by Cochrane. It is Cochrane’s policy to declare and pay quarterly dividends on its shares equal to substantially all of its after-tax income. Cochrane had a put option to sell the Facility to Northland with an exercise date of February 28, 2011 at an exercise price of $3 million. Further to a shareholder meeting on November 12, 2009, the Cochrane shareholders decided not to exercise the put option as the present value of the expected future dividends from this investment were expected to exceed funds they would receive from the put option. As a result, subsequent to February 28, 2011, 75% of operating income of the facility is paid to Northland under the management agreement.

(e)

Power Generation: Algonquin Energy Services

The primary business of AES is to market the output of the Tinker Facility and other APCo owned assets which would otherwise sell the energy they generate on a merchant basis. AES also works to develop strategies for selling the power output of other APCo facilities that are approaching the end of their PPAs and to engage, where possible, in actual selling of power for APCo facilities that would otherwise sell power on a merchant basis.

(i)

Production Method

AES provides standard offer contracts and direct customer contracts for the supply of energy to commercial and industrial customers using a series of short-term energy supply agreements.

(ii)

Principal Markets and Distribution Methods

AES provides energy to commercial and industrial customers in the northern Maine and New Brunswick markets. AES anticipates that, based on the expected load forecast for its existing contracts, it will provide approximately 100,000 MW-hrs of energy to its customers.

AES purchases the majority of its energy requirements from the Tinker Facility. Based on historical long term average levels of hydroelectric energy generation, the Tinker facility is anticipated to provide greater than 65% of the energy required by AES to service its customers and provides a natural hedge on supply costs of AES.

In addition to the energy generation provided by the Tinker Facility, AES purchases additional energy on the open market in order to services its customer demand. APCo manages the risk associated with this business through internally generated energy from the Tinker facility, as well as through the purchase of fixed volume/prices from the ISO-NE market. In addition, AES negotiates appropriate consumption volumes and pricing indexes with large retail and wholesale consumers in northern Maine to ensure risk associated with volatility of consumption by the consumer is mitigated.

(iii)

Material Facilities

AES operates using a series of energy supply agreements. These include energy sales to a town in New Brunswick, Standard Offer Service contracts with two local electric utilities in northern Maine, and a series of direct energy contracts with commercial buyers also in northern Maine. AES has energy purchase obligations with the ISO-NE as required to supplement self-generated energy.

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AES entered into a three year contract with MPS starting March 1, 2011 to provide Standard Offer Service to multiple commercial and industrial customers in Northern Maine. The anticipated annual customer load associated with the standard offer service is approximately 135,000 MW-hrs.

(f)

Power Generation: Development

(i)

Target Markets / Development Strategy

The Development division works to identify, develop and construct new, renewable and efficient power generating facilities, as well as to identify, develop and construct other accretive projects that maximize the potential of APCo’s existing facilities. Development is focused on projects within North America with a commitment to working proactively with all stakeholders, including local communities. It utilizes existing industry relationships to assist in the identification, evaluation, development and construction of projects, and retains expertise, as required, from the financial, legal, engineering, technical, and construction sectors.

The Development division may also create opportunities through the acquisition of operating assets with accretive characteristics and prospective projects that are at various stages of development. The Development division believes that the prevailing economic climate has also created opportunities for APCo to acquire third party development projects on terms that require the experience and financial resources that APCo has at its disposal. The strategy is to focus on high quality renewable and high efficiency thermal energy generation projects that benefit from low operating costs using proven technology that can generate sustainable and increasing operating profit in order to achieve a high return on invested capital.

APCo’s approach to project development is to maximize the utilization of internal resources while minimizing external costs. This allows development projects to evolve to the point where most major elements and uncertainties of a project are quantified and resolved prior to the commencement of project construction. Major elements and uncertainties of a project include the signing of a PPA, obtaining the required financing commitments to develop the project, completion of environmental permitting, and fixing the cost of the major capital components of the project. It is not until all major aspects of a project are secured that APCo will begin construction.

(ii)

Principal Market Environment

APCo believes that future opportunities for power generation projects will continue to arise given that many jurisdictions, both in Canada and the U.S., continue to increase targets for renewable and other clean power generation projects. As an example, the Ontario government passed the GEA. Accordingly the OPA has issued standard pricing for electricity from renewable sources under a FIT program. Included within this legislation is the requirement for OPA to purchase power generated from green energy projects, and an obligation for all utilities to grant priority grid access to such projects. The intention of the legislation is to make development of renewable energy projects significantly easier than the prior process of formal bids in response to requests for proposals from the responsible power authority.

Other jurisdictions have passed or are considering similar legislation to provide incentives for development of new renewable power generation from independent producers. The combination of increased renewable production targets and appropriate fixed pricing will present investment opportunities for APCo to consider in the future.

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APCo continues to actively pursue development projects which provide the opportunity to exhibit accretive growth. APCo anticipates its involvement in many future opportunities as initiatives designed to support independent power producers are being extensively supported by Canadian provincial governments and several U.S. states.

(iii)

Current Development Projects

APCo’s Development Division has successfully advanced a number of projects and has been awarded or acquired a number of PPAs. The projects are as follows:


Project Name (Location)	Location	Size (MW)	Estimated Capital Cost	Commercial Operation	PPA Term	Production GWhr
Chaplin Wind ¹	Saskatchewan	177	$355.0	2016	25	720.0
Amherst Island ²	Ontario	75	$230.0	2014	25	247.0
Morse Wind ^{3, 4}	Saskatchewan	25	$70.0	2014	20	93.0
St. Damase ¹	Quebec	24	$70.0	2013	20	86.0
Val Eo ¹	Quebec	24	$70.0	2015	20	66.0
St. Leon II ¹	Manitoba	17	$30.0	2012	25	58.0
Cornwall Solar ^{1, 2}	Ontario	10	$45.0	2013	20	13.4

Total		352	$870.0			1,283.4

Notes:

1	PPA signed

2	FIT contract awarded

3	Two 10 MW PPAs; one 5 MW PPA

4	Comprised of three projects that are connected geographically and will be built simultaneously. All three projects were awarded PPAs under the province’s Green Options Partner Program (“GOPP”).

(1)

Chaplin Wind

Subsequent to December 31, 2011, APCo entered into a 25 year PPA with SaskPower for development of a 177 MW wind power project in the rural municipality of Chaplin, Saskatchewan, 200 km west of Regina, Saskatchewan.

The project has a targeted commercial operation date of December, 2016. The facility will be constructed at an estimated capital cost of $355 million and consist of approximately 77 multi-megawatt wind turbines. The project is expected to generate first full year EBITDA of $37.5 million. The 25 year PPA features a rate escalation provision of 0.6% throughout the term of the agreement. The project will take advantage of a favourable interconnection location by interconnecting with SaskPower’s new P1S 230 kV transmission line from Swift Current to Moose Jaw and will be compliant with SaskPower’s latest interconnection requirements.

(2)

Amherst Island Wind

The Amherst Island Wind Project is located on Amherst Island in the village of Stella, approximately 25 kilometres southwest of Kingston, Ontario. In February 2011, the 75 MW project was awarded a FIT contract by the OPA as part of the second round of the OPA’s FIT program.

The FIT contract originally stated that the OPA had the option to terminate the FIT contract prior to the date that the OPA had issued a Notice to Proceed (“NTP”) and APCo had paid the

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incremental security required by the NTP. On August 2, 2011, the Ontario Ministry of Energy directed the OPA to offer FIT contract holders the opportunity to have the OPA’s termination rights under the FIT contract waived. APCo exercised this option on August 9, 2011. As required by the waiver, APCo submitted a domestic content plan on October 14, 2011 and provided a statutory declaration regarding equipment supply commitments by November 30, 2011.

The project is currently contemplated to use efficient Class III wind turbine generator technology. APCo forecasts that the available wind resource could produce approximately 247 GWhr of electrical energy annually, depending upon the final turbine selection for the project. Total capital costs for the facility are currently estimated to be $230 million. The financing of the project will be arranged and announced when all required permitting and all other pre-construction conditions have been satisfied. Environmental studies and engineering are underway. The submission of the renewable energy application is targeted for the summer of 2012. Construction will commence shortly following the approval of the application and is expected to take 12 to 18 months.

(3)

Morse Wind Project

The Morse Wind Project is comprised of three contiguous projects with 25 MW in aggregate installed generating capacity. The project is to be constructed near Morse, Saskatchewan, approximately 180 km west of Regina. It is contemplated that the project will have additional land under lease or option in order to facilitate future expansion.

APCo executed an asset purchase agreement with a local developer (“Kineticor”) to acquire assets related to two adjacent 10 MW wind energy development projects in Saskatchewan and a further 5 MW was developed by APCo independently. All of the individual projects comprising the Morse Wind Project were selected by SaskPower for award of PPAs in accordance with the SaskPower Green Options Partners Program. The two 10 MW PPA’s were awarded in May 2010 and the 5 MW PPA was awarded in June 2011. Upon SaskPower’s approval and execution of the Kineticor PPAs, Kineticor will then assign the PPAs to APCo. All three of the projects are expected to be completed contemporaneously in early 2014.

The total annual energy production for the Morse Wind Project is estimated to be 93,000 MWhr. The capital cost to construct the Morse Wind Project is currently estimated to be $65-$70 million, inclusive of acquisition costs. The first year PPA rate is set at $101.98 per MWhr for the first full year of operations, which APCo expects to occur in 2014, with an annual escalation provision of 2% over the expected 20 year term.

(4)

Quebec Community Wind Projects

In 2010, APCo worked with Société en Commandite Val-Éo, a community cooperative with a development project located in the Lac Saint-Jean region of Quebec, and the community of Saint-Damase to submit proposals into Hydro Quebec’s 250 MW wind Request for Proposal. On December 20, 2010, both projects were awarded power purchase contracts that stipulate the use of ENERCON wind turbines.

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Saint-Damase

The Saint-Damase Wind Project is located in the local municipality of Saint-Damase which is within the regional municipality of la Matapédia. The project proponents include the Municipality of Saint-Damase and APCo. The first 24 MW phase of the project is expected to be comprised of eight to twelve generators (depending on the cost and generating capacity of the selected wind turbine model), producing approximately 86,000 MWhr annually. Construction of the first 24 MW phase of the project is estimated to begin in early 2013 with a commercial operations date in late 2013.

The interest of APUC in the project will not be less than 50%. Final funding of the project will be arranged and announced when all required permitting has been met, and all other pre-construction conditions have been satisfied. Preliminary permitting began in early 2011 and studies of flora and fauna and the public consultation process are ongoing. Meetings were conducted July 2011 and March 2012 with participating landowners in addition to open houses to obtain additional community feedback. All major environmental authorizations are targeted for completion by the end of 2012.

ii)

Val-Éo

The Val-Éo Wind Project is located in the local municipality of Saint-Gédéon de Grandmont, which is within the regional municipality of Lac-Saint-Jean-Est. The project proponents include the Val-Éo wind cooperative formed by community based landowners and APCo. The first 24 MW phase of the project is expected to be comprised of eight generators, producing approximately 66,000 MWhr annually. Construction of the first 24 MW phase of the project is expected to begin in early 2015 with commercial operations occurring in late 2015.

The interest of APUC in the project is subject to final negotiations with the cooperative but, in any event, will not be less 25%. Final funding of the project will be arranged and announced when all required permitting has been met, and all other pre-construction conditions have been satisfied. Preliminary permitting began in early 2011 and studies of flora and fauna and the public consultation process are ongoing with all major authorizations targeted for completion by the end of 2012.

(5)

St. Leon II

In July 2011, APCo executed a 25-year PPA with Manitoba Hydro in respect of St. Leon II (a 16.5 MW expansion of APUC’s existing St. Leon wind energy project located in the Province of Manitoba). Construction of this project commenced on August 30, 2011 using 10 Vestas V82 turbines. The final turbine was erected in February 2012 and the project is generating energy on all units as of March 1, 2012. The project is expected to achieve commercial operation in the second quarter of 2012. The total capital cost of the project is expected to be $29.5 million.

(6)

Cornwall Solar

APCo entered into a share purchase agreement with EffiSolar to acquire all of the issued and outstanding shares of Cornwall Solar Inc. based upon the achievement of specific milestones. On December 30, 2011 OPA approval was received and the transaction closed on January 4, 2012. Cornwall Solar owns the rights to develop a 10 MWac solar project located near Cornwall, Ontario. In addition to the Cornwall project, APCo has acquired an option to acquire 10 additional Ontario based solar projects. Projects in the FIT pipeline have submitted FIT applications for an additional 100MWac.

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The project has been granted an Ontario FIT contract by the OPA, with a 20 year term and a rate of $443/MWhr, resulting in expected initial annual revenues of approximately $6.2 million. The Project contemplates the use of a ground-mounted PV array system, with expected annual generation of approximately 13,400 MWh, enough to provide electricity to approximately 1,000 homes.

Following the completion of all regulatory submissions and approvals, construction of the project is expected to begin in the second half of 2012, with a Commercial Operation Date estimated in early 2013. The project is being developed on two parcels of leased land totalling approximately 138 acres.

Total capital cost of the project is targeted at approximately $45 million, which amount includes the consideration to be paid for the acquisition of the project. Funding for the project will be arranged and announced when all required permitting and all other pre-construction conditions have been satisfied.

(7)

Other

APCo has completed preliminary engineering and a financial feasibility analysis on a 12 MW combined cycle high efficiency thermal energy generation project located in Ontario. APCo believes this project is an excellent fit for the Minister of Energy and Infrastructure’s (the “Ministry”) Directive to procure electricity from combined heat and power projects. The Ministry is currently taking registrations from interested parties that wish to participate in such a program.

(iv)

Future Development Projects – Greenfield Projects

There are a number of future greenfield development projects which are being actively pursued by the Development division. These projects encompass several new wind energy projects, hydroelectric projects at different stages of investigation, and thermal energy generation projects. The projects being examined are located both in Canada and the U.S.

(g)

Utilities: Water and Wastewater

(i)

Method of Providing Services and Distribution Methods

A utility services company provides regulated utility water supply and/or wastewater collection and treatment services to its customers.

A water utility sources, treats and stores potable water and subsequently distributes it to its customers through a network of buried pipes (distribution mains). A wastewater utility collects wastewater from its customers and transports it through a network of collection pipes, lift stations and manholes to a centralized facility where it is treated, rendering it suitable for discharge to the environment or for reuse, usually as irrigation.

The raw water for human consumption is sourced from the ground and extracted through wells or from surface waters such as lakes or rivers. The water is treated to potable water standards that are specified in Federal and State regulations and which are typically administered and enforced by a State or local agency. Following treatment, the water is either pumped directly into the distribution system or pumped into storage reservoirs from which it is subsequently pumped into the distribution system. This system of wells, pumps, storage vessels and distribution infrastructure is owned and maintained by the private utility.

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The fees or rates charged for water are comprised of a fixed charge component plus a variable fee based on the volume of water used. Additional fees are typically chargeable for other services such as establishing a connection, late fee, reconnects, etc.

In respect of sewer or wastewater services, the sewage or wastewater produced by the customer flows through a buried service lateral line from the house or commercial space to the street which line is owned and maintained by the customer. This line feeds into collection pipes or lines (collection mains) located under or adjacent to the street which pipes are owned and maintained by the private utility. These pipes generally slope at a grade of approximately 1% as gravity is generally relied on to facilitate flows. On long line runs where maintaining slopes would result in excessive depths below grade or to traverse variable terrain, the line may terminate at a lift station where wastewater is collected and then pumped up to feed into another line located closer to the surface level where the wastewater can continue to flow by gravity.

The wastewater is ultimately delivered to a treatment plant. Primary treatment at the plant consists of the screening out of larger solids, floating material and other foreign objects and, at some facilities, grit removal. These removed materials are hauled to a landfill. Secondary treatment at the plant consists of biological digestion of the organic and other impurities which is performed by beneficial bacteria in an oxygen enriched environment. Excess and spent bacteria are collected from the bottom of the tanks digested and or dewatered and the resulting solids sent to landfill or to land application as a soil amendment. The treated water, referred to as “effluent”, is then used for irrigation or groundwater recharging or is discharged by permit into adjacent surface waters. The standards to which this wastewater is treated are specified in each treatment facilities operating permit and the wastewater is routinely tested to ensure its continuing compliance therewith. The effluent quality standards are based on Federal and State regulations which are administered and continuing compliance therewith enforced by the State agency to which Federal enforcement powers are delegated.

(ii)

Principal Markets

The principal markets of Liberty Utilities (South) are located in Arizona, Texas and Missouri. The Liberty Utilities (South) region’s facilities are generally 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, recovery of depreciation on plant, together with all reasonable and prudent operating costs, establishes the revenue requirement upon which each utility’s customer rates are determined.

Rate cases ensure that a particular facility appropriately recovers its operating costs and has the opportunity to earn a rate of return on its capital investment as allowed by the regulatory authority under which the facility operates. Liberty Utilities (South) monitors the rates of return on each of its utility investments to determine the appropriate time to file rate cases in order to ensure it earns the regulatory approved rate of return on its investments. A summary of the rates and tariffs for the Wastewater Treatment and Water Distribution business unit is attached in Schedule C.

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(1)

Arizona

The Arizona Corporate Commission (“ACC”) is the primary regulatory agency with jurisdiction over water and wastewater treatment utilities in Arizona. The Arizona Department of Environmental Quality (“ADEQ”) and the Arizona Department of Water Resources in conjunction with various County agencies (county health units) have primary jurisdiction respecting environmental regulation and compliance.

(2)

Texas

The Texas Commission on Environmental Quality (the “TCEQ”) is the primary regulatory agency with jurisdiction over water and wastewater treatment utilities in Texas. The TCEQ also has regulatory jurisdiction respecting environmental compliance, including implementing and enforcing the standards mandated by the federal Clean Water Act and the Safe Drinking Water Act, for all water and wastewater treatment service providers, including those owned and operated by municipalities.

(iii)

Material Facilities

(1)

Gold Canyon Facility

The Gold Canyon Facility is a wastewater treatment facility established in 1984 to serve a number of residential developments and in an unincorporated area of Pinal County referred to as Gold Canyon, approximately 25 miles east of downtown Phoenix, Arizona. The Facility currently serves over 7,300 residential and commercial customers. The Gold Canyon Facility is owned by a wholly-owned subsidiary in the Liberty Utilities (South) region.

The treatment plant utilizes a biological nutrient removal process combined with a sequencing batch reactor with a treatment capacity of 1.9 million gallons per day (“gpd”).

The Facility is a consumptive re-use facility and sells its reclaimed A+ effluent for use as irrigation water on two neighbouring golf courses. Excess reclaimed water is recharged (put back into the ground to replenish underground water) via three recharge ponds. The treatment facility operates under ADEQ – Aquifer Protection Permits and Reuse Permits.

(2)

Litchfield Park Facility

The Litchfield Park Facility is a water distribution and wastewater treatment facility located in the city of Goodyear, 15 miles west of Phoenix, Arizona whose service area includes sections of the cities of Goodyear and Avondale. The Litchfield Park Facility is owned by a wholly-owned subsidiary of the Liberty Utilities (South) region.

The Facility presently serves approximately 16,500 water and 18,500 wastewater customers. The wastewater facility has permitted capacity of 4.1 million gpd. The Facility’s water infrastructure includes a total of twelve active wells, a 6.3 million gallon reservoir and a 4.0 million gallon reservoir which provides water to the current customer base through a single pressure zone. In 2007, in response to high growth in connections, the Facility began preparing

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design plans for expansion of its wastewater treatment facility. However, while permitting such expansion is currently underway, slowed growth has now postponed such construction plans and expansion of capacity is now anticipated to begin in 2012 or 2013, depending on local demand growth occurring. The Facility now operates at approximately 85% of design capacity. The Facility supplies Class “A+” effluent to a number of local golf courses in the area.

Rate Cases

On October 5, 2010, Liberty Utilities (South) received a recommended order (“ROO”) for the Facility proposing an annualized revenue increase of U.S. $8.1 million. At the ACC open meeting held on December 10, 2010 to consider the ROO, the approved revenue increase was reduced to U.S. $7.1 million, with new rates effective December 1, 2010. As part of the Litchfield ROO, the rate increase will be phased in with 50% of the increase being applied in the first 6 months, increasing to 75% for 6 months thereafter, and 100% of the rate increase being realized from month 12 forward. Litchfield is entitled to recover the foregone revenue from the phase in of rates including carrying charges at 7.72%, over an approximate 18 month period, until the Company is made whole for the foregone revenue. The recovery of the foregone revenue became effective December 1, 2011 under Decision 72682.

ii)

Credit Facility

The Facility currently has outstanding indebtedness to the City of Goodyear in the amount of U.S. $11.0 million in respect of which the City of Goodyear has acted as a conduit issuer of a like amount of Industrial Development Authority bonds. The bonds consist of two series, both fully amortizing over a 30 year term. The first series was issued in 1999, has a principal amount as of December 31, 2011 of U.S. $3.6 million bearing interest at rates between 5.85% and 5.95%. The second series was issued in 2001 with a principal amount as of December 31, 2011 of U.S. $7.1 million and bearing interest at rates between 6.3% and 6.75%. As partial security for these bonds, the Facility is required to hold funds in a restricted, interest bearing, investment account. The balance of this account at December 31, 2011 was U.S. $1.1 million.

(3)

Rio Rico Facility

The Rio Rico Facility is a water distribution and wastewater facility located in Santa Cruz County, Arizona approximately 60 miles south of Tucson, Arizona. The Facility serves approximately 6,700 water and 2,200 wastewater connections in the community of Rio Rico, Arizona. The Facility is owned by a wholly-owned subsidiary of Liberty Utilities (South).

The Facility has separate water and wastewater Certificates of Convenience and Necessity and is regulated by the ACC.

(4)

Rate Cases—General

In 2010 and 2011, Liberty Utilities (South) completed the regulatory process with rate cases relating to a number of its facilities. Rate cases seek to ensure that a particular facility has the opportunity to recover its operating costs and earn a fair and reasonable return on its capital investment as allowed by the regulatory authority under which the facility operates. Liberty Utilities (South) monitors current and anticipated operating costs, capital investment and the rates of return in respect of each of its facility investments to determine the appropriate timing of a rate case filing in order to ensure it fully earns a rate of return on its investments.

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The following table sets out some particulars with respect to the status of Liberty Water’s rate cases as at March 30, 2012:


Completed Rate Cases	Date of Rate Increases	Test year	Annual U.S. $ Revenue Increase Granted
Facility

Arizona
Black Mountain	October 2010	June 30, 2008	$0.7 million
Litchfield	December 2010	September 30, 2008	$7.1 million
Rio Rico	February 2011	December 31, 2008	$0.9 million
Bella Vista, Northern and Southern Sunrise	April 2011	March 31, 2009	$0.7 million

Texas
Texas Utilities (Silverleaf – 4 utilities)	October 2009	December 31, 2008	$1.2 million
Tall Timbers	July 2009	December 31, 2008	$0.2 million
Woodmark	January 2010	December 31, 2008	$0.1 million

(h)

Liberty Utilities: Electrical Distribution

(i)

Method of Providing Services and Distribution Methods

Electricity distribution is the final stage in the delivery of electricity to end users. A distribution system’s network carries electricity from the transmission system and delivers it to consumers or other end users. Typically, the network would include medium-voltage (less than 50 kV) power lines, electrical substations and pole-mounted transformers, low-voltage (less than 1 kV) distribution wiring and sometimes electricity meters.

An electric distribution utility sources and distributes electricity it to its customers through a network of buried or overhead lines. The electricity is sourced from power generation facilities which can use various fuels such as water (hydro), natural gas, coal, biomass, wind, nuclear and solar. The electricity is transported from the source(s) of generation at high voltages through transmission lines and is then reduced through transformers to lower voltages at substations. The electricity from the substations is then delivered through distribution lines to the customer where the voltage is again lowered through a transformer for use by the customer.

The fees or rates charged for electricity are comprised of a fixed charge component plus a variable fee based on the cost for generation, transmission and distribution of the electricity. Additional fees are typically chargeable for other services such as establishing a connection, late fee, reconnections, etc.

Liberty Utilities (West)’s facility is subject to state regulation and rates charged by these facilities may be reviewed and altered by the State regulatory authorities from time to time.

(ii)

Principal Markets

The principal market of Liberty Utilities (West) is currently in the State of California. The utility operates under a cost-of-service regulation. The utility uses a test year in the establishment of rates for the utility and pursuant to this method the determination of the rate of return on approved rate base, recovery of depreciation on facilities, together with all reasonable and prudent operating costs, establishes the revenue requirement upon which the utility’s customer rates are determined.

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Rate cases ensure that a particular facility appropriately recovers its operating costs and has the opportunity to earn a rate of return on its capital investment as allowed by the regulatory authority under which the facility operates. Liberty Utilities (West) monitors the rates of return on its utility investment to determine the appropriate time to file a rate case in order to ensure it earns the regulatory approved rate of return on its investments. A summary of the rates and tariffs for Liberty Utilities (West)’s California Utility is attached in Schedule D.

(1)

California

The CPUC regulates electrical utilities in California. The CPUC has jurisdiction with respect to rate, service, accounting procedures, issuance of securities, acquisitions and other matters. These regulatory bodies have the authority to establish the allowed rate of return on approved rate base and also determine which investments are approved for inclusion in the rate base which in both cases can affect the profitability of the division.

The California regulatory regime requires regular general rate case filings. This obligates any regulated utility operating in California to file a rate case every 3 years and allows for the use of a prospective test year in the establishment of rates for the utility. The CPUC also allows the use of annual adjuster mechanisms to account for inflation to labour and other expenses over the three year period of the rate case filing. In addition, a utility’s rates include thresholds for capital expenditures, which once reached, can trigger adjustment mechanisms in between rate cases.

The Energy Cost Adjustment Clause (“ECAC”) allowed in California mitigates the impact of changes in fuel prices and stabilizes earnings by allowing for the recovery of fuel and purchased power costs by updating rates charged on an annual basis. The Post Test Year Adjustment Mechanism (“PTAM”) allows Calpeco to update its rates annually by a cost inflation index. In addition, rates are allowed to be updated to recover the return on investment and associated depreciation of major capital projects.

(iii)

Material Facility

(1)

California Utility

The California Utility provides electric service to the Lake Tahoe basin and surrounding areas. The service territory, centered around a popular tourist destination, has a primarily residential and small commercial customer base spread throughout Alpine, El Dorado, Mono, Nevada, Placer, Plumas and Sierra Counties in Northeastern California. The utility plant is comprised of approximately 94 miles of high voltage distribution lines, 13 substations, and 39 distribution circuits (14.4 kV) serving just over 47,000 customers in the seven County service territories. The customer base is heavily-weighted towards El Dorado and Placer Counties, which counties comprise approximately 89% of total revenues.

Calpeco is owned by CPUV, a 50.001% subsidiary of Liberty Utilities (West).

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On April 29, 2011, pursuant to the Strategic Agreement, Emera and APUC agreed to the general terms by which Emera would sell its 49.999% indirect ownership in the California Utility to Liberty Utilities (West), with closing of such transaction subject to regulatory approval. As part of this transaction, Emera was issued 8.211 subscription receipts pursuant to the Subscription Agreement (Calpeco) and such subscription receipts will be converted into Common Shares in two tranches: 4,790,000 subscription receipts will convert into Common Shares following regulatory approval of the transfer of 100% of the California Utility to Liberty Utilities (expected in mid 2012) and the remaining 3,421,000 subscription receipts will convert into Common Shares following completion of the California Utility’s first rate case, expected to be completed in early 2013.

Customer Base

Calpeco’s customer base is primarily residential with exposure to large commercial accounts limited to under 20% of gross revenues. The existing commercial customers primarily consist of ski resorts, hotels, hospitals, schools and grocery stores with no single customer accounting for more than 3.6% of annual sales volume.

ii)

Rate Case

Calpeco’s most recent rate case was settled in 2009. On February 17, 2012, the California Utility filed a general rate case with the CPUC seeking, among other things, an increase of 10.0%, or $7.5 million in general rates, comprised of a $3.3 million increase in vegetation management costs, $13.0 million increase in distribution rates offset by reductions in commodity costs of $8.8 million. The rate case is for the prospective years of 2013-2015. The California Utility’s proposed procedural schedule contemplates rates to be implemented on January 1, 2013.

iii)

Kings Beach Generation

Calpeco has a local-area emergency backup generation facility at Kings Beach in Placer County, California. The facility consists of six new Caterpillar 3516 Engine diesel generation units with a total nameplate capacity of 12 MW. The units were installed in November 2008 at a cost of U.S. $16.5 million and have an estimated useful life of 30 years. The repowered facility meets all California environmental standards. Any non-preventative maintenance expenditures that may occur during the first five years of operation will be fully covered by the Kings Beach warranty.

In the event of a system outage, the Kings Beach Facility is able to provide back-up generation support to Calpeco’s service territory until baseload power is restored. The facility includes quick-start technology which facilitates this support function. The new units are designed to be online and operating within 60 seconds of being activated. The facility has historically run an average of 200 hours per year.

iv)

Energy Cost Adjustment Clause

ECAC is designed to recoup power supply costs that are caused by the fluctuations in the price of fuel and purchased power. The mechanism consists of a base rate and amortization rate set at the time of the general rate case. The actual power supply costs incurred by the facility are tracked and compared to the base rate power supply costs to ensure the cumulative variance

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does not exceed 5%. In the event that the cumulative variance exceeds 5%, the ECAC allows for an adjustment to approved rates, reducing the commodity risk associated with the purchase of power.

Post Test Year Adjustment Mechanism

In years where Calpeco does not file a general rate case, its rates are updated on January 1st to reflect inflationary increases to its administrative, operations, and maintenance costs. The inflationary adjustment is set by the use of an index, less a presumed efficiency offset.

Calpeco may also file for an annual increase in rates to recover its investment costs in material capital projects. This increase is subject to a materiality threshold.

vi)

PPA

Calpeco has entered into a five year all-purpose PPA with NV Energy to provide its full electric requirements at rates NV Energy’s “system average cost”. The PPA has an effective starting date of January 1, 2011 with a five year renewal option. The PPA obligates NV Energy to use commercially reasonable efforts to supply Calpeco with sufficient renewable power to satisfy the current 20% California Renewables Portfolio Standard requirement for the five-year term of the PPA.

NV Energy’s deliveries under the PPA are structured in a manner which satisfies the CPUC resource adequacy (“RA”) requirements, and designed to enable Calpeco to comply with the associated RA reporting requirements.

vii)

Credit Facility

Calpeco entered into a long term debt private placement in an amount of U.S. $70.0 million on December 29, 2010. The private placement is a senior unsecured private placement with U.S. institutional investors. The notes are fixed rate, interest only, and split into two tranches, U.S. $45 million of ten year 5.19% notes and U.S. $25 million of 5.59% fifteen year notes.

3.3

Revenues for 2011 and 2010

As at March 30, 2012, APUC owned, directly or indirectly, debt, equity and royalty and other interests in 47 renewable generation facilities and 12 thermal generation facilities including those identified in “Other Interests in Energy Related Developments”, one electrical distribution facility and 21 water distribution and wastewater facilities. For the year ended December 31, 2011, APUC derived approximately 49.8% of its revenues from its interests in power generation facilities (74.4% in 2010), 5.9% of its revenues from waste disposal fees (4.9% in 2010), 28.0% of its revenues from electrical distribution and 16.3% of its revenues from its interests in water distribution and wastewater facilities (20.7% in 2010).

3.4

Specialized Skill and Knowledge

The senior executives of APUC have extensive contacts in the independent power industry in Canada and the United States. APCo, as well, has extensive experience and contacts in the independent power industry in Canada and the United States. The energy from hydrology aspect of the business of APCo requires specialized knowledge of hydraulic turbines and their various components. This specialized knowledge is available to APCo in-house.

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The energy from wind aspect of the business of APCo requires specialized knowledge of wind turbines and their various components. This specialized knowledge is available to APCo in-house. On a more general level, the production of energy from all facilities of APCo requires specialized skill and knowledge, and APCo has employed various personnel who have such skill and knowledge.

AES requires specialized knowledge of the ISO-NE and the energy markets in Northern Maine. APCo has contracted the services of four personnel who previously performed these services for the vendor of the contracts acquired by AES.

The electrical distribution service business of Liberty Utilities (West) requires specialized knowledge of electrical utility distribution systems and its various components. Liberty Utilities (West) has contracted the services of 41 employees that previously operated and maintained the California Assets electrical distribution network. In addition Liberty Utilities (West) has also recruited an additional 35 qualified individuals to work in the service territory in various capacities, including Lineman, Customer Service and Financial. In late 2011, Liberty Utilities (West) hired a new regional president with over 30 years of electric utility experience.

In anticipation of the acquisitions of Granite State, Energy North and the Midwest Gas Utilities, in 2012, an experienced utility team has been recruited to support procurement of both natural gas and electricity by the utilities owned by Liberty Utilities. As with the acquisition of the California Assets, Liberty Utilities intends to contract the services of the existing operating personnel necessary to run the these new organizations as part of the completion of these acquisitions.

In addition, Liberty Utilities is adding additional utility trained personnel at its corporate offices to support the expanded portfolio of utility assets.

3.5

Competitive Conditions

APUC competes for projects and acquisitions with individuals, corporations and institutions (both Canadian and foreign) which are seeking or may seek investments similar to those desired by APUC. Availability of investment funds and an increase in interest in these investments may increase competition for them, thereby increasing purchase prices or development costs. Many of these investors have greater financial resources than those of APUC or operate according to more flexible conditions.

Unlike electricity generated by fossil fuels such as natural gas and coal which are subject to potentially dramatic and unexpected price swings due to disruptions in supply or abnormal changes in demand, the supply of hydroelectric power is not subject to commodity fuel price volatility or risk. In addition, the generation of hydroelectric power does not involve significant ongoing capital and operating costs to ensure strict compliance with environmental regulations, which is a significant advantage over power generated by burning waste or utilizing landfill gases.

Deregulation has increased demand for privately generated power from a variety of sources including fossil fuels, waste, wind and water. Taking into account capital costs, wind power is

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generally more expensive than traditional forms of generated power. Fossil fuels are harmful to the environment, and waste burning power generation requires producers to abide by stringent and costly environmental regulations.

With deregulation and opening of competition in the electricity marketplace, there should be an increase in the opportunity for the energy customer to choose the type of generation producing the electricity.

The US Department of Energy (“DEP”) has suggested that in a competitive marketplace, utilities and energy marketers will utilize Green Power pricing to strengthen their image with their customers and build customer loyalty. Further, the DEP has found that most utility customers want their utilities to pursue environmentally benign options for generating electricity and some customers are willing to pay extra to receive power generated by renewable resources. The DEP believes that as deregulation and open competition evolve, the Green Power approach will help offset the relatively higher costs of renewable power compared to less costly gas-fired generation.

Though programs and policies are evolving at all government levels, the trading of greenhouse gas credits created by renewable energy projects is seen as part of the eventual solution.

APUC believes that future opportunities for power generation projects will continue to arise given that many jurisdictions, both in Canada and the United States, continue to increase targets for renewable and other clean power generation projects.

APUC is ideally positioned to take advantage of this demand for increased renewable energy, given that a significant portion of its assets are from renewable sources. It has experience and knowledge in the area. APUC will continue to actively pursue development projects which provide the opportunity to exhibit accretive growth. APUC anticipates its involvement in many future opportunities as initiatives designed to support independent power producers are being supported by virtually every Canadian Province and a significant number of U.S. States.

Liberty Utilities is the holding company for APUC’s utilities businesses. The primary focus of Liberty Utilities is the acquisition of regulated utilities in the water, wastewater, electric transmission and distribution and natural gas distribution businesses. These businesses have geographic monopolies in their service territories and are therefore insulated from competition. Liberty Utilities has developed in-house significant regulatory expertise in order to effectively deal with the state regulators in the various jurisdictions in which it operates.

3.6

Environmental Protection

The APUC Businesses encompass operations which require adherence to environmental standards imposed by regulatory bodies through licences, permits, policies and legislation. Failure to operate the APUC Businesses in strict compliance with these regulatory standards may expose the APUC Businesses to claims, clean-up costs and loss of operating licences and permits.

APUC has an environmental management program including environmental policies and procedures that involve long-term environmental monitoring programs, reporting, government liaison and the development and implementation of emergency action plans as related to environmental matters.

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Environmental protection requirements did not have a significant financial or operational effect on APUC’s capital expenditures, earnings and competitive position for the twelve months ended December 31, 2011. However it is expected that certain regimes will impact APUC, in terms of increased expenditures, and that these will not affect the competitive position of APUC. Moreover, other regimes that provide incentives and credits for generation of renewable energy and for carbon offsets are expected to increase the earnings and benefit the competitive position of APUC.

APUC and its subsidiaries face a number of environmental risks that are normal aspects of operating within the renewable power generation, thermal power generation and utilities business segments which have the potential to become environmental liabilities. Many of these risks are mitigated through the maintenance of adequate insurance which include property, boiler and machinery, environmental and excess liability policies. APUC has assessed the likelihood of these risks becoming a contingent environmental liability as remote; therefore APUC has not recorded any contingent liabilities on its financial statements.

To manage these risks responsibly, APUC has ensured the Environmental and Compliance departments have been established within the different subsidiaries which are responsible for monitoring all of each subsidiary’s operations, ensuring all operating Facilities are in compliance with environmental regulations and preparing regulatory submissions as required. In the aggregate, the departments comprise 12 full time equivalent positions and have an annual budget of approximately $1.6 million, which includes wages, travel and other costs. Facility specific permitting and compliance expenses are direct operating expenses of each facility and are excluded from these expenses.

APUC and its subsidiaries have procedures to prevent and minimize any impact of possible oil spills and soil contamination that meet generally accepted industry practices. APCo’s field personnel perform inspections of oil and chemical storage areas on a minimum of a quarterly basis. Each of APUC’s businesses have 24 hour, 365 day emergency response and spill procedures in place in the event there is an oil or chemical spill.

3.7

Employees

APUC has 15 employees involved in the management of the corporation. APCo currently has 77 employees who are involved in the operation of the renewable energy facilities, 16 employees who provide technical, environmental and safety services to APCo, an additional 43 employees through its subsidiaries who are involved in the operations of the thermal Facilities, 29 employees who are involved in management and 5 employees involved in energy marketing. Labour relations have been stable to date and there has not been any disruption in operations as a result of labour disputes with employees. With the exception of 48 employees at the EFW Facility and 6 employees at the Tinker Facility, the employees of APCo entities are non-unionized.

Liberty Utilities, which provides managerial expertise to Liberty Utilities (South) and Liberty Utilities (West) currently has 28 employees. In addition, Liberty Utilities (South) currently has 136 employees. Liberty Utilities (West) currently employs approximately 77 employees. With the exception of 49 employees at the California Utility, the employees of Liberty Utilities employees are non-unionized

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3.8

Foreign Operations

At the current exchange rate, approximately 55% of expected EBITDA in 2012 and 65% of cash flow from operations is generated in U.S. dollars. APUC has interests in hydroelectric, thermal, electric distribution, water distribution and wastewater treatment facilities located in the United States.

Currency fluctuations may affect the cash flow that APUC will realize from its operations, as certain APUC Businesses sell electricity in the United States and receive proceeds from such sales in US dollars. Such APUC Businesses also incur costs in US dollars.

3.9

Cycles and Seasonality

Based on the type of PPAs in place at all of the facilities in which APUC has an interest, the revenue generated by the facilities is proportional to the amount of electrical energy generated.

Power Generation—Hydrology

The hydroelectric operations of APCo are impacted by seasonal fluctuations. These assets are primarily “run-of-river” and as such fluctuate with the natural water flows. During the winter and summer periods, flows are generally lower while during the spring and fall periods flows are generally higher.

The ability of these assets to generate income may be impacted by changes in water availability or other material hydrologic events within a watercourse. Due to the geographic diversity of the facilities, variability of total revenues will be minimized.

Power Generation—Wind

The strength and consistency of the wind resource will vary from the estimate set out in the initial wind studies that were relied upon to determine the feasibility of any wind farm. If weather patterns change or the historical data proves not to accurately reflect the strength and consistency of the actual wind, the assumptions underlying the financial projections as to the amount of electricity to be generated by the facility may be different and cash could be impacted.

Power Generation—AES

For AES, demand for energy is primarily affected by temperature. Demand for energy during colder months is generally greater than warmer months as the load served by AES is located in a “winter peaking” region.

Liberty Utilities — Water distribution

Demand for water, in the Liberty Utilities (South) region, is affected by weather conditions and temperature. Demand for water during warmer months is generally greater than cooler months due to requirements for irrigation, swimming pools, cooling systems and other outside water use. If there is above normal rainfall the demand for water may decrease adversely affecting revenues.

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Water distribution facilities depend on an adequate supply of water to meet present and future demands of customers. Drought conditions could interfere with sources of water supply used by the utilities and affect their ability to supply water in sufficient quantities to existing and future customers. An interruption in the water supply could have an adverse effect on the results of operations of the utilities. Government restrictions on water usage during drought conditions could also result in decreased demand for water, even if supplies are adequate, which could adversely affect revenues and earnings.

Liberty Utilities — Electricity distribution

For Liberty Utilities, demand for and consumption of electrical energy is primarily affected by weather conditions and to a smaller degree conservation initiatives. Above normal snowfall, with lower temperatures in the Lake Tahoe area brings more ski resort tourists with an increased and consumption of demand for electricity by our customers. Liberty Utilities provides information and programs to its customers to encourage the conservation of energy. In turn, demand for and consumption of electrical energy may be reduced in the case of a mild winter (light snowfall & warmer winter) which could have adverse impacts to revenues. Liberty Utilities provides information and programs to its customers to encourage the conservation of energy.

3.10

Customers

The APUC Businesses derive their revenues principally from the sale of electricity to large utilities. For the twelve months ended December 31, 2011, APUC Businesses’ revenues were derived as follows: Hydro-Québec—approximately 8.4%; Manitoba Hydro—approximately 8.1%; PG&E – approximately 5.3%; electricity sales facility – approximately 28.0%; water distribution and wastewater treatment facilities – approximately 16.3%; waste disposal fees – approximately 5.9% and others—approximately 26.9%.

3.11

Economic Dependence

The largest customer on a percentage basis is Hydro-Québec which totalled 8.4% of gross revenues in the year ended December 31, 2011. This customer maintains an A+ S&P rating and receivables are invoiced monthly and generally collected within 20 days.

Similarly, the second largest customer on a percentage basis is Manitoba Hydro which totalled 8.1% of gross revenues in the year ended December 31, 2011. This customer maintains an AA S&P rating and receivables are invoiced monthly and generally collected within 30 days.

Otherwise, APUC does not believe it is substantially dependant on any single contractual agreement or set of related agreements either for the sale of a major part of its products and services or for the purchase of a major part of its requirements for goods, services or raw materials or any franchise or licence or other agreement to use a patent formula, trade secret, process or trade-name upon which its business depends.

3.12

Social or Environmental Policies

APUC has safety and environmental compliance policies in place. These policies have been communicated with staff, and have been incorporated into APUC’s Safety Mission Statement and Employee manual.

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APUC has an Environmental, Health and Safety Group that reports independently to the President of the appropriate region. This group is responsible for developing environmental and safety policies, developing and delivering environmental and safety training, conducting internal audits of environmental and safety performance, and arranging for third party environmental and safety audits.

4.	RISK FACTORS

The following are certain risk factors relating to the APUC Businesses. The following information is a summary only of certain risk factors and is qualified in its entirety by reference to, and must be read in conjunction with, the detailed information appearing elsewhere in this AIF and the documents incorporated by reference herein.

4.1

Treasury Risk Management

APUC attempts to proactively manage the risk exposures of its subsidiaries in a prudent manner. APUC ensures that each of APCo, Liberty Utilities (South) and Liberty Utilities (West) maintain insurance on all of their facilities. This includes property and casualty, boiler and machinery, and liability insurance. It has also initiated a number of programs and policies including currency and interest rate hedging policies to manage its risk exposures.

There are a number of monetary and financial risk factors relating to the business of APUC and its subsidiaries. Some of these risks include the U.S. versus Canadian dollar exchange rates, energy market prices, credit risk associated with a reliance on key customers, interest rate, liquidity and commodity price risk considerations. The risks discussed below are not intended as a complete list of all exposures that APUC and its subsidiaries may encounter.

(a)

Foreign currency risk

Currency fluctuations may affect the cash flows APUC would realize from its consolidated operations, as certain APUC subsidiary businesses sell electricity or provide utility services in the United States and receive proceeds from such sales in U.S. dollars. Such APUC Businesses also incur costs in U.S. dollars. At the current exchange rate, approximately 55% of EBITDA and 65% of cash flow from operations is generated in U.S. dollars. APUC estimates that, on an unhedged basis, a $0.10 increase in the strength of the U.S. dollar relative to the Canadian dollar would result in increased reported revenue from U.S. operations of approximately $5.4 million ($0.05 per share) on an annual basis.

APUC manages this risk primarily through the use of natural hedges by using U.S. long term debt to finance its U.S. operations. APUC’s policy is not to utilize derivative financial instruments for trading or speculative purposes.

(i)

Liberty Utilities

Liberty Utilities has operations in the U.S., incurs the majority of its operating costs in U.S. currency and generates all of its revenue from utility services in U.S. dollars. Liberty Utilities uses U.S. dollar long term debt as part of its capital structure. As such, Liberty Utilities has minimal foreign currency risk arising from U.S./Canadian currency fluctuations, with the exception of corporate head office charge backs based in Canadian dollars.

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(b)

Market price risk

APCo

The majority of APCo’s electricity generating facilities sell their output pursuant to long term PPAs. However, certain of APCo’s hydroelectric facilities sell energy at current spot market rates. In this regard, each $10.00 per MW-hr change in the market prices in the New England and New York regions would result in a change in revenue of $1.0 million on an annualized basis.

Liberty Utilities (South) and Liberty Utilities (West)

There is no exposure to market price risk as rates charged to customers are stipulated by the respective regulatory bodies.

(c)

Credit/Counterparty risk

APUC and its subsidiaries are subject to credit risk through its trade receivables, net receivable and short term investments. APUC has processes in place to monitor and evaluate this risk on an ongoing basis including background credit checks and security deposits from new customers.

APCo

APCo does not believe this risk to be significant as approximately 82% of Renewable Energy division’s revenue, approximately 48% of APCo Thermal Energy division’s revenue, and over 68% of APCo’s total revenue 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 following chart sets out APCo’s significant counterparties, their credit ratings and percentage of total revenue associated with the counterparty:


Counterparty	Credit Rating *	Approximate Annual Revenues		Percent of Divisional Revenue
Renewable Energy Division
Hydro – Quebec	A+		23,200		26	%
Manitoba Hydro	AA		22,400		25	%
Ontario Electricity Financial Corporation	A+		11,000		12	%
MPS**	BBB+		6,600		7	%
TransAlta Corp – Dickson Dam	BBB		4,000		5	%
Public Service Company of New Hampshire	BBB		3,200		4	%
National Grid	A-		3,000		3	%
Total		$	73,400		82	%

Thermal Energy Division

Regional Municipality of Peel	AAA		16,400		25	%
Pacific Gas and Electric Company	BBB+		14,600		23	%

Total		$	31,000		48	%

*	Ratings by Dunn & Bradstreet or Standard & Poor’s as of February 2012.

**	MPS is a subsidiary of Emera. Emera is rated BBB+.

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Liberty Utilities (South)

Liberty Utilities (South) does not believe this risk to be significant as approximately 75% of revenue are generated from the residential customer base and exposure to large commercial accounts is limited to less than 20% of gross revenues. The residential customer base provides a source of stable cashflows thereby further reducing credit/counterparty risk. Credit risk related to Liberty Utilities (South) accounts receivable balances of U.S. $5.1 million at December 31, 2011 is spread over approximately 76,000 customers, resulting in an average outstanding balance of approximately $70.00 per customer. In addition, no single customer accounts for more than 3.5% of annual sales volume.

Liberty Utilities (West)

Liberty Utilities (West) does not believe this risk to be significant as over 50% of revenue is generated from the residential customer base and exposure to large commercial accounts is limited to less than 20% of gross revenues. The residential customer base provides a source of stable cashflows thereby further reducing credit/counterparty risk. The existing commercial customer base primarily consist of ski resorts, hotels, hospitals, schools and grocery stores, which tend to exhibit characteristics similar to residential accounts (predictable usage patterns, low attrition, etc.). In addition, no single customer accounts for more than 3.6% of annual sales volume.

Credit risk is monitored on an ongoing basis with processes in place to check and evaluate this risk including background credit checks and security deposits from new customers.

(d)

Interest rate risk

APCo

APCo has a number of project specific and other debt facilities that are subject to a variable interest rate. These facilities and the sensitivity to changes in the variable interest rates charged are discussed below:

•

The APCo Facility has no amounts outstanding as at December 31, 2011. As a result, a 100 basis point change in the variable rate charged would not impact interest expense.

•

APCo’s project debt at the St. Leon facility had a balance of $67.8 million as at June 30, 2011. The outstanding balance was repaid during the quarter ended September 30, 2011 using proceeds from the Senior Unsecured Debenture offering. Accordingly there is no further interest rate risk associated with this debt facility.

•

APCo’s project debt at its Sanger cogeneration facility has a balance of U.S. $19.2 million as at December 31, 2011. Assuming the current level of borrowings over an annual basis, a 100 basis point change in the variable rate charged would impact interest expense by U.S. $0.2 million annually.

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Liberty Utilities

As at December 31, 2011, Liberty Utilities has minimal exposure to interest rate risk.

Liberty Utilities (South) has existing project debt at the Litchfield and Bella Vista Facilities which are subject to a fixed rate of interest and thus is not subject to interest rate risk. Liberty Utilities (South) has fixed rate senior unsecured private placement borrowings of U.S. $50 million which is not subject to interest rate risk.

Liberty Utilities (West) has fixed rate senior unsecured private placement borrowings of U.S. $70 million which is not subject to interest rate risk.

Liberty Utilities has a senior debt facility that is subject to a variable interest rate. The facility and the sensitivity to changes in the variable interest rates charged are discussed below:

•

The Liberty Facility has no amounts outstanding as at March 30, 2011. As a result, a 100 basis point change in the variable rate charged would not impact interest expense.

(e)

Liquidity risk

Liquidity risk is the risk that APUC and its subsidiaries will not be able to meet their financial obligations as they become due.

APCo

APCo’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.

During 2011, APCo concluded negotiations with its bank syndicate on the renewal of the APCo Facility. APCo also reduced the total of the APCo Facility to $120 million following the completion of the Senior Unsecured Debenture offering of APCo in July 2011.

As at December 31, 2011, no amounts had been drawn on the APCo Facility. In addition to amounts actually drawn, there were $39.6 million in letters of credit outstanding as at December 31, 2011, resulting in APCo having $80.4 million of committed and available bank facilities.

The cash flow generated from several of APCo’s operating facilities is subordinated to senior project debt. In the event that there was a breach of covenants or obligations with regard to any of these particular loans which was not remedied, the loan could go into default which could result in the lender realizing on its security and APCo losing its investment in such operating facility. APCo actively manages cash availability at its operating facilities to ensure they are adequately funded and minimize the risk of this possibility.

Liberty Utilities

On January 19, 2012, Liberty Utilities concluded negotiations with its bank syndicate on entering into the Liberty Facility, a senior unsecured revolving credit facility. The Liberty Facility provides Liberty Utilities with sufficient liquidity to manage the short term working capital needs of its operations or allow investments in property, plant and equipment.

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As the long term borrowings at Liberty Utilities (South) do not mature until 2020 and beyond and the long term borrowings at Liberty Utilities (West) do not mature until 2020 and 2025, there is no immediate liquidity risk associated with the long term debt.

Senior unsecured notes and project specific debt for Liberty Utilities (South) totals approximately U.S. $64 million. In the event that there is a breach of covenants or obligations with regard to any of the project specific debt which was not later remedied, the project level debt could go into default which could result in the lender realizing on its security and the company losing its investment in the respective operating facility.

Liberty Utilities actively manages both the cash availability in its regions and funds available under the Liberty Facility to ensure its operations are adequately funded and minimize the risk of this possibility.

(f)

Commodity price risk

APCo

APCo’s exposure to commodity prices is primarily limited to exposure to natural gas price risk.

•

APCo’s Sanger facility’s PPA includes provisions which reduce its exposure to natural gas price risk. In this regard, a $1.00 increase in the price of natural gas per mmbtu, based on expected production levels, would result in an increase in net revenue by approximately $0.1 million on an annual basis.

•

APCo’s Windsor Locks facility’s ESA includes provisions which reduce its exposure to natural gas price risk but has exposure to market rate conditions for sales above those to Ahlstrom. In this regard, a $1.00 increase in the price of natural gas per mmbtu, based on expected production levels, would result in an increase in net revenue by approximately $1.4 million on an annual basis.

•

APCo’s BCI facility’s energy services agreement includes provisions which reduce its exposure to natural gas price risk. In this regard, a $1.00 increase in the price of natural gas per mmbtu, based on expected production levels, would result in an increase in net revenue by approximately $0.1 million.

•

AES provides short-term energy requirements to various customers at fixed rates. The energy requirements of these customers are estimated at approximately 130,000 MW-hrs in fiscal 2012. While the Tinker facility is expected to provide the majority of the energy required to service these customers, AES anticipates having to purchase a portion of its energy requirements at the ISO-NE spot rates to supplement self-generated energy. In the event that AES was required to purchase all of its energy requirements at ISO-NE spot rates, each $10.00 change per MW-hr in the market prices in ISO-NE would result in a change in expense of $1.3 million on an annualized basis.

•

This risk is mitigated through the use of short-term financial energy hedge contracts. AES has committed to acquire approximately 70,000 MW-hrs of net energy over the next 12 months at an average rate of approximately U.S. $50 per MW-hr. The mark-to-market value of these forward energy purchase contracts at December 31, 2011 was a net liability of U.S. $1.2 million.

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Liberty Utilities (South)

Liberty Utilities’ water distribution and wastewater collection and treatment utility systems are not subject to any material commodity price risk.

Liberty Utilities (West)

Liberty Utilities (West) provides electric services to the Lake Tahoe basin and surrounding areas at rates approved by the CPUC. Liberty Utilities (West) purchases the energy requirements for its customers from NV Energy at rates reflecting its system average costs. In the event that these rates change, each $10.00 change per MW-hr would result in a change in expense of approximately U.S. $6.5 million on an annualized basis.

The rate structure in California allows for a pass-through of energy costs to rate payers on a dollar for dollar basis, through the ECAC mechanism, which is designed to recoup power supply costs that are caused by the fluctuations in the price of fuel and purchased power. Actual power supply costs incurred by the facility are tracked and compared to the base rate power supply costs to ensure the cumulative variance, including carrying charges, does not exceed 5%. In the event that the cumulative variance exceeds 5%, the ECAC allows for an adjustment to the California Utility’s approved rates (including carrying charges associated therewith), substantially eliminating the commodity risk associated with the purchase of power.

(g)

Risk of Default under Senior Credit Facility

APCo

As security for repayment of the APCo Facility, APCo has, among other things, pledged the shares and other equity interests of certain of its subsidiaries. In addition to any amounts outstanding under the APCo Facility as described above, APCo has posted certain letters of credit totaling $39.6 million as security for obligations of the APCo businesses. The terms of the APCo Facility require APCo to pay a standby charge calculated as one quarter of the current stamping fee on the unused portion of the Senior Credit Facility and maintain certain financial covenants.

If the APCo Facility goes into default, or is not renewed or refinanced when due, there is a risk that the lenders could exercise their security.

Liberty Utilities

The Liberty Facility is unsecured. In addition to any amounts outstanding under the Liberty Facility as described above, Liberty Utilities has posted certain letters of credit totaling $1.2 million as security for obligations of the Liberty businesses. The terms of the Liberty Facility require Liberty Utilities to pay a standby charge calculated as one quarter of the current stamping fee on the unused portion of the Liberty Facility and maintain certain financial covenants.

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Liberty Utilities manages its operational cash flow and its availability under the Liberty Facility to meet such payment obligations. If the Liberty Facility goes into default, or is not renewed or refinanced when due, there is a risk that the lenders could exercise their rights to accelerate Liberty Utilities repayment obligations under the facility.

4.2

Operational Risk Management

APUC attempts to proactively manage its risk exposures in a prudent manner and has initiated a number of programs and policies such as employee health and safety programs and environmental safety programs to manage its risk exposures.

There are a number of risk factors relating to the business of APUC and its subsidiaries. Some of these risks include the dependence upon APUC Businesses, regulatory climate and permits, tax related matters, gross capital requirements, labour relations, reliance on key customers and environmental health and safety considerations. The risks discussed below are not intended as a complete list of all exposures that APUC and its subsidiaries may encounter.

(a)

Mechanical and Operational Risks

APUC is entirely dependent upon the operations and assets of each of APUC’s Businesses. Accordingly, dividends to shareholders are dependent upon the profitability of each of APUC’s Businesses. This profitability could be impacted by equipment failure, the failure of a major customer to fulfill its contractual obligations under its PPA, reductions in average energy prices, a strike or lock-out at a facility and expenses related to claims or clean-up to adhere to environmental and safety standards.

APCo

APCo’s existing long term PPAs minimize the risk of reductions in average energy pricing across its portfolio of facilities.

Liberty Utilities (South)

Liberty Utilities (South)’s profitability could be impacted by equipment failure at a facility and expenses related to claims or clean-up to adhere to environmental and safety standards.

The water distribution networks operate under pressurized conditions within pressure ranges approved by regulators. Should a water distribution network become compromised or damaged, the resulting release of pressure could result in serious injury or death to individuals or damage to other property.

These risks are mitigated through the geographic diversification of water distribution operations, and the use of regular maintenance programs, maintaining adequate insurance and the establishment of reserves for expenses. U.S. governmental authorities have the ability to impose restrictions on water usage during drought conditions. If imposed, this could result in decreased demand for water, even if supplies are adequate, which could adversely affect revenues and earnings.

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Liberty Utilities (West)

Electricity distribution systems are subject to storm events, usually winter storm events, whereby power lines can be brought down by high winds, tree branches, and even complete trees with the attendant risk to individuals and property. In addition, in forested areas during dry weather years, power lines brought down by wind can ignite forest fires which also bring attendant risk to individuals and property.

These forest fire risks are mitigated through the use of regular vegetation management and line maintenance programs, maintaining adequate insurance and the establishment of reserves for expenses.

US governmental authorities have the ability to impose restrictions on electricity usage during periods of power generation disruption and loss of adequate transmission capability. If imposed, this could result in decreased demand for electricity, even if supplies are adequate, which could adversely affect revenues and earnings.

(b)

Asset Retirement Obligations

APUC and its subsidiaries complete periodic reviews of potential asset retirement obligations that may require recognition. As part of this process, APUC and its subsidiaries consider the contractual requirements outlined in their operating permits, leases and other agreements, the probability of the agreements being extended, the likelihood of being required to incur such costs in the event there is an option to require decommissioning in the agreements, the ability to quantify such expense, the timing of incurring the potential expenses as well as business and other factors which may be considered in evaluating if such obligations exist and in estimating the fair value of such obligations. Based on its assessments, APUC’s businesses do not have any significant retirement obligation liabilities and APUC has not recorded any liability in its financial statements.

APCo

Generally, APCo’s hydroelectric facilities are subject to some form of a water use agreement. The terms of these agreements vary by facility as they are agreements made with the local government body that regulates electrical energy generators and can extend over many years. Certain of the agreements contain clauses which allow the regulating body the option to require APCo to decommission the facility upon the expiry or termination of the agreements. Other facilities have no specific obligations other than to maintain the facility in good working order. APCo has options in many of its existing water use agreements to renew or extend the agreements and anticipates being in a position to extend the majority of its agreements and continue to operate its facilities. Based on historical general practice within the regions in which APCo has facilities, APCo has assessed the probability of being required to decommission a facility upon the expiry of a water use agreement to be remote. As such, any potential asset retirement obligation expense has been assessed as insignificant as the obligation would be incurred well into the future and there is a remote likelihood of being required to decommission a facility.

The St. Leon Facility does not own the property on which its turbines are located. In 2004, St. Leon entered into long-term right-of-way agreements with land owners which allowed it to construct and maintain the wind turbines used by the facility on their property. These agreements are for minimum terms of 40 years and, upon expiry or termination, provide the land owners with title to the equipment if it is not decommissioned by APCo at its option. While APCo

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anticipates being in a position to renew or extend the existing PPA in 2025, in the event that APCo is unable to renew or extend the agreement, or identify another purchaser of the energy, APCo may choose to decommission the facility. APCo has assessed there to be a remote likelihood of incurring any cost to decommission the wind farm.

The EFW Facility owns the property on which its facility operates. EFW’s current waste incineration agreement with the Region expires in April 2012. On February 23, 2012, the Peel Regional Council decided to seek competitive proposals from several waste management companies, including APCo. APCo is participating in this proposal process. In addition, the facility is currently permitted to accept commercial and industrial waste from certain other jurisdictions outside of the Region of Peel. APCo is actively sourcing alternative supply options with respect to municipal solid waste from other jurisdictions to ensure a continued supply of waste for the facility.

While APCo anticipates being in a position to renew or extend the existing contract in 2012, in the event that APCo is unable to renew or extend the agreement, APCo may choose to close the facility but has no legal obligation to remove the assets. Under the terms of the contract, the responsibility for removal of the bulk of any hazardous material generated in the operation of the facility remains with EFW’s primary customer. As such, the potential expense to bring the facility in line with current environmental standards in the event it is eventually closed has been assessed as insignificant based on the quantification of costs to remediate the facility, expectation that the existing contract can be extended or renewed and that the potential timing of such an event, although unlikely, would be well in the future.

Liberty Utilities (South)

Liberty Utilities (South)’s water distribution and wastewater collection and treatment utility systems are operated with the assumption that their services will be required in perpetuity and there are no contractual requirements to decommission the entire facility. In order to remain in compliance with the applicable regulatory bodies, Liberty Utilities (South) has regular maintenance programs at each facility to ensure its equipment is properly maintained and replaced on a cyclical basis. These maintenance expenses, expenses associated with replacing aging wastewater treatment facilities and expenses associated with providing new sources of water can generally be included in the facility’s rate base and thus Liberty Utilities (South) is allowed to earn a return on its investment

Liberty Utilities (West)

Liberty Utilities (West) operates its electrical distribution facilities with the assumption that their services will be required in perpetuity and there are no contractual requirements to decommission the entire facility. In order to remain in compliance with the applicable regulatory bodies, Liberty Utilities (West) has regular maintenance programs at each facility to ensure its equipment is properly maintained and replaced on a cyclical basis. These maintenance expenses, expenses associated with replacing aging electricity distribution facilities and expenses associated with providing new sources of electricity can generally be included in the facility’s rate base and thus Liberty Utilities (West) is allowed to earn a return on its investment.

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(c)

Environmental Risks

APCo

The APCo Renewable Energy division faces a number of environmental risks that are normal aspects of operating within its business segment. The primary environmental risks associated with the operation of a hydroelectric facility include possible dam failure which results in upstream or downstream flooding and equipment failure which result in oil or other lubricants being spilled into the waterway. In addition, the operation of a hydroelectric facility may cause the water in the associated waterway to flow faster, or slower, which could result in water flow issues which impact fish population, water quality and potential increases in soil erosion around a dam facility. In order to monitor and mitigate these risks, APCo completes facility inspections at minimum on an annual basis and ensures its facilities are in compliance with the appropriate regulatory requirements for the specific facility. Federal regulators in the U.S. inspect certain hydroelectric facilities on an annual basis and complete an environmental inspection every 3-5 years.

The primary environmental risks associated with the operation of a wind farm include potential harm to the local and migratory bird population, potential harm to the local bat population as well as concerns over noise levels and visual ‘harm’ to the scenic environment around the wind farm. As part of the federal and provincial approval of the St. Leon wind project, certain pre-construction and post construction monitoring studies were required. No significant issues were identified as a result of these studies. In order to monitor and mitigate these risks, APCo completes facility inspections at minimum on an annual basis and ensures its facilities are in compliance with the appropriate regulatory requirements for the specific facility.

The APCo Thermal Energy division faces a number of environmental risks that are normal aspects of operating within its business segment. The primary environmental risks associated with the operation of a cogeneration facility include potential air quality and emissions issues, soil contamination resulting from oil spills and issues around the storage and handling of chemicals used in normal operations. In order to monitor and mitigate these risks, and to remain within the regulatory requirements appropriate for the specific facility, APCo maintains continuous emissions monitoring systems, performs regular stack testing and tests the calibration of monitoring equipment. The primary environmental risks associated with the operation of an incineration facility include potential air quality, odour and emissions issues, soil contamination resulting from oil or other chemical spills and issues around the storage and handling of municipal solid waste. In order to monitor and mitigate these risks, and to remain within the regulatory requirements appropriate for the specific facility, APCo maintains continuous emissions monitoring systems, performs annual stack testing and completes an annual technical evaluation of ash composition.

Liberty Utilities (South)

Liberty Utilities (South)’s water distribution and wastewater collection and treatment utility systems face a number of environmental risks that are normal aspects of operating within its business segment. The primary environmental risks associated with the operation of a wastewater treatment facility include potential air quality and odour management issues, wastewater spills and surface and ground water contamination.

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In order to monitor and mitigate these risks, and to remain within the regulatory requirements appropriate for the specific facility, Liberty Utilities (South) maintains ongoing sampling and testing programs as required in its operational jurisdiction, including annual field investigations by management. It also has a preventative maintenance program to reduce the risk of leaks and other mechanical failures within the wastewater collection system and at the wastewater treatment plants that it operates.

The primary environmental risks associated with the operation of a water distribution facility include risk of groundwater contamination by contaminants such as bacterial, synthetic, organic and inorganic pollutants, consumption and availability of groundwater and ensuring water quality continues to meet and exceed Environmental Protection Agency (“EPA”) and state standards. In order to monitor and mitigate these risks, and to remain within the regulatory requirements appropriate for the specific facility, Liberty Utilities (South) maintains a regular sampling and testing program as required in its operational jurisdiction. It also has a preventative maintenance program to reduce the risk of leaks and other mechanical failures within the water distribution systems that it operates.

Federal drinking water legislation in the United States requires all drinking water systems to meet specific standards. The costs of complying with drinking water standards form part of a facility’s rate case applications.

Liberty Utilities (West)

Liberty Utilities (West) faces environmental risks that are normal aspects of operating within its business segment. The primary environmental risks associated with the operation of an electrical distribution system are related to potential accidental release of mineral oil to the environment from non-operational events and the management of hazardous and universal waste in accordance with the various Federal, State and local environmental laws. Like most other industrial companies, Liberty Utilities (West) generates some hazardous wastes as a result of its electrical distribution operations. Under Federal and State Superfund laws, potential liability for historic contamination of property may be imposed on responsible parties jointly and severally, without fault, even if the activities were lawful when they occurred.

In order to monitor and mitigate these risks and to remain within the regulatory requirements appropriate for these assets, Liberty Utilities (West) promptly investigates all reported accidental releases to take all required remedial actions and manages hazardous waste and universal waste streams in accordance with the applicable Federal and State Legislation

(d)

Cycles and Seasonality Risk

Please see “Description of the business – Cycles and Seasonality” for a detailed description and discussion of this risk.

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(e)

Specific Environmental Risks

(i)

APCo—Greenhouse Gas Initiatives – Power Generation

Several north-eastern U.S. States have formed a coordination group to develop a multi-state green house gas mitigation action plan. This group, the Regional Greenhouse Gas Initiative (“RGGI”), has received backing from states where APCo operates facilities including Connecticut. RGGI drafted a model cap and trade legislation that has been endorsed by all of the states involved in the initiative. The cap and trade program will be implemented to regulate CO₂ emissions from large electrical generation facilities, including the Windsor Locks Facility. The RGGI regulation to implement a greenhouse gas cap and trade program was passed in Connecticut in late August 2008.

The Windsor Locks Facility is the only APCo site that is currently affected by the RGGI regulations. As such APCo will be required to purchase approximately 250,000 tons of CO₂ allowances per year, equivalent to the total annual CO₂ emissions from the Windsor Locks facility for the 2009 to 2012 fiscal years. APCo is entitled to apply for allowances and/or purchase allowances at a base price of $2.00 per tonne from the state of Connecticut. APCo submitted an application on October 31, 2008 for allowances under the available programs. For 2012, APCo has currently estimated the cost of compliance with the RGGI requirements for the Windsor Locks Facility to be between $0.2 and $0.4 million.

RGGI has been in effect in CT since 2009. The first compliance period is from January 2009 to December 2011. For 2012, it is estimated that the Facility will produce 100,000 tons of CO₂, obtain allowances of 55,000 tons through the UTSA, and be required to purchase an additional 55,000 tons to comply with RGGI by the end of December. The current price for RGGI allowances is approximately $1.90/ton.

Seven U.S. States (including Arizona and California) and four Canadian provinces (including Manitoba, Ontario and Quebec) have formed a group called the Western Climate Initiative. Each member state/province is now responsible for developing the draft design of the Regional Cap-and-Trade Program and taking the necessary steps to implement the Program within its jurisdiction. APCo owns and operates the Sanger Facility in California and the EFW Facility in Ontario and holds investments in two others in Ontario which could be impacted by this program.

The EFW Facility submitted the first GHG report under the Ontario Regulation 452/09 in June 2011. In the future, APEFW will also be required to purchase emissions allocations based on emissions reported for the 2010 and/or subsequent periods, depending on the timing for the implementation of the Provincial Cap-and-Trade program, still under final design and approval.

The State of California is the first member of the WCI to implement a Cap-and-Trade program. This program started on January 1, 2012, with the first enforceable compliance obligation beginning with the 2013 GHG emissions. Under this program, independent power generation facilities are not eligible for direct/free credits allocations, as such, the Sanger Facility will have to make provisions to purchase allowances.

On December 15, 2011, Québec announced the adoption of the cap-and-trade system for greenhouse gas emission allowances, which is based on the rules established by the WCI. The first year of implementation of the system will be a transition year. It will begin on January 1,

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2012 and will allow emitters and participants to familiarize themselves with how the system works. Over the course of the year, emitters will also be able to make any adjustments that may be necessary to meet their obligations under the system for capping and reducing GHG emissions, which will come into force on January 1, 2013.

The Carbon Disclosure Project (“CDP”) is an independent non-profit organization that represents institutional investors managing over $57.0 trillion of assets. The CDP is specifically working to encourage companies worldwide to quantify and disclose their greenhouse gas emissions and to outline what actions the companies are taking to address climate change risk, both potential physical impacts and regulatory changes that may result in an effort to address climate change.

APCo submitted a baseline greenhouse gas emissions inventory to the CDP for 2008, 2009 and 2010. The inventory is presently being done for 2011. The emissions data includes both direct emissions from our processes as well as indirect emissions from purchased power. The emissions inventory has been developed based on guidance from the Greenhouse Gas Protocol. This submission will allow comparisons with other firms to be made, and will also be useful as a baseline for addressing climate change regulations. Results are available on the CDP website.

(ii)

APCo—Greenhouse Gas Initiatives – Renewable Energy

As a result of certain legislation passed in Québec (Bill C93), APCo is undertaking technical assessments of its hydroelectric facility dams owned or leased within the Province of Québec.

The province of Ontario is considering enacting new legislation similar to Bill C93. APCo operates four hydroelectric facilities in Ontario. While it is too early to assess the costs of compliance, it is possible that modifications to certain dam structures may be required in order to be compliant with any new regulations should they come into effect. Any capital costs associated with the anticipated modifications are expected to be significantly lower than the expected capital costs related to the Québec Facilities, as there are fewer facilities in Ontario and they are of newer construction.

(iii)

Liberty Utilities (South)

The Litchfield Park Facility operates where groundwater pollutants, namely trichloroethylene (“TCE”) originally employed by a former aerospace manufacturing plant in the nearby City of Goodyear, are progressing toward three of the twelve wells that provide water to the Litchfield service area. The EPA began monitoring TCE in 1981 and has been tracking the gradual underground movement since. In addition to actively participating in EPA regular technical meetings in regards to this monitoring program, the Litchfield Park Facility closely monitors its wells for this groundwater pollutant through the sampling and testing of water from wells that are potentially at risk of contamination.

To date there have not been any detectable levels of TCE in the water from wells used by the Litchfield Park Facility. EPA’s monitoring and control efforts have begun to show reducing concentrations in monitoring wells associated with the northeastern portion of the plume, closest to the Litchfield Park Facility wells. Remedial efforts are currently being intensified in the northwestern portion of the plume in order to ensure full capture of the plume. Additional remedial efforts by the EPA to stop advancement and reduce TCE concentrations are

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continuing. In the event that any wells exceed the EPA permitted TCE level, the Litchfield Facility would undertake the appropriate actions which may include installing appropriate treatment facilities or removing the well from the water distribution system of the utility. In the event of removal of a well, there would remain sufficient production and reservoir capacity within the balance of the water distribution system to adequately service the needs of all of the Litchfield Park Facility’s customers.

In addition, the Litchfield Park Facility has identified alternate sites where replacement wells can be established to replace this potential lost capacity. The cost of establishing a new well is estimated to be between U.S $2.0 million and U.S. $3.5 million depending on the location, depth and other factors. The cost of commissioning a well forms part of the rate base for the utility. Other factors that can impact the cost of a well include, but are not limited to, any requirement to construct wellhead treatment for pollutants, proximity of newly constructed well to water distribution lines, volume of water available at the new site, and acquisition of land and groundwater rights. Liberty Utilities (South) does not believe it is exposed to a material liability and has not recorded a contingent environmental liability on its financial statements.

The Company’s policy is to record estimates of environmental liabilities when they are known or considered probable and the related liability is estimable. There are no known material environmental liabilities as at December 31, 2011.

(iv)

Regimes that Could Impact APUC

APCo

As a result of certain legislation passed in Quebec (Bill C93), APCo is undertaking technical assessments of its hydroelectric facility dams owned or leased within the Province of Quebec. See “Specific Environmental Risks” under “Risk Factors”.

Liberty Utilities (West)

The State of California is considering legislation that will increase the Renewable Portfolio Standards to 33% from the current 20% by the year 2020 which could impact the source of electricity for Calpeco. Any increases in cost of electricity will be passed on the ratepayers through the General Rate Case process.

(v)

Regimes that Could Benefit APUC

The US Federal government has committed to implementing a US carbon reduction strategy, and has included revenue from a federal carbon cap-and-trade program in future budget projections. Similarly, the Canadian federal and provincial governments have indicated increased support for Canadian participation in an integrated North American climate change program.

APUC believes that with its existing portfolio of renewable energy and high efficiency cogeneration Facilities the Power Generation business unit is ideally situated to benefit from an improved competitive position within the North American power sector.

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In addition, the US Federal government is currently debating the implementation of a country-wide Renewable Energy Portfolio Standard. This would increase the market demand for renewable energy and broaden the opportunities for development of renewable energy projects.

In conjunction with the development of cap and trade programs and working to increase the supply of renewable energy, various North American governments are making legislative and regulatory changes to streamline the approvals process for the development of new renewable energy projects.

(f)

Litigation risks and other contingencies

APUC and certain of its subsidiaries are involved in various lawsuits, claims and other legal proceedings that arise from time to time in the ordinary course of business. Any accruals for contingencies related to these items are recorded in the financial statements at the time it is concluded that a material financial loss is likely and the related liability is estimable. Anticipated recoveries under existing insurance policies are recorded when reasonably assured of recovery.

APCo

As discussed below under “Legal Proceedings and Regulatory Actions – Legal Proceedings”, APCo and Algonquin Power Corp. (“APC”), an affiliate of APMI, are involved in civil proceedings and bankruptcy proceedings with Trafalgar. As also discussed in that section, the Attorney General of Québec (“Québec AG”) filed suit claiming that an Algonquin entity had been paying to the federal authority under its water lease. Both proceedings have gone to the appeal stage. On the Trafalgar civil proceedings file, the claims against APCo were dismissed on appeal, and the bankruptcy proceedings continue. On the Côte Ste-Catherine Water Lease Dues file, the appeal was heard in January 2011 and on October 21, 2011 the Québec Court of Appeal allowed the appeal and condemned the APUC subsidiary to pay approximately $5.4 million which includes the amount claimed with interest.

(g)

Tax Related Risks

Although APUC is of the view that all expenses being claimed by APUC are reasonable and that the cost amount of APUC’s depreciable properties have been correctly determined, there can be no assurance that Canada Revenue Agency or the Internal Revenue Service will agree. A successful challenge by either agency regarding the deductibility of such expenses or the correctness of such cost amounts could impact the return to shareholders.

(h)

Tax Risks Associated with the Unit Exchange

There is a possibility that the Canada Revenue Agency could successfully challenge the tax consequences of the Unit Exchange or prior transactions of the Corporation or that legislation could be enacted or amended resulting in different tax consequences from those contemplated in the Unit Exchange for APUC. While APUC is confident in its position, such a challenge or legislation could potentially and materially affect the availability or amount of the tax attributes or other tax accounts of APUC.

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(i)

Obligations to Serve

APCo

APCo is not subject to obligations to serve.

Liberty Utilities

Liberty Utilities facilities may be located within areas of the United States experiencing growth. These utilities may have an obligation to service new residential, commercial and industrial customers. While expansion to serve new customers will likely result in increased future cash flows, it may require significant capital commitments in the immediate term. Accordingly, Liberty Utilities (South) and Liberty Utilities (West) may be required to solicit additional capital or obtain additional borrowings to finance these future construction obligations.

4.3

Regulatory Climate and Permitting Risks

Profitability of APUC Businesses is in part dependant on regulatory climates in the jurisdictions in which it operates.

APCo

In the case of some APCo hydroelectric facilities, water rights are generally owned by governments who reserve the right to control water levels which may affect revenue. The failure to obtain all necessary licences or permits, including renewals thereof or modifications thereto, may adversely affect cash generated from operating activities.

In the United States, FERC issues licences for the construction, operation and maintenance of electrical generating facilities. Facilities are required to be licenced or have valid exemptions from FERC. Failure to maintain such licences, including amendments or modifications thereto, may result in the owner being unable to operate the licenced facility and could adversely affect cash generated from operating activities.

The US Thermal Facilities obtain certain benefits and exemptions because of their Qualifying Facility status (“QF Status”) under PURPA. If any facility were to lose its QF Status, the Facility would no longer be entitled to the exemptions and benefits thereof. Loss of QF Status may also require the Facility to cease selling electricity at the rates set forth in the existing PPAs to the extent they exceed current short run Avoided Costs. Under certain circumstances, loss of QF Status on a retroactive basis could lead to, among other things, claims by an electrical utility’s end user customers for a refund of payments previously made.

Liberty Utilities (South)

Liberty Utilities (South) water distribution and wastewater collection and treatment utility systems are subject to rate setting by State regulatory agencies. The time between the incurrence of costs and the granting of the rates to recover those costs by State regulatory agencies is known as regulatory lag. As a result of regulatory lag, inflationary effects may impact the ability to recover expenses, and profitability could be impacted. Federal, State and local environmental laws and regulations impose substantial compliance requirements on water and wastewater utility operations. Operating costs could be significantly affected in order to comply with new or stricter regulatory requirements.

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Water and wastewater utilities could be subject to condemnation or other methods of taking by government entities under certain conditions. While any taking by government entities would require compensation be paid to Liberty Utilities (South), and while Liberty Utilities (South) believes it would receive fair market value for any assets that are taken, there is no assurance that the value received for assets taken will be in excess of book value.

Liberty Utilities (South) regularly works with these authorities to manage the affairs of the business.

Liberty Utilities (West)

Liberty Utilities (West)’s facilities are subject to rate setting by State regulatory agencies. The time between the incurrence of costs and the granting of the rates to recover those costs by State regulatory agencies is known as regulatory lag. As a result of regulatory lag, inflationary effects may impact the ability to recover expenses, and profitability could be impacted. Federal, State and local environmental laws and regulations impose substantial compliance requirements on electricity distribution utilities. Operating costs could be significantly affected in order to comply with new or stricter regulatory requirements.

Electricity distribution utilities could be subject to condemnation or other methods of taking by government entities under certain conditions. While any taking by government entities would require compensation be paid to Liberty Utilities (West), and while Liberty Utilities (West) believes it would receive fair market value for any assets that are taken, there is no assurance that the value received for assets taken will be in excess of book value.

Liberty Utilities (West) regularly works with these authorities to manage the affairs of the business.

4.4

Dependence upon APUC Businesses

APUC

Liberty Utilities has reduced its dependence on APUC through initiatives such as obtaining a senior unsecured revolving credit facility, the Liberty Facility, issuing long term debt directly on its own and placement of regional presidents to oversee operations. APUC is entirely dependent upon the profitable operations and assets of other APUC Businesses in order to acquire funding for future growth acquisitions. Accordingly, dividends to shareholders are dependent upon the ability of each of the APUC Businesses to pay principal and interest on the notes issued by it and to declare and pay dividends.

APCo

The profitability of APCo may be affected by expiry of the present long-term PPAs to which certain of APCo’s subsidiaries are a party.

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Liberty Utilities

US governmental authorities have the ability to impose restrictions on water and electricity usage during periods of drought or power generation disruption and loss of adequate transmission capability, respectively. If imposed, this could result in decreased demand for water and electricity, even if supplies are adequate, which could adversely affect revenues and earnings.

Water and electricity distribution and wastewater treatment facilities could also be subject to condemnation or other methods of taking by government entities under certain conditions. While any taking by government entities would require compensation be paid to Liberty Utilities (South) and Liberty Utilities (West), and while both Liberty Utilities (South) and Liberty Utilities (West) believe it would receive fair market value for any assets that are taken, there is no assurance that the value received for assets taken will be in excess of book value.

4.5

Safety Considerations

The operation of the facilities require adherence to safety standards imposed by regulatory bodies. Failure to operate the facilities in strict compliance with these regulatory standards may expose the Facilities to claims and administrative sanctions. To mitigate the risk of administrative sanctions and to minimize safety risks to employees and contractors, APUC works continuously with all employees to ensure the development and implementation of a progressive, proactive safety culture within all operations. APUC has multiple active safety committees operating with each operating unit and has a dedicated staff to ensure that the existing safety program is continuously improving.

4.6

Labour Relations

While labour relations have been stable to date and there have not been any disruptions in operations as a result of labour disputes with employees, the maintenance of a productive and efficient labour environment cannot be assured.

APCo

With the exception of the EFW Facility and the Tinker Facility, employees of APCo and their material subcontractors are non-unionized. The EFW Facility is unionized and a new collective bargaining agreement was renegotiated in 2011 for a term of three years, until April 2014. The Tinker Facility is unionized and a new collective bargaining agreement was renegotiated in January 2011 for a term of five years.

Liberty Utilities (South)

All employees of Liberty Utilities (South) and their material subcontractors are non-unionized.

Liberty Utilities (West)

All employees of Liberty Utilities (West) are non-unionized with the exception of 49 employees at the California Utility. The California Utility is unionized and the current collective bargaining agreement was renegotiated in August 2010 for a term of three years, until August 2013.

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4.7

Dependence Upon Key Customers

APCo

The customers that currently purchase APUC’s Facilities are primarily large utilities. See the summaries of the contracts in Schedules A, B, C and D. If, for any reason, such customers were unable to fulfill their contractual obligations under the PPAs, cash flow available to Shareholders would decline.

Liberty Utilities (South)

The customers of Liberty Utilities (South) water and wastewater utilities are primarily residential. Large commercial and industrial customers make up less than 24% of gross revenues, with no single customer making up more than 2.4% of gross revenues. As such, the Company has minimal dependence upon a few key customers.

Liberty Utilities (West)

The customers that currently purchase from Liberty Utilities (West) facilities are primarily residential. Large commercial accounts make up less than 20% of gross revenues, with no single customer making up more than 3.6% of gross revenues. As such, the Company has minimal dependence upon a few key customers.

4.8

Potential Conflicts of Interest

As discussed in “Three Year History – Fiscal 2009” above, an agreement was reached on December 21, 2009 to internalize management. Unitholders had previously been dependent on APMI for the administration of APCo and for management and operation of the Facilities. Since December 21, 2009, management of Algonquin has been conducted by officers of APUC. There may be situations in which conflicts of interest may arise between the Senior Executives of APUC in relation to the interests of APUC. Transactions involving related parties, including the Senior Executives who are principals of APMI, are disclosed in APUC’s annual financial statements and management’s discussion and analysis as at and for the period ended December 31, 2011.

4.9

Construction / Development Risk

Successful development of wind and other energy projects are subject to significant risks and uncertainties including those relating to the ability to obtain financing on acceptable terms, currency fluctuations affecting the cost of major capital components such as turbines, price escalation for construction labour and other construction inputs, construction risk that the project is built with mechanical defects, is not completed on time and is not within budget estimates.

4.10

Acquisitions and Divestitures

Acquisitions of complementary businesses and technologies are a part of APUC’s overall business strategy. In spite of the complementary nature of any businesses or technologies acquired, there is always a risk that services, technologies, key personnel or businesses of acquired companies may not be effectively assimilated into APUC’s business or service offerings. Similarly, divestitures of businesses that are no longer viewed as being strategic to APUC’s continuing operations can be an active part of APUC’s overall business strategy. Divestitures may result in a reduction in total revenues and net income.

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APCo and Liberty Utilities each have a Transition Management Office (“TMO”) that have developed standard project management and governance processes to manage its respective company integrations due to acquisitions. These processes ensure an effective organization of people, resources and time frames for a successful integration of technology, operations, asset management and business processes. The TMO uses a sound governance reporting structure which includes the participation of APCo and Liberty Utilities senior management to ensure that the respective operations and processes are implemented in a timely and efficient manner. The governance process also includes a transparent issue resolution process which is documented and reported throughout APCO and Liberty Utilities.

5.	DIVIDENDS

The total amount of dividends declared for fiscal 2009, 2010 and 2011 were $19.3, $22.8 million and $32.4 million, respectively. The amount of dividends declared for each Common Share of APUC for fiscal 2009, 2010 and 2011 were $0.24, $0.24 and $0.27, respectively.

APUC follows a quarterly dividend schedule, subject to subsequent Board declarations each quarter. Effective August 11, 2011, the Board established a quarterly dividend of $0.07 or $0.28 annually.

The Board has adopted a dividend policy to provide sustainable dividends to shareholders, considering cash flow from operations, financial condition, financial leverage, working capital requirements and investment opportunities. The Board can modify the dividend policy from time to time in its discretion. There are no restrictions on the dividend policy of APUC. The amount of dividends declared and paid is ultimately dependent on a number of factors, including the risk factors noted above. See “Risk Factors”.

5.1

Dividend Reinvestment Plan

Effective October 1, 2011, APUC introduced a shareholder dividend reinvestment plan (the “Reinvestment Plan”) which will be offered to registered holders of Common Share (“Shareholders”) of APUC.

The purpose of the Reinvestment Plan is to enable Shareholders to invest all cash dividends on Common Shares in additional shares of APUC (“Plan Shares”). All such Plan Shares will be, at APUC’s election, either (i) Common Shares purchased on the open market through the facilities of the TSX (“Market Purchase”) or (ii) newly issued Common Shares purchased from APUC (“Treasury Purchase”).

The price at which Plan Shares will be purchased with such cash dividends will be (i) in the case of a Market Purchase, the volume weighted average price paid (excluding brokerage commissions, fees and transaction costs) per Plan Share by the Agent for all Plan Shares purchased in respect of a Dividend Payment Date under the Reinvestment Plan, or (ii) in the case of a Treasury Purchase, the volume weighted average of the trading price for Common Shares on TSX for the five (5) trading days immediately preceding the relevant dividend payment date less a discount, if any, of up to five percent (5%), at APUC’s election. No commissions, service charges or brokerage fees are payable by Shareholders in connection with the Reinvestment Plan.

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As at December 31, 2011, 23.6 million Common Shares had been registered with the Reinvestment Plan.

6.	DESCRIPTION OF CAPITAL STRUCTURE

6.1

Common Shares

APUC may issue an unlimited number of Common Shares. The holders of Common Shares are entitled to dividends, if and when declared; to one vote for each Common Shares at meetings of the holders of Common Shares; and to receive a pro rata share of any remaining property and assets of APUC upon liquidation, dissolution or winding up of APUC. All Common Shares are of the same class and with equal rights and privileges and are not subject to future calls or assessments.

As at December 31, 2011, APUC had 136,122,780 issued and outstanding Common Shares. Following the Series 2A Redemption, APUC had 146,741,635 Common Shares outstanding.

As at December 31, 2011, the 12.0 million subscription receipts issued to Emera pursuant to the Subscription Agreement (National Grid) convertible into 12.0 million Common Shares was outstanding. Delivery of the Common Shares under the subscription receipts is conditional on and is planned to occur simultaneously with the closing of the acquisition of Granite State and EnergyNorth. The proceeds of the subscription receipts are to be utilized to fund a portion of the cost to acquire Granite State and EnergyNorth.

On April 29, 2011, pursuant to the Strategic Agreement, Emera and APUC agreed to the general terms by which Emera would sell its 49.999% direct ownership in the California Utility to APUC, with closing of such transaction subject to, among other things, execution of a definitive purchase agreement and regulatory approval. On September 12, 2011, Emera US Holdings Inc., a subsidiary of Emera through which it holds its interest in the California Utility, entered into a definitive purchase agreement with Liberty Utilities. In connection with this transaction, Emera entered into a subscription agreement dated September 12, 2011 (the “Subscription Agreement (Calpeco)”) with APUC, pursuant to which Emera subscribed for an aggregate of 8,211,000 subscription receipts from APUC price of $4.72 per subscription receipt. Payment for these subscription receipts was satisfied by delivery by Emera of two non-interest bearing promissory notes, one in the amount of $22,608,800 and one in the amount of $16,147,120. The proceeds of this subscription receipt transaction will be used to fund the acquisition by Liberty Utilities of Emera US Holdings Inc.’s interest in the California Utility. 4,790,000 subscription receipts will convert into APUC shares on a one-for-one basis following regulatory approval of the transfer of 100% of the California Utility to Liberty Utilities (expected in early 2012), at which time the $22,608,800 promissory note delivered by Emera to APUC to satisfy the subscription price of the first tranche of subscription receipts become due and payable. The remaining 3,421,000 subscription receipts will convert into APUC shares on a one-for-one basis following completion of the California Utility’s first rate case, expected to be completed in early 2013, at which time the $16,147,120 promissory note delivered by Emera to APUC to satisfy the subscription price of the second tranche of subscription receipts become due and payable. In the event of termination of the Subscription Agreement (Calpeco), the promissory notes will be returned to Emera for cancellation, the subscription receipts will be returned to APUC for cancellation, and the parties will have no further obligations under the Subscription Agreement (Calpeco).

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On April 30, 2011, APUC committed to issuance to Emera of a treasury subscription of subscription receipts convertible into approximately 6.9 million APUC common shares upon closing of the transaction related to the acquisition of an interest in a portfolio of 370MW wind projects. APUC intends to cancel this treasury subscription as it announced on January 27, 2012 that it no longer intended to proceed with the First Wind acquisition.

6.2

Preferred Shares

APUC is authorized to issue an unlimited number of preferred shares, issuable in one or more series, containing terms and conditions as approved by the Board. APUC does not have any issued and outstanding preferred shares.

6.3

Convertible Debentures

APUC currently has outstanding series of convertible debentures:

•

a principal amount of $62,800 Series 3 Debentures.

If all of the principal amount of the Series 3 Debentures were converted by the holders thereof, an additional 14,882,142 Common Shares will be issued pursuant to the terms of the trust indenture (the “Series 3 Trust Indenture”) dated as of December 2, 2009 between APUC and the Debenture Trustee.

(a)

Series 1A Debentures

On October 27, 2009, the Corporation issued, in connection with the Unit Exchange, an aggregate of $66,942,750 principal amount of 7.50% convertible unsecured subordinated debentures due November 33, 2014 (the “Series 1A Debentures”).

On April 7, 2011, APUC provided the holders of its Series 1A Debentures with notice of its intention to redeem for equity, all of the issued and outstanding Series 1A Debentures. Prior to the Redemption Date, a principal amount of $60,339,000 of Series 1A Debentures were converted into 14,788,975 Common Shares. On the Redemption Date, APUC issued and delivered 430,666 Common Shares to the remaining holders of the Series 1A Debentures, representing the number of freely tradeable Common Shares obtained by dividing the aggregate principal amount of Debentures, by 95% of the current market price of Common Shares on the Redemption Date.

As a result of the Redemption there were no Series 1A Debentures outstanding subsequent to the Redemption Date.

(b)

Series 2A Debentures

On October 27, 2009, the Corporation issued, in connection with the Unit Exchange, an aggregate of $59,967,000 principal amount of Series 2A Debentures.

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On January 20, 2012, APUC provided the holders of its Series 2A Debentures notice of its intention to redeem for equity, effective on the Series 2A Redemption Date (February 24, 2012), all of the issued and outstanding Series 2A Debentures. Prior to the Series 2A Redemption Date, $2,916,000 principal amount of Series 2A Debentures were converted by debentureholders into 485,998 Common Shares.

On the Series 2A Redemption Date, APUC issued and delivered 9,836,520 APUC shares to the remaining holders of Series 2A Debentures, representing the number of freely tradeable APUC shares obtained by dividing the aggregate principal amount of Debentures of $57,041,000, by 95% of the current market price of Common Shares on the Series 2A Redemption Date.

As a result, there are no Series 2A Debentures outstanding subsequent to the Series 2A Redemption Date.

(c)

Series 3 Debentures

On December 2, 2009, APUC issued $63,250,000 principal amount of Series 3 Debentures. The Series 3 Debentures bear interest at 7.0% per annum, payable semi-annually in arrears on June 30 and December 30 each year. As at March 15, 2012, there were $62,505,000 principal amount of Series 3 Debentures outstanding.

APUC may, from time to time, without the consent of the holders of the APUC Debentures, issue additional debentures. For a complete description of the APUC Debentures, reference should be made to the Trust Indenture and the Series 3 Trust Indenture, copies of which are available on www.sedar.com.

(i)

Conversion Privilege

The Series 3 Debentures are convertible at the holder’s option into fully paid, non-assessable and freely tradeable Common Shares at any time prior to 5:00 p.m. (Toronto time) on the earlier of June 30, 2017 (the “Series 3 Maturity Date”) and the business day immediately preceding the date specified by APUC for redemption of the Series 3 Debentures, at a conversion price of $4.20 per Common Share (the “Series 3 Conversion Price”) being a ratio of approximately 238.1 Common Shares per $1,000 principal amount of Series 3 Debentures. The Series 3 Debentures bear interest from the date of issue at 7.0% per annum, which will be payable semi-annually on June 30 and December 31 in each year, commencing on June 30, 2010 (each, a “Series 3 Interest Payment Date”).

Interest will be payable based on a 365-day year. At the option of APUC, subject to applicable law, APUC may deliver Common Shares to its agent who shall sell such Common Shares on behalf of APUC in order to raise funds to satisfy all or any part of APUC’s obligations to pay interest on the APUC Debentures, but in any event, the holders of APUC Debentures shall be entitled to receive cash payments equal to the interest otherwise payable on the APUC Debentures.

No adjustment will be made for dividends on Common Shares issuable upon conversion or for interest accrued on APUC Debentures surrendered for conversion; however, holders converting their APUC Debentures are entitled to receive, in addition to the applicable number of Common Shares, accrued and unpaid interest in respect thereof for the period up to the date of conversion from the latest Series 3 Interest Payment Date in the case of the Series 3

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Debentures. Notwithstanding the foregoing, no Series 3 Debentures may be converted on any Series 3 Interest Payment Date and during the five business days preceding June 30 and December 31 in each year as the registers of the Debenture Trustee are closed during such periods.

Subject to the provisions thereof, the Series 3 Trust Indenture provide for the adjustment of the Series 3 Conversion Price in certain events including: (a) the subdivision or consolidation of the outstanding Common Shares; (b) the distribution of Common Shares to holders of Common Shares by way of distribution or otherwise other than an issue of securities to holders of Common Shares who have elected to receive distributions in securities of APUC in lieu of receiving cash distributions paid in the ordinary course; (c) the issuance of options, rights or warrants to holders of Common Shares entitling them to acquire Common Shares or other securities convertible into Common Shares at less than 95% of the then Current Market Price (as defined below under “Payment upon Redemption or Maturity”) of the Common Shares; and (d) the distribution to all holders of Common Shares of any securities or assets (other than cash distributions and equivalent distributions in securities paid in lieu of cash distributions in the ordinary course). There will be no adjustment of the Series 3 Conversion Price, in respect of any event described in (b), (c) or (d) above if, subject to prior regulatory approval, the holders of APUC Debentures are allowed to participate as though they had converted their APUC Debentures prior to the applicable record date or effective date. APUC will not be required to make adjustments the Series 3 Conversion Price, unless the cumulative effect of such adjustments would change the Series 3 Conversion Price, as the case may be, by at least 1%.

In the case of any reclassification or change (other than a change resulting only from consolidation or subdivision) of the Common Shares or in case of any amalgamation, consolidation or merger of APUC with or into any other entity, or in the case of any sale, transfer or other disposition of the properties and assets of APUC as, or substantially as, an entirety to any other entity, the terms of the conversion privilege shall be adjusted so that each APUC Debenture shall, after such reclassification, change, amalgamation, consolidation, merger or sale, be exercisable for the kind and amount of securities or property of APUC, or such continuing, successor or purchaser entity, as the case may be, which the holder thereof would have been entitled to receive as a result of such reclassification, change, amalgamation, consolidation, merger or sale if on the effective date thereof it had been the holder of the number of Common Shares into which APUC Debenture was convertible prior to the effective date of such reclassification, change, amalgamation, consolidation, merger or sale.

No fractional Common Shares will be issued on any conversion of APUC Debentures, but in lieu thereof, APUC shall satisfy such fractional interest by a cash payment equal to the Current Market Price of such fractional interest.

(ii)

Redemption and Purchase

The Series 3 Debentures may not be redeemed by APUC (except in the case of a change of control) on or before December 31, 2012. Thereafter, but prior to December 31, 2014, the Series 3 Debentures may be redeemed at the option of APUC, in whole at any time or in part from time to time, on not more than 60 days’ and not less than 30 days’ prior notice, at a redemption price equal to the principal amount thereof plus accrued and unpaid interest, provided that the weighted average trading price of the Common Shares on the TSX for the 20 consecutive trading days ending five trading days preceding the date on which notice of redemption is given exceeds 125% of the Series 3 Conversion Price.

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On or after December 31, 2014 and prior to the Series 3 Maturity Date, the Series 3 Debentures may be redeemed by APUC, in whole or in part from time to time, on not more than 60 days’ and not less than 30 days’ prior notice, at a redemption price equal to the principal amount thereof plus accrued and unpaid interest.

APUC will have the right to purchase APUC Debentures in the market, by tender or by private contract subject to regulatory requirements; provided, however, that if an Event of Default (as defined below) has occurred and is continuing, APUC will not have the right to purchase APUC Debentures by private contract.

In the case of redemption of less than all of APUC Debentures, APUC Debentures to be redeemed will be selected by the Debenture Trustee on a pro rata basis or in such other manner as the Debenture Trustee deems equitable, subject to the consent of the TSX.

(iii)

Payment upon Redemption or Maturity

On redemption or on the Series 3 Maturity Date, as applicable, APUC will repay the indebtedness represented by APUC Debentures which are to be redeemed or which have matured by paying to the Debenture Trustee in lawful money of Canada an amount equal to the principal amount of the outstanding APUC Debentures, together with accrued and unpaid interest thereon. APUC may, at its option, on not more than 60 days’ and not less than 40 days’ prior notice and subject to any required regulatory approvals, unless an Event of Default (as defined below) has occurred and is continuing, elect to satisfy its obligation to repay, in whole or in part, the principal amount of APUC Debentures which are to be redeemed or which have matured by issuing and delivering freely tradeable Common Shares to the holders of the APUC Debentures. The number of Common Shares to be issued will be determined by dividing the principal amount of the APUC Debentures which are to be redeemed by 95% of the Current Market Price of the Common Shares on the date fixed for redemption or the maturity date, as the case may be. No fractional Common Shares will be issued to holders of APUC Debentures but in lieu thereof APUC shall satisfy such fractional interest by a cash payment equal to the Current Market Price of such fractional interest.

The term “Current Market Price” is defined in the Series 3 Trust Indenture to mean the weighted average trading price of the Common Shares on the TSX for the 20 consecutive trading days ending on the fifth trading day preceding the date of the applicable event.

(iv)

Cancellation

All APUC Debentures converted, redeemed or purchased as aforesaid will be cancelled and may not be reissued or resold.

(v)

Subordination

The payment of the principal of, and interest on, the APUC Debentures is subordinated in right of payment, in the circumstances referred to below and more particularly as set forth in the Trust Indenture, to the prior payment in full of all Senior Indebtedness of APUC. “Senior Indebtedness” of APUC is defined in the Series 3 Trust Indenture as all indebtedness of APUC, other than the APUC Debentures and any other debentures issued under the Series 3Trust Debenture, (whether outstanding as at the date of the Series 3 Trust Indenture or thereafter created, incurred, assumed or guaranteed), and including, for greater certainty, claims of trade

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creditors of APUC, which by the terms of the instrument creating or evidencing the indebtedness, is not expressed to be pari passu with, or subordinate in right of payment to, APUC Debentures.

The Series 3 Trust Indenture provides that in the event of any insolvency or bankruptcy proceedings, or any receivership, liquidation or reorganization in connection with or as a result of an insolvency or bankruptcy proceeding or other similar proceedings relative to APUC, or to its property or assets, or in the event of any proceedings for voluntary liquidation, dissolution or other winding up of APUC, whether or not involving insolvency or bankruptcy, or any marshalling of the assets and liabilities of APUC, all creditors under any Senior Indebtedness will receive payment in full before the holders of APUC Debentures will be entitled to receive any payment or distribution of any kind or character, whether in cash, property or securities, which may be payable or deliverable in any such event in respect of any APUC Debenture or any unpaid interest accrued thereon.

In addition to the foregoing, pursuant to the terms of the Series 3 Trust Indenture, neither the Debenture Trustee for, nor the holders of, APUC Debentures are entitled to demand or otherwise attempt to enforce in any manner, institute proceedings for the collection of, or institute any proceedings against APUC, including, without limitation, by way of any bankruptcy, insolvency or similar proceedings or any proceeding for the appointment of a receiver, liquidator, trustee or other similar official (it being understood and agreed that the Debenture Trustee and/or the holders of APUC Debentures are permitted to take any steps necessary to preserve the claims of the holders of APUC Debentures in any such proceeding and any steps necessary to prevent the extinguishment or other termination of a claim or potential claim as a result of the expiry of a limitation period), or receive any payment or benefit in any manner whatsoever on account of indebtedness represented by APUC Debentures other than as set forth in the Trust Indenture at any time when (i) an event of default (howsoever designated) has occurred and is continuing under the Senior Credit Facility, or (ii) an event of default (howsoever designated) has occurred under any other Senior Indebtedness and is continuing and, in each case, notice of such event of default has been given by or on behalf of the lender or lenders party to such Senior Indebtedness to APUC or an affiliate thereof that is the borrower pursuant to such Senior Indebtedness (the “Senior Indebtedness Postponement Provisions”).

The APUC Debentures are also subordinate to claims of creditors of APUC.

(vi)

Put Right upon a Change of Control

Upon the occurrence of a change of control of APUC involving the acquisition of voting control or direction over 66 2/3% or more of the outstanding Common Shares by any person or group of persons acting jointly or in concert (a “Change of Control”), each holder of APUC Debentures may require APUC to purchase, on the date which is 30 days following the giving of notice of the Change of Control as set out below (the “Put Date”), the whole or any part of such holder’s APUC Debentures at a price equal to 101% of the principal amount thereof (the “Put Price”) plus accrued and unpaid interest to the Put Date.

If 90% or more in the aggregate principal amount of APUC Debentures outstanding on the date of the giving of notice of the Change of Control have been tendered for purchase on the Put Date, APUC will have the right to redeem all the remaining APUC Debentures on such date at the Put Price, together with accrued and unpaid interest to such date. Notice of such redemption must be given to the Debenture Trustee prior to the Put Date and as soon as possible

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thereafter, by the Debenture Trustee to the holders of APUC Debentures not tendered for purchase. The principal on APUC Debentures will be payable in lawful money of Canada or, at the option of APUC and subject to applicable regulatory approval, by payment of Common Shares to satisfy, in whole or in part, its obligation to repay the principal amount of APUC Debentures.

The Series 3 Trust Indenture contains notification provisions to the effect that:

APUC will promptly give written notice to the Debenture Trustee of the occurrence of a Change of Control and the Debenture Trustee will thereafter give to the holders of APUC Debentures a notice of the Change of Control, the repayment right of the holders of APUC Debentures and the right of APUC to redeem un-tendered APUC Debentures under certain circumstances; and

(a)	a holder of APUC Debentures, to exercise the right to require APUC to purchase its APUC Debentures, must deliver to the Debenture Trustee, not less than five business days prior to the Put Date, written notice of the holder’s exercise of such right, together with a duly endorsed form of transfer.

(b)	APUC will comply with the requirements of Canadian securities laws and regulations to the extent such laws and regulations are applicable in connection with the repurchase of APUC Debentures in the event of a Change of Control.

(vii)

Modification

The rights of the holders of the APUC Debentures as well as any other series of debentures that may be issued under the Series 3 Trust Indenture may be modified in accordance with the terms of the Series 3 Trust Indenture. For that purpose, among others, the Trust Indenture contains certain provisions which will make binding on all holders of APUC Debentures resolutions passed at meetings of the holders of APUC Debentures by votes cast thereat by holders of not less than 66 2/3% of the principal amount of the then outstanding APUC Debentures present at the meeting or represented by proxy, or rendered by instruments in writing signed by the holders of not less than 66 2/3% of the principal amount of the then outstanding APUC Debentures. In certain cases, the modification will, instead of or in addition to, require assent by the holders of the required percentage of APUC Debentures of each particularly affected series. Under the Series 3 Trust Indenture, the Debenture Trustee has the right to make certain amendments to the Trust Indenture in its discretion, without the consent of the holders of APUC Debentures.

(viii)

Events of Default

The Series 3 Trust Indenture provides that an event of default (“Event of Default”) in respect of the APUC Debentures will occur if certain events described in the Series 3 Trust Indenture occur, including if any one or more of the following described events has occurred and is continuing with respect to the APUC Debentures: (i) failure for 15 days to pay interest on the APUC Debentures when due; (ii) failure to pay principal or premium, if any, on the APUC Debentures, whether at maturity, upon redemption, by declaration or otherwise; or (iii) certain events of bankruptcy, insolvency or reorganization of APUC under bankruptcy or insolvency laws. Subject to the Senior Indebtedness Postponement Provisions, if an Event of Default has occurred and is continuing, the Debenture Trustee may, in its discretion, and shall, upon the request of holders of not less than 25% in principal amount of the then outstanding APUC Debentures, declare the principal of (and premium, if any) and interest on all outstanding APUC Debentures to be immediately due and payable.

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(ix)

Offers for Debentures

The Series 3 Trust Indenture contains provisions to the effect that if an offer is made for APUC Debentures which is a take-over bid for APUC Debentures within the meaning of the Securities Act (Ontario) and not less than 90% of the APUC Debentures (other than APUC Debentures held at the date of the take-over bid by or on behalf of the offeror or associates or affiliates of the offeror) are taken up and paid for by the offeror, the offeror will be entitled to acquire the APUC Debentures held by holders of APUC Debentures who did not accept the offer on the terms offered by the offeror.

(x)

Priority of Debt

The APUC Debentures are direct obligations of APUC and may not be secured by any mortgage, pledge, hypothec or other charge and are subordinated to other liabilities of APUC. The Trust Indenture does not restrict AUC from incurring additional indebtedness for borrowed money or from mortgaging, pledging or charging its assets to secure any indebtedness.

6.4

Employee Share Purchase Plan

In September 2011, APUC approved an employee share purchase plan (“ESPP”). Eligible employees may have a portion of their earnings withheld to be used to purchase common shares of APUC. APUC will match up to 20% of an employee’s contribution amount for the first $5,000 contributed annually and 10% of an employee’s contribution amount for contributions over $5,000 and up to $10,000 annually. Shares purchased through the APUC match portion vest over a one year period. At APUC’s option, the shares may be (i) issued to participants from treasury at the weighted average share price at time of issue or (ii) acquired on behalf of participants by purchases through the facilities of the TSX by an independent broker. The aggregate number of shares reserved for issuance from treasury by APUC under this plan shall not exceed 2,000,000 shares. As at December 31, 2011, a total of 7,176 shares had been issued under the ESPP. For the year ended December 31, 2011, APUC recorded $9 in compensation expense.

6.5

Directors Deferred Share Units

In June 2011, the Shareholders approved a Deferred Share Unit Plan. Under the plan, non-employee directors of APUC may elect annually to receive all or any portion of their compensation in deferred share units (“DSU”) in lieu of cash compensation. Directors’ fees are paid on a quarterly basis and at the time of each payment of fees, the applicable amount is converted to DSUs. A DSU has a value equal to one APUC common share. Dividends accumulate in the DSU account and are converted to DSUs based on the market value of the shares on that date. DSUs cannot be redeemed until the Director retires, resigns, or otherwise leaves the Board. The DSUs provide for settlement in cash or shares at the election of APUC. As APUC expects to settle these instruments in cash, these DSUs will be accounted for as liability awards. The DSU liabilities will be marked-to-market at the end of each period based on the common share price at the end of the period.

As at December 31, 2011, no DSUs had been issued.

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6.6

Performance Share Units

In October 2011, APUC issued 28,370 performance share units (“PSUs”) to certain members of management other than senior executives as part of APUC’s long-term incentive program. At the end of the three-year performance periods, the number of shares vested can range from 0% to 144% of the number of PSUs granted. Dividends accumulate during vesting period and are converted to PSUs based on the market value of the shares on that date. None of these PSUs have voting rights. Any PSUs not vested at the end of a performance period will expire. The PSUs provide for settlement in cash or shares at the election of APUC. As APUC does not expect to settle these instruments in cash, these PSUs will be accounted for as equity awards. Compensation expense associated with PSUs is recognized rateably over the performance period based on APUC’s estimated achievement of the established metrics. Compensation expense for awards with performance conditions will only be recognized for those awards for which it is probable that the performance conditions will be achieved and which are expected to vest. The compensation expense will be estimated based upon an assessment of the probability that the performance metrics will be achieved and anticipated vesting percentage.

6.7

Shareholders’ Rights Plan

The Rights Plan is designed to ensure the fair treatment of shareholders in any transaction involving a potential change of control of APUC and will provide the board of directors of the Corporation and shareholders with adequate time to evaluate any unsolicited take-over bid and, if appropriate, to seek out alternatives to maximize shareholder value. The Rights Plan was approved by shareholders at the Meeting until the termination of the annual general meeting of the Shareholders of APUC in 2013 or its termination under the terms of the of Rights Plan. The Rights Plan is similar to rights plans adopted by many other Canadian corporations. Until the occurrence of certain specific events, the rights will trade with the Common Shares of APUC and be represented by certificates representing the Common Shares. The rights become exercisable only when a person, including any party related to it or acting jointly with it, acquires or announces its intention to acquire twenty percent or more of the outstanding Common Shares without complying with the Permitted Bid provisions of the Plan. Should a non-Permitted Bid be launched, each right would entitle each holder of shares (other than the acquiring person and persons related to it or acting jointly with it) to purchase additional Common Shares at a fifty percent discount to the market price at the time.

It is not the intention of the Rights Plan to prevent take-over bids but to ensure their proper evaluation by the market. Under the Rights Plan, a Permitted Bid is a bid made to all shareholders for all of their Common Shares on identical terms and conditions that is open for no less than 60 days. If at the end of 60 days at least fifty percent of the outstanding Common Shares, other than those owned by the offeror and certain related parties, have been tendered and not withdrawn, the offeror may take up and pay for the Common Shares but must extend the bid for a further ten days to allow all other shareholders to tender.

6.8

Stock Option Plan

The Corporation implemented a stock option plan (the “Stock Option Plan”) in 2010. The purpose of the Stock Option Plan is to attract, retain and motivate persons as key service providers to the Corporation and its affiliates and to advance the interests of the Corporation by providing such persons with the opportunity, through share options, to acquire a proprietary interest in the Corporation.

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The Stock Option Plan authorizes the Board to issue stock options (“Options”) to directors, officers or employees of the Corporation or any affiliate (an “Eligible Individual”), a corporation controlled by an Eligible Individual or any person/company, partnership, trust or corporation engaged to provide management or consulting services for the Corporation or any affiliate (“Eligible Persons”).

The aggregate number of Common Shares that may be reserved for issuance under the Stock Option Plan must not exceed 10% of the number of Common Shares outstanding at the time the Options are granted. For greater clarity, the Stock Option Plan is “reloading” in the sense that, to the extent that Options expire or are terminated, cancelled or exercised, the Corporation may make a further grant of Options in replacement for such expired, terminated, cancelled or exercised Options, provided that the 10% maximum is not exceeded. No fractional Common Shares may be purchased or issued under the Stock Option Plan.

In addition, under the Stock Option Plan:

•

subject to the terms of the Stock Option Plan, the number of Common Shares subject to each Option, the exercise price of each Option, the expiration date of each Option, the extent to which each Option vests and is exercisable from time to time during the term of the Option and other terms and conditions relating to each Option will be determined by the Board from time to time;

•

subject to any adjustments pursuant to the provisions of the Stock Option Plan, the exercise price of any Option shall in no circumstances be lower than the Market Price (as defined below) of the Common Shares on the date on which the Board approves the grant of the Option;

•

Options will be personal to the grantee and will be non-transferable and non-assignable, except in certain limited circumstances;

•

the maximum number of Common Shares which may be reserved for issuance to insiders under the Stock Option Plan, together with the number of Common Shares reserved for issuance to insiders under any other securities based compensation arrangement, shall be 10% of the Common Shares outstanding at the time of the grant;

•

the maximum number of Common Shares which may be issued to insiders under the Stock Option Plan and all other security based compensation arrangements within a one year period shall be 10% of the Common Shares outstanding at the time of the issuance;

•

non-employee director participation in the Stock Option Plan is limited to the lesser of (i) a reserve of 1% of the Common Shares outstanding for non-employee directors as a group and (ii) an annual equity award value of $100,000 per director;

•

if the expiration date for an Option occurs during a Blackout Period (as defined below) or within 10 business days after the expiry date of a Blackout Period applicable to a person granted Options (an “Optionee”), then the expiration date for that option will be extended to the 10th business day after the expiry date of the Blackout Period. A “Blackout Period” is a period of time of time during which the Optionee cannot exercise an Option, or sell Common Shares issuable pursuant to the exercise of Options, due to applicable policies of the Corporation in respect of insider trading); and

•

except in certain circumstances, the term of an Option shall not exceed ten (10) years from the date of the grant of the Option.

Under the Stock Option Plan, “Market Price” of the Common Shares is defined as the volume weighted average trading price of such Common Shares on the TSX (or, if such Common

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Shares are not then listed and posted for trading on the TSX, on such stock exchange in Canada on which such Common Shares are listed and posted for trading as may be selected for such purpose by the Board) for the five (5) consecutive trading days immediately preceding such date, provided that in the event that such Common Shares did not trade on any of such trading days, the Market Price will be the average of the bid and ask prices in respect of such Common Shares at the close of trading on all of such trading days and provided that in the event that such Common Shares are not listed and posted for trading on any stock exchange, the Market Price will be the fair market value of such Common Shares as determined by the Board in its sole discretion.

The Stock Option Plan provides that, except as set out in the Stock Option Plan or any resolution passed at any time by the Board or the terms of any option agreement or employment agreement with respect to any Option or an Optionee, an Option and all rights to purchase Common Shares pursuant thereto shall expire and terminate immediately upon the Optionee who holds such Option ceasing to be an Eligible Person.

Where an Optionee (other than a service provider) resigns from the Corporation or is terminated by the Corporation for cause, the Optionee’s unvested options shall immediately be forfeited and the Optionee’s vested options may be exercised for a period of 30 days after the date of resignation or termination.

Where an Optionee (other than a service provider) retires from the Corporation or ceases to serve the Corporation or an affiliate as a director, officer or employee for any reason other than a termination by the Corporation for cause, the Optionee’s unvested options may be exercised within 90 days after such retirement or termination. The Board may in such circumstances accelerate the vesting of unvested Options then held by the Optionee at the Board’s discretion.

In the event that an Optionee, other than a service provider, has suffered a permanent disability, Options previously granted to such Optionee shall continue to vest and be exercisable in accordance with the terms of the grant and the provisions of the Stock Option Plan, but no additional grants of Options may be made to the Optionee.

If an Optionee, other than a service provider, dies, all unexercised Options held by such Optionee at the time of death immediately vest, and such Optionee’s personal representatives or heirs may exercise all Options within one year after the date of such death.

All Options granted to service providers shall terminate in accordance with the terms, conditions and provisions of the associated option agreement between the Corporation and such service providers, provided that such termination shall occur no later than the earlier of (i) the original expiry date of the term of the Option and (ii) one year following the date of termination of the engagement of the service provider.

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Options may be exercised in accordance with the specific terms of their grant and by the Optionee delivering the exercise price to the Corporation for all of the Options exercised. The Optionee may also surrender Options and receive in exchange for each such Option, the amount by which the Market Price of the Common Shares exceeds the exercise price of the Option (the “In-the-Money Amount”). If the Optionee elects to surrender any Options in exchange for the In-the-Money Amount, the Corporation will determine whether to pay such amount in cash or in Common Shares representing the equivalent of the In-the-Money Amount based on the Market Price of the Common Shares at the date of exercise, in each case net of an amount equal to any withholding taxes.

In the event that the Common Shares are at any time changed or affected as a result of the declaration of a stock dividend, a Share subdivision or consolidation, the number of Common Shares reserved for Option shall be adjusted accordingly by the Board to such extent as it deems proper in its discretion.

If, after the grant of an Option and prior to its expiry:

(i)	the Common Shares are reclassified, reorganized or otherwise changed (a “Share Reorganization”), otherwise than as specified in the immediately preceding paragraph, or

(ii)

subject to the Corporation’s right to allow the exercise of vested and unvested Options following the occurrence of certain transactions, the Corporation shall consolidate, merge or amalgamate with or into another corporation (a “Merger”, with the resulting corporation being the “Successor Corporation”),

the Optionee will receive, upon the subsequent exercise of his or her Options in accordance with the Stock Option Plan, the number of Common Shares or securities of the appropriate class of the Corporation or Successor Corporation, as the case may be, that the Optionee would have received if on the record date of such Share Reorganization or Merger the Optionee were the registered holder of the number of Common Shares to which the Optionee was prior thereto entitled to receive on exercise of his or her Options.

The Board may amend, suspend or discontinue the Stock Option Plan or amend Options granted under the Stock Option Plan at any time without shareholder approval; provided, however, that:

(a)	approval by a majority of the votes cast by shareholders present and voting in person or by proxy at a meeting of shareholders of the Corporation shall be obtained for any:

(i)

amendment for which, under the requirements of the TSX or any applicable law, shareholder approval is required;

(ii)

reduction of the Option price, or cancellation and reissuance of Options or other entitlements, of non-insider Options granted under the Stock Option Plan;

(iii)

extension of the term of Options beyond the original expiry date of non-insider Options;

(iv)

change in Eligible Persons that may permit an increase to the limit imposed on non-employee director participation set out in the Stock Option Plan;

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(v)

allowance of Options granted under the Stock Option Plan to be transferable or assignable other than for estate settlement purposes; or

(vi)

amendment to the Stock Option Plan’s amendment provisions; and

(b)	the consent of the Optionee is obtained for any amendment which alters or impairs any Option previously granted to an Optionee under the Stock Option Plan.

Notwithstanding the other provisions of the Stock Option Plan, if:

(a)	the Corporation proposes to amalgamate, merge or consolidate with any other corporation (other than a wholly-owned affiliate) or to liquidate, dissolve or wind-up;

(b)	an offer to purchase or repurchase all of the Common Shares shall be made to all holders of Common Shares which offer has been approved or accepted by the Board; or

(c)	the Corporation proposes the sale of all or substantially all of the assets of the Corporation as an entirety, or substantially as an entirety, so that the Corporation shall cease to operate any active business,

then, the Corporation will have the right, upon written notice thereof to Optionees, to permit the exercise of all such Options, whether or not vested, within the 20 day period next following the date of such notice and to determine that upon the expiration of such 20 day period, all rights of the Optionee to such Options or to exercise same (to the extent not theretofore exercised) shall ipso facto terminate and cease to have further force or effect whatsoever.

As of March 30, 2012 the number of outstanding options is 3,681,710, which is 2.5% of the total outstanding Common Shares of the Corporation. The number of Common Shares that have been issued pursuant to the plan is nil.

7.	MARKET FOR SECURITIES

7.1

Trading Price and Volume

(a)

Common Shares

The Corporation’s Common Shares are listed and posted for trading on the TSX under the symbol “AQN”. The following table sets forth the high and low closing prices and the aggregate volume of trading of the Common Shares and trust units for the periods indicated (as quoted by the TSX).


2011	High ($)		Low ($)		Volume (000’s)
January		5.03		4.73		6,167
February		5.13		4.81		5,018
March		5.42		4.85		5,654
April		5.63		4.98		9,523
May		5.87		5.23		7,487
June		5.86		5.44		5,755
July		5.99		5.59		2,563
August		5.83		4.90		6,599
September		5.85		5.40		4,362
October		5.88		5.47		5,872
November		6.13		5.52		9,249
December		6.59		5.96		22,740

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(b)

Series 1A Debentures

Series IA Debentures were listed and posted for trading on the TSX under the symbol “AQN.DB”. On the Redemption Date, the remaining Series 1A Debentures were redeemed. As a result, there are no Series 1A Debentures outstanding subsequent to the Redemption Date.

The following table sets forth the high and low closing prices and the aggregate volume of trading of the Series 1A Debentures for the periods indicated (as quoted by the TSX).


2011	High ($)		Low ($)		Volume (000’s)
January		122.79		118.00		58
February		125.50		119.62		16
March		130.70		120.89		29
April		137.52		121.00		191
May 1 -16, 2011		134.65		125.50		33

(c)

Series 2A Debentures

Series 2A Debentures were listed and posted for trading on the TSX under the symbol “AQN.DB.A”. On the Series 2A Redemption Date, the remaining Series 2A Debentures were redeemed. As a result, there are no Series 2A Debentures outstanding subsequent to the Series 2A Redemption Date.

The following table sets forth the high and low closing prices and the aggregate volume of trading of the Series 2A Debentures for the periods indicated (as quoted by the TSX).


2011	High ($)		Low ($)		Volume (000’s)
January		107.00		106.00		1
February		107.50		106.31		2
March		109.00		106.70		2
April		107.50		107.00		4
May		107.50		106.00		4
June		108.74		106.76		8
July		108.00		106.50		5
August		107.00		102.00		7
September		106.50		104.00		9
October		106.00		103.00		8
November		107.80		104.51		6
December		110.00		104.25		48
January		108.60		102.50		11,000110
February 1 - 24		107.00		102.15		17,006176

(d)

Series 3 Debentures

Series 3 Debentures are listed and posted for trading on the TSX under the symbol “AQN.DB.B”. The following table sets forth the high and low closing prices and the aggregate volume of trading of the Series 3 Debentures for the periods indicated (as quoted by the TSX).

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2011	High ($)		Low ($)		Volume (000’s)
January		121.00		115.33		44
February		125.00		118.05		19
March		130.67		120.00		25
April		135.00		121.02		15
May		139.58		127.11		26
June		140.00		131.53		21
July		144.00		135.01		5
August		140.00		120.00		53
September		139.10		131.00		15
October		140.00		133.00		24
November		145.00		133.40		15
December		155.34		143.17		34

7.2

Prior Sales

During the year ended December 31, 2010, 1,160,204 options were granted to senior executives of APUC which allow for the purchase of common shares at a price of $4.05. One-third of the options vest on each of January 1, 2011, 2012 and 2013.

During the year ended December 31, 2011, the Board approved the following grant of options:

•

On March 22, 2011, 892,107 options were granted to senior executives of APUC which allow for the purchase of common shares at a price of $5.23;

•

On June 21, 2011, 171,642 options were granted to a senior executive of APCo which allow for the purchase of common shares at a price of $5.64;

•

On July 28, 2011, 90,909 options were granted to a senior executive of APUC which allow for the purchase of common shares at a price of $5.74; and

•

On September 13, 2011, 172,242 options were granted to a senior executive of Liberty Utilities which allow for the purchase of common shares at a price of $5.68.

On March 14, 2012, 1,194,606 options were granted to senior executives of APUC and senior managers which allow for the purchase of common shares at a price of $6.22.

All options are issued at the market price of the underlying common share at the date of grant. In each case, one-third of the options vest on each of January 1, 2012, 2013 and 2014. Options may be exercised up to eight years following the date of grant.

During the year ended December 31, 2011, no options were exercised. As at December 31, 2011, APUC had 2,487,104 options issued and outstanding. As at December 31, 2011, 386,735 options are exercisable. No share options were exercised in 2011 or 2010.


	Number of shares		Weighted average exercise price		Weighted average remaining contractual term
Balance at January 1, 2011		1,160,204	$	4.05		7.62
Granted		1,326,900		5.38		8.00

Balance at December 31, 2011		2,487,104	$	4.76		6.96

Exercisable at December 31, 2011		386,735	$	4.05		6.62

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7.3

Escrowed Securities and Securities Subject to Contractual Restrictions on Transfer

The following securities of the Corporation are being held in escrow or subject to contractual restrictions on transfer as of the date of this AIF:


Description	Number of Securities held in escrow			Percentage of class
Subscription receipts		27,101,131	⁽¹⁾		100	%
Common Shares		8,523,000	⁽²⁾		5.8	%

(1)

Consists of the 12,000,000 subscription receipts issued pursuant to the Subscription Agreement (National Grid); 6,890,131 subscription receipts issued to Emera on July 5, 2011; and subscription receipts issued pursuant to the Subscription Agreement (Calpeco). These subscription receipts are being held by CIBC Mellon Trust Company as escrow agent. The Subscription Agreement (National Grid) will be released from escrow when the EnergyNorth and Granite State acquisitions are completed and the subscription receipts convert into APUC Common Shares (or if such acquisitions are terminated and the subscription receipts are cancelled). The 6,890,131 subscription receipts relate to an acquisition that the Corporation has determined not to proceed with, and such subscription receipts will be cancelled and released from escrow when a termination agreement relating to the subscription receipts is executed. The 8,211,000 subscription receipts will be released from escrow either (i) in two tranches, where 4,790,000 will be released when the Corporation completes the acquisition of Emera’s interest in the California Utility and the subscription receipts convert into APUC Common Shares and 3,421,000 will be released following the completion of the California Utility’s first rate case or (ii) if the acquisition of the California Utility is terminated.

(2)	These shares were issued to Emera upon conversion of subscription receipts effective January 1, 2011. The shares are subject to restrictions on transfer until January 1, 2014, as set out in the Subscription Agreement dated April 22, 2009.

8.	DIRECTORS AND OFFICERS

8.1

Name, Occupation and Security Holdings

The following table sets forth certain information with respect to the directors and executive officers of APUC, and information on their history with APCo. Unless otherwise indicated, the individuals have been in their principal occupations for more than five years.

Name and Place of

Residence

Principal Occupation

Served as

Director or Officer

of APUC from

Number of
Common
Shares

CHRISTOPHER J. BALL

Toronto, Ontario, Canada

Age: 61

Mr. Ball is currently the Executive Vice President of Corpfinance International Limited, an investment banking boutique firm. From 1982 to 1988, Mr. Ball was Vice President at Standard Chartered Bank of Canada with responsibilities for the Canadian branch operation. Prior to that, Mr. Ball held various managerial positions with the Canadian Imperial Bank of Commerce. He is also a Director of the Independent Power Association of British Columbia.

Director of APUC since October 27, 2009.

Trustee of APCo since October 22, 2002

24,200

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Name and Place of Residence	Principal Occupation	Served as Director or Officer of APUC from	Number of Common Shares
KENNETH MOORE Toronto, Ontario, Canada Age: 53	Mr. Moore is currently the Managing Partner of NewPoint Capital Partners Inc., an investment banking firm. From 1993 to 1997, Mr. Moore was a senior partner at Crosbie & Co., another Toronto mid-market investment banking firm. Prior to investment banking, he was a Vice-President at Barclays Bank where he was responsible for a number of leveraged acquisitions and restructurings. Mr. Moore holds a Chartered Financial Analyst designation and has completed the Chartered Director program of the Directors College (McMaster University and the Conference Board) and has the certification of Chartered Director (“Ch. Dir.”).	Director of APUC since October 27, 2009. Trustee of APCo since December 18, 1998	18,000
GEORGE L. STEEVES Aurora, Ontario, Canada Age: 62	Mr. Steeves is the Principal of True North Energy, an energy consulting firm. From January 2001 to April 2002, Mr. Steeves was a division manager of Earthtech Canada Inc. Prior to January 2001, he was the president of Cumming Cockburn Limited, an engineering firm, and has extensive financial expertise in acting as a Chairman, director and/or audit committee member of public and private companies, including APCo, Borealis Hydroelectric Holdings Inc. and KMS Power Income Fund. Mr. Steeves has completed the Chartered Director program of the Directors College (McMaster University and the Conference Board) and has the certification of Ch. Dir. He received a Bachelor and Masters of Engineering from Carleton University and holds the Professional Engineering designation in Ontario and British Columbia.	Director of APUC since October 27, 2009. Trustee of APCo since September 8, 1997	17,241⁽¹⁾
CHRISTOPHER HUSKILSON Wellington, Nova Scotia, Canada Age: 54	Mr. Huskilson is currently the President and Chief Executive Officer of Emera Incorporated, a North American energy and services company. Since 1980, Mr. Huskilson has held a number of positions within Nova Scotia Power Inc, and is currently a director of Emera Incorporated, Nova Scotia Power Inc. and chairman of Bangor Hydro-Electric Company.	Director of APUC since October 27, 2009. Trustee of APCo since July 27, 2009	nil⁽²⁾
DAVID BRONICHESKI Oakville, Ontario, Canada Age: 52	Mr. Bronicheski is the Chief Financial Officer (“CFO”) of APUC. He has held various senior management positions including Executive Vice President and CFO of a publicly traded income trust providing local telephone, cable television and internet service. He was also CFO for a large public hospital in Ontario. Mr. Bronicheski holds a Bachelor of Arts in economics (cum laude), a Bachelor of Commerce degree and an MBA. He is also a Chartered Accountant.	Officer of APUC since October 27, 2009. Officer of APCo since September 17 2007^{(3) (4)}	40,000⁽⁷⁾⁽⁸⁾⁽⁹⁾

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Name and Place of Residence	Principal Occupation	Served as Director or Officer of APUC from	Number of Common Shares
CHRISTOPHER K. JARRATT^{(5) (6)} Oakville, Ontario, Canada Age: 53	Mr. Jarratt is currently the Vice Chairman of APUC. Mr. Jarratt is a founder and principal of Algonquin Power Corporation Inc. (“APC”), a private independent power developer formed in 1988. Mr. Jarratt has completed the Chartered Director program of the Directors College (McMaster University and the Conference Board) and has the certification of Ch. Dir.. He holds a Professional Engineer designation and an Honours Bachelor of Science degree from the University of Guelph	Director of APUC since June 23, 2010.	407,444^(7)(8)(9)
IAN E. ROBERTSON^{(5) (6)} Oakville, Ontario, Canada Age: 52	Mr. Robertson is currently the President and Chief Executive Officer of APUC. Mr. Robertson is a founder and principal of APC. Mr. Robertson has completed the Chartered Director program of the Directors College (McMaster University and the Conference Board) and has the certification of Ch. Dir.. He received a Bachelor of Engineering from the University of Waterloo and holds the Professional Engineering designation along with a Master of Business Administration degree from York University and a Chartered Financial Analyst designation	Director of APUC since June 23, 2010.	423,546^(7)(8)(9)
LINDA BEAIRSTO Ontario,Canada Age: 51	Ms. Beairsto has been general counsel for APUC since June 2011 and also holds the role of Corporate Secretary of APUC. Prior to her position with APUC, she was in-house legal counsel for a large Bay Street law firm and several multinational companies. Ms. Beairsto attended law at the University of New Brunswick and was called to the bar in Ontario in1990.	Officer of APUC since June 6, 2011	Nil^{(9) (10)}

Notes:

(1)	Mr. Steeves’ directly owns 14,327 Common Shares and Mr. Steeves’ spouse owns 2,914 Common Shares. Mr. Steeves exercises control and direction over the Common Shares owned by his spouse.

(2)	Mr. Huskilson does not own any Common Shares.

(3)	Mr. Bronicheski became an officer of APCo on September 17, 2007.

(4)	Prior to becoming an officer of APCo in September 2007, Mr. Bronicheski was the CFO of Amtelecom Income Fund from July 2003 to July 2007.

(5)	Messrs. Jarratt and Robertson, together with others, collectively own all of the issued and outstanding shares of APMI.

(6)	As consideration for payment of APUC’s acquisition of APMI’s interest in the management agreement, Mr. Robertson and Mr. Jarratt following shareholder approval at the Meeting each received 295,045 Common Shares.

(7)

Messrs. Jarratt, Robertson, and Bronicheski hold 436,224, 494,388, and 229,593 stock options respectively, granted on August 12, 2010. The stock options allow for the purchase of Common Shares at a price of $4.05. One-third of the stock options vests on each of January 1, 2011, 2012 and 2013. Stock options may be exercised up to eight years following the date of grant.

(8)

Messrs. Jarratt, Robertson, and Bronicheski hold 335,423, 380,146, and 176,538 stock options respectively, granted on March 11, 2011. The stock options allow for the purchase of Common Shares at a price of $5.23. One-third of the stock options vests on each of January 1, 2012, 2013 and 2014. Stock options may be exercised up to eight years following the date of grant.

(9)

Ms. Beairsto and Messrs. Jarratt, Robertson, and Bronicheski hold 85,000, 267,963, 350,413, and 162,917 stock options respectively, granted on March 14, 2012. The stock options allow for the purchase of Common Shares at a price of $6.22. One-third of the stock options vests on each of January 1, 2013, 2014, and 2015. Stock options may be exercised up to eight years following the date of grant.

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(10)	Ms. Beairsto holds 90,909 stock options granted on July 28, 2011, that allow for the purchase of Common Shares at a price of $5.74. One-third of the stock options vests on January 1, 2011, 2012, and 2013. Stock options may be exercised up to eight years following the date of grant.

Each director will serve as a director of APUC until the next annual meeting of shareholders or until his successor is elected in accordance with the by-laws of APUC (the “By-Laws”).

As of March 30, 2011, approximately 870,990 Common Shares representing 0.59% of the issued and outstanding Common Shares are beneficially owned, directly or indirectly, by Senior Executives and approximately 930, 431 Common Shares representing 0.63% of the issued and outstanding Common Shares are beneficially owned, directly or indirectly, by the directors and executive officers of the Corporation.

8.2

Audit Committee

Under the By-Laws, the directors may appoint from their number committees to effect the administration of the director’s duties. The directors have established an Audit Committee comprised of three of the four independent directors of APUC, Mr. Ball (Chairman), Mr. Moore and Mr. Steeves, all of whom are independent and financially literate for purposes of National Instrument 52-110, Audit Committees. The Audit Committee is responsible for reviewing significant accounting, reporting and internal control matters, reviewing all published quarterly and annual financial statements and recommending their approval to the Directors and assessing the performance of APUC’s auditors.

(a)

Audit Committee Charter

The charter for APUC’s audit committee (the “Audit Committee”) is attached as Schedule E to this AIF.

(b)

Relevant Education and Experience

The following is a description of the education and experience, apart from their roles as Directors of APUC, of each member of the Audit Committee that is relevant to the performance of his responsibilities as a member of the Audit Committee.

Mr. Ball has extensive financial experience, with over 30 years of domestic and international lending experience. He is Executive Vice-President of Corpfinance International Limited, a privately owned long-term debt and securitization financier. Mr. Ball was formerly a Vice-President at Standard Chartered Bank of Canada with responsibilities for the Canadian branch operation. Prior to that, Mr. Ball held numerous positions with Canadian Imperial Bank of Commerce, including credit function responsibilities. Mr. Ball is the Chair of the Audit Committee.

Mr. Moore has extensive financial experience and is the Managing Partner of NewPoint Capital Partners Inc., a boutique financial advisory firm focused on mergers and acquisitions. He was formerly a Vice-President at a Canadian Chartered Bank. Mr. Moore holds a Chartered Financial Analyst and a Chartered Director designation.

Mr. Steeves received a Bachelor and Masters of Engineering from Carleton University. Mr. Steeves is the former president of Cumming Cockburn Limited and has extensive financial

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experience in acting as a Chairman, director and/or audit committee member of public and private companies, including APCo, Borealis Hydroelectric Holdings Inc. and KMS Power Income Fund. Mr. Steeves has completed the Chartered Director program of the Directors College (McMaster University and the Conference Board) and has the certification of Ch. Dir. (Chartered Director). He received a Bachelor and Masters of Engineering from Carleton University and holds the Professional Engineering designation in Ontario and British Columbia.

(c)

Pre-Approval Policies and Procedures

All non-audit services proposed to be provided by APUC’s auditors must be approved by the Directors prior to the auditors providing such services.

For the financial year ended December 31, 2011 and December 31, 2010, KPMG LLP charged the following fees to APUC:


Services	2011 Fees ($)		2010 Fees ($)
Audit Fees⁽¹⁾		1,330,000		913,000
Audit-Related Fees⁽²⁾		278,000		110,000
Tax Fees⁽³⁾		907,850		885,000
All Other Fees		Nil		Nil

NOTES:

(1)	For professional services rendered for audit or review or services in connection with statutory or regulatory filings or engagements. The 2011 fees include additional costs related to APCo private placement and APUC equity offering.

(2)

For assurance and related services that are reasonably related to the performance of the audit or review of the Company’s financial statements and not reported under Audit Fees, including accounting advice and French translation services. Fees related to financial statement audits of subsidiary companies and other regulatory filing requirements in 2010 of $265,000 were reclassified to Audit Fees for comparative purposes.

(3)	For tax compliance, advice and planning services.

8.3

Corporate Governance and Compensation Committees

The directors have also established a Corporate Governance Committee (“CGC”) comprised of three of the independent directors of APUC, Mr. Steeves (Chair), Mr. Huskilson and Mr. Moore. The CGC includes two members of management by invitation, Mr. Robertson and Mr. Bronicheski. The mandate of the CGC includes the director nominating and evaluation process. The CGC is responsible for reviewing APUC’s corporate governance practices. The CGC will also consider and make recommendations to the board from time to time regarding the effectiveness of the Directors and whether an increase to the number of directors is warranted.

The directors have also put in place a Compensation Committee (“CC”), comprised of Directors Mr. Huskilson (Chair) and Mr. Ball. The CC includes two members of management by invitation, Mr. Robertson and Mr. Jarratt.

The CC shall exercise the responsibilities and duties set forth below, including but not limited to:

•

Selecting and appointing the CEO of the Corporation;

•

Approving executive compensation plan (including philosophy and guidelines);

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•

Recommending to the Board compensation arrangements for the CEO and reviewing and approving compensation arrangements for Designated Employees and Directors;

•

Reviewing and approving management succession plans; and

•

Approving the grant of stock options.

8.4

Bankruptcies

Mr. Moore was a director of Telephoto Technologies Inc., a private sports and entertainment media. Telephoto Technologies Inc. was placed into receivership in August, 2010 by Venturelink Funds. Mr. Moore resigned from the board of directors of Telephoto Technologies Inc. in April, 2010.

8.5

Potential Material Conflicts of Interest

Other than as set out below or disclosed elsewhere in this AIF and APUC’s financial statements and management’s discussion and analysis for the fiscal year ended December 31, 2011, APUC is not aware of any existing or potential material conflicts of interest between APUC or a subsidiary and any current director or officer of APUC or a subsidiary. Mr. Huskilson is a director of APUC but also the President and CEO of Emera, and Emera is a shareholder of APUC, is a co-owner of Calpeco with Liberty Utilities (West), has entered into agreement to acquire 12 million Common Shares through subscription receipts subject to certain trigger events, and is also in a strategic relationship with APUC. Mr. Huskilson does not vote in Board meetings on matters involving APUC’s relationship with Emera nor on matters involving a potential conflict between APUC and Emera.

9.	LEGAL PROCEEDINGS AND REGULATORY ACTIONS

9.1

Legal Proceedings

Except as disclosed elsewhere in this AIF, the only legal proceedings involving APUC or its subsidiaries that were material in 2011 are as follows:

(a)

Trafalgar

As reported in previous public filings of APUC, APCo owns debt on seven hydroelectric facilities owned by Trafalgar. In 1997, an affiliate of APMI moved to foreclose on the assets, and subsequently Trafalgar went into bankruptcy. Trafalgar was previously awarded a U.S. $10.0 million claim in respect of a lawsuit related to faulty engineering in the design of these facilities, and these funds are held in the bankruptcy estate. As previously disclosed, Trafalgar, APUC and an affiliate of APMI are involved in litigation over, among other things, a civil proceeding on the foreclosure on the assets and in bankruptcy proceedings. APMI funded the initial $2 million in legal fees. An agreement was reached in 2004 between APMI and APUC whereby APUC would reimburse APMI 50% of the legal costs to date in an amount of approximately $1 million, and going forward APUC would fund the legal fees, third party costs and other liabilities with the proceeds from the lawsuits being shared after reimbursement of legal fees, third party costs and other liabilities. The Board has determined that any proceeds from the lawsuit will be shared between APMI and APUC proportionally to the quantum of such costs funded by each party. The Second Circuit Court of Appeals dismissed all the claims against APCo in the civil proceedings and remanded one issue to the District Court. The bankruptcy proceedings are continuing.

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(b)

Côte Ste-Catherine Water Lease Dues

On December 19, 1996, the Québec AG filed a suit in Québec Superior Court against a subsidiary of APUC claiming for amounts that the APUC subsidiary has been paying to The St. Lawrence Seaway Management Corporation (“Seaway Management”) under its water lease with Seaway Management. The water lease contains a “hold harmless” clause which mitigates this claim. As such, the APUC subsidiary brought the Attorney General of Canada and Seaway Management (the “Federal Authorities”) into the proceedings in an action in warranty. On March 27, 2009, the Superior Court dismissed the claim of the Québec AG and suspended the action in warranty following final judgment in this case.

The Québec AG subsequently appealed this decision and on October 21, 2011 the Québec Court of Appeal allowed the appeal and condemned the APUC subsidiary to pay approximately $5.4 million which includes the amount claimed with interest.

The APUC subsidiary believes it is held harmless in its water lease from this decision. The Federal Authorities have decided not to appeal this decision to the Supreme Court of Canada. APUC and Seaway Management are now required to go back to the Superior Court of Quebec which will determine the amount of money reimbursable by Seaway Management to APUC pursuant to the terms of the Water Lease. As a result, the probability of loss, if any, and its quantification cannot be estimated at this time but could range from $nil to $4.8 million. Accordingly, no accruals for amounts owed or recoverable in respect of the water lease dues already paid to Seaway Management have been recorded in the financial statements. Conversely, APCo accrued $1.0 million of water lease owed to Québec AG for 2008 to 2011, which years are subsequent to those covered by the Court Decision and might not be subject to the legal right of offset. Probable amounts recoverable from the Federal Authorities of $0.3 million were also recorded in 2011.

9.2

Regulatory Actions

Except as disclosed elsewhere in this AIF, during the financial year ended December 31, 2011, there have been:

(a)	no penalties or sanctions imposed against APUC by a court relating to securities legislation or by a securities regulatory authority;

(b)	no other penalties or sanctions imposed by a court or regulatory body against APUC that would likely be considered important to a reasonable investor in making an investment decision; or

(c)	no settlement agreements that APUC has entered into with a court relating to securities legislation or with a securities regulatory authority.

10.

INTEREST OF MANAGEMENT AND OTHERS IN MATERIAL TRANSACTIONS

Except as disclosed elsewhere in this AIF, and as disclosed in APUC’s annual financial statements and management’s discussion and analysis as at and for the periods ended

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December 31, 2011, 2010, and 2009, management has no material interest, direct or indirect, in any transaction occurring within the three most recently completed financial years or during the current financial year that has materially affected or will materially affect APUC.

11.

TRANSFER AGENTS AND REGISTRARS

The transfer agent and registrar for the Trust Units is CIBC Mellon Trust Company, at its offices in Toronto, Montréal, Vancouver, Calgary, Halifax and Winnipeg.

12.

MATERIAL CONTRACTS

Except for certain contracts entered into in the ordinary course of business of APUC and its subsidiaries, the contracts described below are the only contracts entered into by APUC or its subsidiaries during 2011 (or prior to 2010 in the case of contracts that are still in effect) that are material to APUC. It is worthy of note that Transfer Agreements dated December 21, 2009 with each of the principals of APMI that transferred their interests in the Management Agreement (as discussed in the Management Information Circular dated June 1, 2010) were approved in 2010 by the Shareholders at the Meeting as well as the TSX. The previously disclosed material contracts with Management have all been terminated as they pertain to APUC. These are the Management Agreement, the Operations Supervisory Agreement, the Administration Agreement, the Governance Agreement and the Direct Operations Agreements, all as defined in the AIF of APUC dated March 31, 2011.

(a)	Cornwall Solar Acquisition: On November 24, 2011 APCo entered into a share purchase agreement with EffiSolar, to acquire all of the issued and outstanding shares of Cornwall Solar Inc. On December 30, 2011 OPA approval was received and the transaction closed on January 4, 2012.

(b)

U.S. Wind Farm Portfolio: Amended and Restated 51% Membership Interest Purchase and Sale Agreement (“MIPA”) entered into as of December 30, 2011, as amended and restated as of March 8, 2012, by and among APFA (the “Wind Farm Buyer”), and Gamesa Energy USA, LLC, a Delaware limited liability company (the “Wind Farm Seller”). Termination of 49% MIPA by that certain letter to APFA c/o APUC dated March 8, 2012, sent by the Wind Farm Seller and as acknowledged and agreed to by the Wind Farm Buyer. 51% MIPA Guarantee dated as of March 8, 2012 made by APUC in favor of the Wind Farm Seller. 51% MIPA Guarantee dated as of March 8, 2012 made by Gamesa in favor of APFA. Indemnification Agreement entered into as of March 8, 2012, by and among the Wind Farm Seller and Gamesa, Wind Portfolio Sponsorco, LLC and APFA. Indemnification Agreement dated March 8, 2012, by and among the various parties to the transaction, including Gamesa and APFA.

(c)	Midwest Utility Transaction Documents: An Asset Purchase Agreement entered into on May 12, 2011 between Atmos Energy Corporation, as Seller, and Liberty Midstates, as Buyer.

(d)

APCo debentures: APCo Trust Indenture between APCo and BNY Trust Company of Canada dated July 25, 2011 providing for the issuance of senior unsecured debentures from time to time. A First Supplemental Trust Indenture between APCo and BNY Trust Company of Canada dated July 25, 2011 providing for the issuance of $135,000,000 5.50% senior unsecured debentures due July 25, 2018. The notes are interest only until maturity. The funds were used to repay the Airsource Senior Debt and to reduce outstanding indebtedness under the APCo Facility.

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(e)

Emera Strategic Agreement: Strategic Agreement between APUC and Emera dated April 29, 2011 which establishes how APUC and Emera will work together to pursue specific strategic investments of mutual benefit. The Strategic Agreement was approved by shareholders at the annual and special general meeting held on June 21, 2011.

(f)

LU credit agreement: Credit agreement dated January 18, 2012 between Liberty Utilities as Borrower and JP Morgan Chase Bank N.A. as Lender and Administrative Agent. The Lender has agreed to provide a three year, unsecured operating line of U.S. $80 million to Liberty Utilities to support the working capital and operating needs of Liberty Utilities and its subsidiaries.

(g)	Chaplin: On February 28, 2012 APCo announced that it was awarded and had signed a 177 megawatt power purchase contract with SaskPower.

(i)

St Leon II: On July 18, 2011 APUC executed of a 25-year PPA with Manitoba Hydro in respect of a 16.5MW expansion of APUC’s existing St. Leon wind energy project located in the Province of Manitoba. On the same day the St. Leon II Energy LP executed a Turbine Supply Agreement and a Service and Maintenance Agreement with Vestas Canadian Wind Technology, Inc. for the procurement and operation of ten 1.65MW wind turbines.

(j)

National Grid Transaction Documents: Two Stock Purchase Agreements each entered into on December 8, 2010 and amended and restated January 21, 2011 between National Grid, as Seller, and Liberty Energy, as Buyer. One agreement is for the purchase of all issued and outstanding shares of Granite State, and the other is for all the issued and outstanding shares of EnergyNorth. The interests of Buyer in the agreements have been transferred to Liberty Energy NH. The closings of the transactions are subject to certain conditions including state and federal regulatory approval, and are expected to occur in the second quarter of 2012.

(k)

Subscription Agreement (National Grid): Subscription agreement dated as of March 25, 2011 for the private placement of 12,000,000 subscription receipts from APUC to Emera at a price of $5.00 per subscription receipt. The proceeds of this subscription receipt transaction will be used to fund the National Grid acquisitions. See “General Development of the Business – Significant Acquisitions – 2011 – New Hampshire Utility Acquisition ”.

(l)

Subscription Agreement (First Wind): Subscription agreement dated as of July 5, 2011 for the private placement of 6,890,131 subscription receipts from APUC to Emera at a price of $5.37 per subscription receipt. Payment for these subscription receipts was satisfied by delivery by Emera of a non-interest bearing promissory note in the amount of $37,000,000. Upon the satisfaction of conditions precedent to the closing of the investment in First Wind Holdings, LLC’s (“First Wind”) wind energy facilities portfolio in the North East United States (other than payment of the purchase price), including the receipt of all necessary regulatory approvals, the promissory note will become due and payable and the rights evidenced by the subscription receipts will be deemed to have been satisfied by the delivery of Common Shares from APUC on a one-for-one basis,

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subject to customary anti-dilution adjustments. As APUC announced on January 27, 2012 that it will no longer proceed with the First Wind investment, these subscription receipts will be cancelled and will not convert into Common Shares of APUC.

13.

INTERESTS OF EXPERTS

KPMG LLP is the external auditor of the Corporation and is independent within the meaning of the Rules of Professional Conduct of the Institute of Chartered Accountants of Ontario.

14.

ADDITIONAL INFORMATION

Additional information relating to APUC may be found on SEDAR at www.sedar.com. Additional information, including directors’ and officers’ remuneration and indebtedness, principal holders of APUC’s securities and securities authorized for issuance under equity compensation plans is contained in APUC’s information circular for its most recent annual meeting. Additional financial information is provided in APUC’s financial statements and management discussion and analysis for the year ended December 31, 2011.

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SCHEDULE A

Renewable—Hydroelectric and Wind Facilities


Generating Facility/Owner	Generating Capacity (kilowatts)	Location	Electricity Purchaser/ 2012 Power Purchase Rates⁽¹⁾	Annual Average Expected Energy Production (MW-hrs)	Year of Expiry of PPA
Renewable Ontario Facilities
Facility: Long Sault Rapids Facility (Hydroelectric) Owner: Algonquin Power (Long Sault) Partnership and N-R Power Partnership	18,000	Abitibi River near Cochrane, Ontario	Electricity Purchaser: OEFC Rates: $0.09634/kW-hr (average estimate)	111,600	2047

Facility: Hurdman Dam Facility (Hydroelectric) Owner: APFC	570	Mattawa River near Mattawa, Ontario	Electricity Purchaser: Ontario Power Authority Rates: $0.07334/kW-hr Paid on Hydroelectric Contract Incentive rate	3,150	2031

Facility: Burgess Dam Facility (Hydroelectric) Owner: APFC	140	Muskoka River near Bala, Ontario	Electricity Purchaser: Hydro One Inc Rates: Paid on Hourly Spot Market Price	0	month to month

Facility: Campbellford Facility (Hydroelectric) Owner: Campbellford LP	4,000	Trent River near Campbellford, Ontario	Electricity Purchaser: OEFC Rates: $0.04346/kW-hr (average estimate)	26,250	2019
Renewable Québec Facilities

Facility: Saint-Alban Facility (Hydroelectric) Owner: SLI	8,200	Ste-Anne River near the Village of Saint-Alban, Québec	Electricity Purchaser: Hydro-Québec Rates: $0.07837/kW-hr (Jan – Nov) $0.08072/kW-hr (Dec)	37,650	2016

Facility: Glenford Facility (Hydroelectric) Owner: Glenford Partnership	4,950	Ste-Anne River near the Village of Ste-Christine d’Auvergne, Québec	Electricity Purchaser: Hydro-Québec Rates: $0.07837/kW-hr (Jan – Nov) $0.08072/kW-hr (Dec)	24,000	2020

Facility: Rawdon Facility (Hydroelectric) Owner: APFC	2,500	Ouareau River near the Village of Rawdon, Québec	Electricity Purchaser: Hydro-Québec Rates: $0.07837/kW-hr (Jan – Nov) $0.08072/kW-hr (Dec)	15,400	2014


Generating Facility/Owner	Generating Capacity (kilowatts)	Location	Electricity Purchaser/ 2012 Power Purchase Rates⁽¹⁾	Annual Average Expected Energy Production (MW-hrs)	Year of Expiry of PPA
Facility: Côte Ste-Catherine Facility (Hydroelectric) Owner: Mont-Laurier Partnership	11,120	St. Lawrence River near the Town of Ste.-Catherine, Québec	Electricity Purchaser: Hydro-Québec Rates: Phase I Energy $0.04911/kW-hr Phase II Energy $0.06703/kW-hr Capacity $164.10/kW * Phase III Energy $0.06979/kW-hr Capacity $172.06/kW* * calculated over the average kilowatt output over the period December to March	Phase 1: 15,500 Phase II: 35,100 Phase III: 34,750	Phase 1: 2021 Phase II: 2018 Phase III:2021

Facility: Ste-Raphaël Facility (Hydroelectric) Owner: APFC	3,500	Rivière de Sud near Québec City, Québec	Electricity Purchaser: Hydro-Québec Rates: $0.07837/kW-hr (Jan – Nov) $0.08072/kW-hr (Dec)	22,550	2014

Facility: Mont Laurier Facility (Hydroelectric) Owner: Mont-Laurier Partnership	2,725	Rivière-du-Lièvre in the Town of Mont Laurier, Québec	Electricity Purchaser: Hydro-Québec Rates: $0.05907/kW-hr	21,250	2027

Facility: Rivière-du-Loup Facility (Hydroelectric) Owner: APFC	2,600	Rivière-du-Loup near the Town of Rivière-du-Loup, Québec	Electricity Purchaser: Hydro-Québec Rates: $0.07837/kW-hr (Jan – Nov) $0.08072/kW-hr (Dec)	17,250	2015

Facility: Hydraska Facility (Hydroelectric) Owner: APT	2,250	Yamaska River near the Town of St.-Hyacinthe, Québec	Electricity Purchaser: Hydro-Québec Rates: Summer Energy $0.06591/kW-hr Winter Energy $0.12086/kW-hr	9,100	2014

Facility: Ste-Brigitte Facility (Hydroelectric) Owner: APFC	4,200	Nicolet River in the Municipality of Ste-Brigitte-des-Saults, Québec	Electricity Purchaser: Hydro-Québec Rates: $0.07837/kW-hr (Jan – Nov) $0.08072/kW-hr (Dec)	12,750	2014

Facility: Belleterre Facility (Hydroelectric) Owner: APFC	2,200	Winneway River in the Municipality of Laforce, Québec	Electricity Purchaser: Hydro-Québec Rates: Summer Energy: $0.06532/kW-hr Winter Energy: $0.12046/kW-hr Capacity: $161.45/kilowatt (over the average kilowatt output over the period December to March)	11,250	2013

A - 2


Generating Facility/Owner	Generating Capacity (kilowatts)	Location	Electricity Purchaser/ 2012 Power Purchase Rates⁽¹⁾	Annual Average Expected Energy Production (MW-hrs)	Year of Expiry of PPA
Facility: Donnacona Facility (Hydroelectric) Owner: Donnacona Partnership	4,800	Jacques Cartier River near Donnacona, Québec	Electricity Purchaser: Hydro-Québec Rates: $0.07837/kW-hr (Jan – Nov) $0.08072/kW-hr (Dec)	20,550	2022

Facility: St. Raphaël de Bellechasse Facility (Arthurville) (Hydroelectric) Owner: APT	650	Riviere du Sud downstream from Ste-Raphaël	Electricity Purchaser: Hydro-Québec Rates: $0.07837/kW-hr (Jan – Nov) $0.08072/kW-hr (Dec)	0⁽⁴⁾	2013

Renewable New York Facilities
Facility: Ogdensburg Facility (Hydroelectric) Owner: Trafalgar⁽²⁾	3,675	Oswegatchie River near Ogdensburg, New York	Electricity Purchaser: National Grid Rates: US$0.04296/kW-hr (est)⁽³⁾	11,100	2016

Facility: Forestport Facility (Hydroelectric) Owner: Trafalgar⁽²⁾	3,300	Black River near Boonville, New York	Electricity Purchaser: National Grid Rates: US$0.04265/kW-hr (est) ⁽³⁾	11,500	2016

Facility: Herkimer Facility (Hydroelectric) Owner: Trafalgar⁽²⁾	1,680	West Canada Creek near Herkimer, New York	Electricity Purchaser: National Grid Rates: No target rate as the site is expected to be offline	0⁽⁴⁾	2016

Facility: Christine Falls Facility (Hydroelectric) Owner: Christine Falls Corporation⁽²⁾	850	Sacandaga River near Clifton, New York	Electricity Purchaser: National Grid Rates: US $0.04145/kW-hr (est) ⁽³⁾	3,300	2028

Facility: Cranberry Lake (Hydroelectric) Owner: Trafalgar⁽²⁾	500	Oswegatchie River near Clifton, New York	Electricity Purchaser: National Grid Rates: US$0.04297/kW-hr (est) ⁽³⁾	1,800	2016

Facility: Kayuta Lake Facility (Hydroelectric) Owner: Trafalgar⁽²⁾	400	Black River near Boonville, New York	Electricity Purchaser: National Grid Rates: US$0.00822/kW-hr (est)	1,800	2028

Facility: Adams Facility (Hydroelectric) Owner: Trafalgar⁽²⁾	350	Sandy Creek near Adams, New York	Electricity Purchaser: National Grid Rates: No target rate as the site is expected to be offline	0⁽⁴⁾	2028

Facility: Kings Falls Facility (Hydroelectric) Owner: Tug Hill Energy, Inc.⁽⁵⁾	1,750	Deer River near Copenhagen, New York	Electricity Purchaser: National Grid Rates: No estimate complete for 2012⁽⁶⁾	0⁽⁶⁾	2016

A - 3


Generating Facility/Owner	Generating Capacity (kilowatts)	Location	Electricity Purchaser/ 2012 Power Purchase Rates⁽¹⁾	Annual Average Expected Energy Production (MW-hrs)	Year of Expiry of PPA
Facility: Otter Creek Facility (Hydroelectric) Owner: Tug Hill Energy, Inc.⁽⁵⁾	530	Otter Creek in Craig, New York	Electricity Purchaser: National Grid Rates: No estimate complete for 2012 ⁽⁷⁾	0⁽⁶⁾	2016

Facility: Phoenix Facility (Hydroelectric) Owner: Oswego Hydro Partners L.P.⁽⁵⁾	3,500	Oswego River in Phoenix, New York	Electricity Purchaser: National Grid Rates: US$0.09205/kW-hr Flat Rate	11,250	2026

Facility: Beaver Falls Facility (Hydroelectric) Owner: Algonquin Power (Beaver Falls) LLC	2,500	Beaver River in Beaver Falls, New York	Electricity Purchaser: National Grid Rates: US$0.02852/kW-hr (est)	15,400	2019

Facility: Burt Dam Facility (Hydroelectric) Owner: Burt Dam Partnership	600	18 Mile Creek near Newfane, New York	Electricity Purchaser: National Grid Rates: No estimate complete for 2012 ⁽⁶⁾	0⁽⁶⁾	2016

Facility: Hollow Dam Facility (Hydroelectric) Owner: Hollow Dam Partnership	900	Oswegatchie River near Gouverneur, New York	Electricity Purchaser: National Grid Rates: No estimate complete for 2012 ⁽⁶⁾	0⁽⁶⁾	2016

New England Facilities
Facility: Greggs Falls Facility (Hydroelectric) Owner: Greggs Falls Partnership	3,500	Piscataquog River near the Town of Goffstown, New Hampshire	Electricity Purchaser: Public Service Company of New Hampshire (“PSNH”) Rates: US$0.05407/kW-hr (est) ⁽⁵⁾	10,450	60 day written notice

Facility: Pembroke Facility (Hydroelectric) Owner: Pembroke Hydro Associates Limited Partnership	2,600	Suncook River near the Town of Pembroke, New Hampshire	Electricity Purchaser: PSNH Rates: US$0.05461/kW-hr (est) ⁽⁵⁾	9,750	60 day written notice

Facility: Clement Facility (Hydroelectric) Owner: Clement Dam Hydroelectric LLC	2,400	Winnipisaukee River near the Town of Tilton, New Hampshire	Electricity Purchaser: PSNH Rates: US$0.05551/kW-hr (est) ⁽⁵⁾	10,700	60 day written notice

Facility: Franklin Facility (Hydroelectric) Owner: Franklin Power LLC	River Bend 1,600 Steven’s Mill 200	Winnipesaukee River near the Town of Franklin, New Hampshire	Electricity Purchaser: PSNH Rates: River Bend US$0.05291/kW-hr (est) ⁽⁵⁾ Steven’s Mill US$0.05609/kW-hr (est) ⁽⁵⁾	River Bend 6,800 Steven’s Mill 950	60 day written notice – both sites

A - 4


Generating Facility/Owner	Generating Capacity (kilowatts)	Location	Electricity Purchaser/ 2012 Power Purchase Rates⁽¹⁾	Annual Average Expected Energy Production (MW-hrs)	Year of Expiry of PPA
Facility: Lochmere Facility (Hydroelectric) Owner: HDI Partnership	1,200	Winnipesaukee River near Lochmere, New Hampshire	Electricity Purchaser: PSNH Rates: US$0.05560/kW-hr (est) ⁽⁵⁾	4,150	60 day written notice

Facility: Lakeport Facility (Hydroelectric) Owner: Lakeport Corporation	600	Winnipesaukee River near Laconia, New Hampshire	Electricity Purchaser: PSNH Rates: US$0.05530/kW-hr (est) ⁽⁵⁾	2,450	60 day written notice

Facility: Mine Falls Facility (Hydroelectric) Owner: Mine Falls Limited Partnership	3,000	Nashua River near the City of Nashua, New Hampshire	Electricity Purchaser: PSNH Rates: US $0.05483/kW-hr (est)⁽⁵⁾	11,400	60 day written notice

Facility: Great Falls Facility (Hydroelectric) Owner: Great Falls Partnership	10,950	Passaic River near the City of Paterson, New Jersey	Electricity Purchaser: Public Service Electric and Gas Company Rates: US $0.05470/kW-hr (est)⁽⁵⁾	23,350	60 day written notice

Facility: Moretown Facility (Hydroelectric) Owner: Moretown Partnership	1,200	Mad River near Moretown, Vermont	Electricity Purchaser: Vermont Power Exchange, Inc. Rates: $0.10780/kW-hr (average estimate)	0⁽⁴⁾	2018

Renewable—Western Canada Facility
Facility: Dickson Dam Facility (Hydroelectric) Owner: APOT	15,000	Innisfail, Alberta	Electricity Purchaser: AESO Rates: Market Rates Energy: $0.0620/kW-hr (estimate)	65,000	NA

Renewable—Maritime Facilities
Facility: Tinker Facility (Hydroelectric) Owner: APT	33,500	Perth-Andover, New Brunswick	Electricity Purchaser: AES Town of Perth-Andover Rates: AES ~ U.S. $0.046/kWhr Town of Perth Andover: ~ CDN $.085/kWhr (including transmission charges)	120,000	Perth-Andover Contract through 2021 AES contract through 2013

Facility: Caribou Facility (Hydroelectric) Owner: Maine Gen Co.	900	Caribou, Maine	Electricity Purchaser: AES Rates: Energy – ~U.S. $0.046/kWhr	5,300	n/a

Facility: Squa Pan Facility (Hydroelectric) Owner: Maine Gen Co.	1,400	Squa Pan Lake, near Caribou Maine	Electricity Purchaser: AES Rates: Energy – ~U.S. $0.046/kWhr	850	n/a

A - 5


Generating Facility/Owner	Generating Capacity (kilowatts)	Location	Electricity Purchaser/ 2012 Power Purchase Rates⁽¹⁾	Annual Average Expected Energy Production (MW-hrs)	Year of Expiry of PPA
Facility: Rattle Brook Facility (Hydroelectric) Owner: Rattlebrook Partnership	4,000	Rattle Brook near Jackson’s Arm, Newfoundland	Electricity Purchaser: Newfoundland and Labrador Hydro Rates: Summer $0.07148/kW-hr Winter $0.09693/kW-hr	15,950	2024

Renewable—Solar Facility
Facility: Cornwall Solar (Solar)	10,000	Cornwall, Ontario	Electricity Purchaser: (Under Development - OPA)	13,400	n/a

Renewable—Wind Facilities
Facility: Chaplin Wind (Wind)	177,000	Chaplin, Saskatchewan	Electricity Purchaser: (Under Development - SaskPower)	247,000	n/a

Facility: St. Leon Facility (Wind) Owner: St. Leon LP	104,000	St. Leon, Manitoba	Electricity Purchaser: Manitoba Hydro	372,000	2025 + one 5 year extension

Facility: Amherst Island (Wind)	75,000	Stella, Ontario	Electricity Purchaser: (Under Development - OPA)	247,000	n/a

Facility: Red Lily (Wind) Owner: Concord	26,400	Saskatchewan	Electricity Purchaser: SaskPower	88,000	2036

Facility: Morse (Wind)	25,000	Morse, Saskatchewan	Electricity Purchaser: (Under Development - SaskPower)	93,000	n/a

Facility: Saint-Damase (Wind)	24,000	Saint-Damase, Québec	Electricity Purchaser: (Under Development – Hydro-Quebec)	86,000	n/a

Facility: Val-Éo (Wind)	24,000	Saint-Gédéon, Québec	Electricity Purchaser: (Under Development – Hydro-Quebec)	66,000	n/a

Facility: St. Leon II Facility (Wind)	16,500	St. Leon, Manitoba	Electricity Purchaser: Manitoba Hydro	58,000	2037

Notes:

(1)	2012 PPA rates have been rounded to four decimals and are not representative of long term power purchase rates under the applicable PPAs. Long-term rates under different agreements will be both higher and lower than current rates. Seasonal periods and daily periods vary from project to project.

(2)

APC provides Trafalgar with certain operational services in respect of the Trafalgar Facilities.

(3)	These rates reflect the estimated Avoided Costs of National Grid.

(4)	Scheduled to be offline for repairs in 2012. No decision has been made as to the timing of repairing these Facilities.

(5)	PSNH purchases the energy produced by these generating stations at the ISO-NE. market rates. These agreements are cancellable on 60 days written notice.

(6)	This facility no longer fits APUC’s preferred asset profile and is no longer considered strategic to APUC. As a result, APUC’s interest in these facilities is expected to be sold in 2012.

A - 6

SCHEDULE B

Thermal—Biomass, Cogeneration, Steam, Diesel and Energy From Waste Facilities

Generating

Facility/Owner

Generating
Capacity
(kilowatts)

Location

Electricity Purchaser/ 2012

Power Purchase Rates

Annual
Average
Expected
Energy
Production
(MW-hrs)

Year of
Expiry of
PPA

Year of
Expiry of
Lease

Thermal - Biomass Facility

Facility:

Valley Power Facility (Biomass)

Owner:

Valley Power L.P.

12,000

Drayton
Valley,
Alberta

Electricity Purchaser:

TransAlta Utilities Corporation

Rates:

Energy: $0.0709/kW-hr

0⁽¹⁾

2014

Owned

Thermal—Cogeneration Facilities

Facility:

Sanger Facility (Cogeneration)

Owner:

Algonquin Power Sanger LLC

56,000

Sanger,
California

Electricity Purchaser:

PG&E

98,000

2021

Owned

Rates:

US$ 0. 045/ kW-hr (estimated average)*

* subject to gas price indexing

Capacity – Approximately $298,000 January-April &November-December Approximately $1,093,000 May-October

Facility:

Windsor Locks Facility (Cogeneration)

Owner:

Algonquin Power Windsor Locks LLC

56,000

Windsor
Locks,
Connecticut

Electricity Purchaser:

ISO New England

Ahlstrom

176,000

87,000

Merchant

2018

Rates:

ISO New England-Market Rates , included hourly energy, forward capacity and forward reserve payments

Mill/NGC - US$0. 049/kW-hr* Capacity $203,000**

Steam - DNM/NGC - US$7.26/1000lbs* Capacity $127,000

* Estimated average rate, includes variable component based on natural gas prices.

**Estimated average monthly rate, charges are CPI indexed.

Capacity Market and Spot Market – market prices

Facility:

Brampton Cogeneration Inc.

(Cogeneration)

Owner:

APOT

N/A

Brampton,
Ontario

Electricity Purchaser:

N/A

Rates:

Steam - Normapac

$8.45/1000lbs*

Capacity $103,600**

* Estimated average rate, includes variable component based on natural gas prices.

**Estimated average monthly rate, charges are partially CPI indexed.

604
million
lbs of
steam

2024

N/A

Facility:

EFW Facility (Energy from Waste)

Owner:

Algonquin Power Energy from Waste Inc.

10,100

Brampton,
Ontario

Electricity Purchaser:

OEFC

Rates:

$0.060/kW-hr (average estimated rate)

Tipping -

Peel – $91/tonne up to 127,900 tonnes, $66 tonnes thereafter

Waste rates subject to monthly CPI indexing

7,450

2012

Owned

Generating

Facility/Owner

Generating
Capacity
(kilowatts)

Location

Electricity Purchaser/ 2012

Power Purchase Rates

Annual
Average
Expected
Energy
Production
(MW-hrs)

Year of
Expiry of
PPA

Year of
Expiry of
Lease

Thermal – Diesel Facilities

Facility:

Tinker Facility

(Diesel)

Owner:

Tinker Gen Co.

1,000

Perth-
Andover,
New
Brunswick

Electricity Purchaser: Not Under Contract

Rates:

Capacity only

Owned

Facility:

Caribou Facility

(Diesel)

Owner:

Maine Gen Co.

7,000

Caribou,
Maine

Electricity Purchaser: AES

Rates:

Capacity only

Owned

Facility:

Flo’s Inn Facility

(Diesel)

Owner:

Maine Gen Co.

4,000

Caribou,
Maine

Electricity Purchaser: Not Under Contract

Rates:

n/a

0⁽²⁾

Owned

Notes:

(1)	This facility no longer fits APUC’s preferred asset profile and is no longer considered strategic to APUC. As a result, APUC’s interest in these facilities is expected to be sold in 2012.

(2)	Available to provide capacity only. The thermal facilities located in Northern Maine and New Brunswick are not considered strategic to APUC. As a result APUC is taking steps to shutdown these facilities.

B - 2

SCHEDULE C

Wastewater and Water Distribution Facilities


Utility	Owner	Location	Type of Utility	December 31, 2011 Connections	Rates
Black Mountain	Black Mountain Sewer Corporation	Carefree, Arizona	Wastewater	2,276	Residential US $65.24 (standard monthly rate)

Gold Canyon	Gold Canyon Sewer Company	Gold Canyon Arizona	Wastewater	7,423	Residential US $52.40 (standard monthly rate)

Bella Vista	Bella Vista Water Co., Inc.	Sierra Vista, Arizona	Water Distribution	9,012	Residential US $15.00 (Average monthly rate)

Tall Timbers	Tall Timbers Utility Company, Inc.	Tyler, Texas	Wastewater	2,185	Residential US $54.93 (standard monthly rate)

Woodmark	Woodmark Utilities, Inc.	Tyler, Texas	Wastewater	1,731	Residential US $47.76 (standard monthly rate)

Litchfield Park	Litchfield Park Service Company	Litchfield, Park, Arizona	Wastewater Water Distribution	18,891 16,564	Residential US $56.54 Commercial US $95.60 US $39.58 (Average residential rate)

Fox River	AWRI	Sheridan, Illinois	Wastewater Water Distribution	219 220	US $240.08 US $141.61

Timber Creek	AWRM	DeSoto, Missouri	Wastewater Water Distribution	20 25	US $16.00 min & $17.24/1000 gal. US $8.96 min. & US $5.96/1000 gal

Holiday Hills	AWRM	Branson, Missouri	Water Distribution	484	US $8.96 min. & US $5.96/1000 gal

Ozark Mountain	AWRM	Kimberling City, Missouri	Wastewater Water Distribution	241 256	US $16.00 min & $17.24/1000 gal. US $8.96 min. & $5.96/1000 gal

Holly Lake Ranch	AWRT	Hawkins, Texas	Wastewater Water Distribution	152 1,725	US $128.53 min & US $3.65/1000 gal. US $30.20 min. & $2.89/1000 gal

Big Eddy	AWRT	Flint, Texas	Wastewater Water Distribution	411 668	US $128.53 min & US $3.65/1000 gal. US $30.20 min. & $2.89/1000 gal

Piney Shores	AWRT	Conroe, Texas	Wastewater Water Distribution	269 273	US $128.53 min & US $3.65/1000 gal. US $39.81 min. & $1.30/1000 gal

Hill Country	AWRT	New Braunfels, Texas	Wastewater Water Distribution	379 225	US $128.53 min & US $3.65/1000 gal. US $39.81 min. & $1.30/1000 gal


Utility	Owner	Location	Type of Utility	December 31, 2011 Connections	Rates
Rio Rico	Rio Rico Utilities Inc.	Rio Rico, Arizona	Wastewater Water Distribution	2,207 6,429	US $45.88 (residential rates) US $10.98 min. & 0-3,000 gal – US $1.59/1,000 gal 3,001-9,000 gal – US $2.92/1,000 gal >9,000 gal – US $3.64/1,000 gal

Northern Sunrise	Northern Sunrise Water Company Inc.	Sierra Vista, Arizona	Water Distribution	352	US $15.00 min / Per 1000 / 0-4,000gal $1.45/ 4,000-10,000 gal $2.21 / >10,000 gal $2.72

Southern Sunrise	Southern Sunrise Water Company Inc.	Sierra Vista, Arizona	Water Distribution	866	US $15.00 min / Per 1000 / 0-4,000gal $1.45/ 4,000-10,000 gal $2.21 / >10,000 gal $2.72

Entrada Del Oro ⁽¹⁾	Entrada Del Oro Sewer Company	Gold Canyon , Arizona	Wastewater	337	US $70.00 (standard monthly rate)

Seaside Resort	AWRT	Galveston, Texas	Water Distribution Wastewater	156 156	US $166.68 US $165.45

Noel	AWRM	Noel, Missouri	Water Distribution	612	US $7.76 Consumption $1.80 per 1000 gallons

KMB	AWRM	Jefferson, Franklin and Cape Girardeau counties in Missouri	Wastewater Water Distribution	190 546	$27.60 Varies – Fixed Average US $17.33 Consumption Average US $3.57 per 1000 gal;

Total connections				75,500

Notes:

(1)	Liberty Water Co. currently holds a beneficial interest in the shares of the company pending regulatory approval of its acquisition.

C - 2

SCHEDULE D

Electrical Distribution Facilities

Utility

Owner⁽¹⁾

Location

Type of Utility

December 31, 2011
Connections

Rates

Calpeco

California Pacific Electric Company, LLC

Lake Tahoe, California

Electricity Distribution

47,000

Residential Rates – Monthly Charge $6.62 plus $0.10864/kwh for baseline usage; $0.13696 for excess usage.

Commercial (Small) – Monthly Charge $12.22 plus $0.12882/kwh for baseline usage.

Commercial - (Medium) – Monthly Charge $108.94 plus average rate of $0.09969/kwh for baseline usage.

Commercial - (Large) – Monthly Charge $223.98 plus an average rate of $0.069376/kwh for baseline usage.

SCHEDULE E

ALGONQUIN POWER & UTILITIES CORP.

MANDATE OF THE AUDIT COMMITTEE

By appropriate resolution of the board of directors (the “Board”) of Algonquin Power & Utilities Corp., the Audit Committee (the “Committee”) has been established as a standing committee of the Board with the terms of reference set forth below. Unless the context requires otherwise, the term “Corporation” refers to Algonquin Power & Utilities Corp. and its subsidiaries.

1.	PURPOSE

1.1	The Committee’s purpose is to:

(a)

assist the Board’s oversight of:

(i)

the integrity of the Corporation’s financial statements, Management’s Discussion and Analysis (“MD&A”) and other financial reporting;

(ii)

the Corporation’s compliance with legal and regulatory requirements;

(iii)

the external auditor’s qualifications, independence and performance;

(iv)

the performance of the Corporation’s internal audit function and internal auditor;

(v)

the communication among management of the Corporation and its subsidiary entities and the Corporation’s Chief Executive Officer and its Chief Financial Officer (collectively, “Management”), the external auditor, the internal auditor and the Board;

(vi)

the review and approval of any related party transactions; and

(vii)

any other matters as defined by the Board;

(b)

prepare and/or approve any report that is required by law or regulation to be included in any of the Corporation’s public disclosure documents relating to the Committee.

2.	COMMITTEE MEMBERSHIP

2.1	Number of Members – The Committee shall consist of not fewer than three members.

2.2	Independence of Members – Each member of the Committee shall:

(a)

be a director of the Corporation;

(b)

not be an officer or employee of the Corporation or any of the Corporation’s subsidiary entities or affiliates;

(c)

be an unrelated director for the purposes of the Toronto Stock Exchange (the “TSX”) Corporate Governance Policy; and

(d)

satisfy the independence requirements applicable to members of audit committees under each of the rules of National Instrument 52 110 – Audit Committees of the Canadian Securities Administrators (“NI 52 110”) and other applicable laws and regulations.

2.3

Financial Literacy – Each member of the Committee shall satisfy the financial literacy requirements applicable to members of audit committees under the TSX Corporate Governance Policy, NI 52 110 and other applicable laws and regulations.

2.4

Annual Appointment of Members – The Committee and its Chair shall be appointed annually by the Board and each member of the Committee shall serve at the pleasure of the Board until he or she resigns, is removed or ceases to be a director.

3.	COMMITTEE MEETINGS

3.1

Time and Place of Meetings – The time and place of the meetings of the Committee and the calling of meetings and the procedure in all things at such meetings shall be determined by the Committee; provided, however, that the Committee shall meet at least quarterly, a majority of the members of the Committee shall constitute a quorum and the Committee shall maintain minutes or other records of its meetings and activities.

3.2

In Camera Meetings – As part of each meeting of the Committee at which it approves, or if applicable, recommends that the Board approve, the annual audited financial statements of the Corporation or at which the Committee reviews the interim financial statements of the Corporation, and at such other times as the Committee deems appropriate, the Committee shall meet separately with each of the persons set forth below to discuss and review specific issues as appropriate:

(a)

representatives of Management;

(b)

the external auditor; and

(c)

the internal audit personnel.

3.3

Attendance at Meetings – The external auditors are entitled to attend and be heard at each Committee meeting. In addition, the Committee may invite to a meeting any officers or employees of the Corporation, legal counsel, advisor and other persons whose attendance it considers necessary or desirable in order to carry out its responsibilities.

4.	COMMITTEE AUTHORITY AND RESOURCES

4.1	Direct Channels of Communication – The Committee shall have direct channels of communication with the Corporation’s internal and external auditors to discuss and review specific issues as appropriate.

E - 2

4.2

Retaining and Compensating Advisors – The Committee, or any member of the Committee with the approval of the Committee, may retain at the expense of the Corporation such independent legal, accounting (other than the external auditor) or other advisors on such terms as the Committee may consider appropriate and shall not be required to obtain any other approval in order to retain or compensate any such advisors.

4.3	Funding – The Corporation shall provide for appropriate funding, as determined by the Committee, for payment of compensation of the external auditor and any advisor retained by the Committee under Section 4.2 of this Charter.

4.4	Investigations – The Committee shall have unrestricted access to the personnel and documents of the Corporation and the Corporation’s subsidiary entities and shall be provided with the resources necessary to carry out its responsibilities.

5.	REMUNERATION OF COMMITTEE MEMBERS

5.1	Director Fees Only – No member of the Committee may accept, directly or indirectly, fees from the Corporation or any of its subsidiary entities other than remuneration for acting as a director or member of the Committee or any other committee of the Board.

5.2

Other Payments – For greater certainty, no member of the Committee shall accept any consulting, advisory or other compensatory fee from the Corporation. For purposes of Section 5.1, the indirect acceptance by a member of the Committee of any fee includes acceptance of a fee by an immediate family member or a partner, member or executive officer of, or a person who occupies a similar position with, an entity that provides accounting, consulting, legal, investment banking or financial advisory services to the Corporation or any of its subsidiaries, other than limited partners, non–managing members and those occupying similar positions who, in each case, have no active role in providing services to the entity.

6.	DUTIES AND RESPONSIBILITIES OF THE COMMITTEE

6.1	Overview – The Committee’s principal responsibility is one of oversight. Management is responsible for preparing the Corporation’s financial statements and the external auditor is responsible for auditing those financial statements.

6.2	The Committee’s specific duties and responsibilities are as follows:

(a)

Financial and Related Information

(i)

Annual Financial Statements – The Committee shall review and discuss with Management and the external auditor the Corporation’s annual financial statements and related MD&A and if applicable, report thereon to the Board as a whole before they approve such statements and MD&A.

(ii)

Interim Financial Statements – The Committee shall review and discuss with Management and the external auditor the Corporation’s interim financial statements and related MD&A and if applicable, report thereon to the Board as a whole before they approve such statements and MD&A.

E - 3

(iii)

Prospectuses and Other Documents – The Committee shall review and discuss with Management and the external auditor the financial information, financial statements and related MD&A appearing in any prospectus, annual report, annual information form, management information circular or any other public disclosure document prior to its public release or filing and if applicable, report thereon to the Board as a whole.

(iv)

Accounting Treatment – Prior to the completion of the annual external audit, and at any other time deemed advisable by the Committee, the Committee shall review and discuss with Management and the external auditor (and shall arrange for the documentation of such discussions in a manner it deems appropriate) the quality and not just the acceptability of the Corporation’s accounting principles and financial statement presentation, including, without limitation, the following:

(A)

all critical accounting policies and practices to be used, including, without limitation, the reasons why certain estimates or policies are or are not considered critical and how current and anticipated future events impact those determinations and an assessment of Management’s disclosures along with any significant proposed modifications by the auditors that were not included;

(B)

all alternative treatments within generally accepted accounting principles for policies and practices related to material items that have been discussed with Management, including, without limitation, ramification of the use of such alternative disclosure and treatments, and the treatment preferred by the external auditor, which discussion should address recognition, measurement and disclosure consideration related to the accounting for specific transactions as well as general accounting policies. Communications regarding specific transactions should identify the underlying facts, financial statement accounts impacted and applicability of existing corporate accounting policies to the transaction. Communications regarding general accounting policies should focus on the initial selection of, and changes in, significant accounting policies, the impact of the Management’s judgments and accounting estimates and the external auditor’s judgments about the quality of the Corporation’s accounting principles. Communications regarding specific transactions and general accounting policies should include the range of alternatives available under generally accepted accounting principles discussed by Management and the auditors and the reasons for selecting the chosen treatment or policy. If the external auditor’s preferred accounting treatment or accounting policy is not selected, the reasons therefore should also be reported to the Committee;

(C)

other material written communications between the external auditor and Management, such as any management letter,

E - 4

schedule of unadjusted differences, listing of adjustments and reclassifications not recorded, management representation letter, report on observations and recommendations on internal controls, engagement letter and independence letter;

(D)

major issues regarding financial statement presentations;

(E)

any significant changes in the Corporation’s selection or application of accounting principles;

(F)

the effect of regulatory and accounting initiatives, as well as off balance sheet structures, on the financial statements of the Corporation; and

(G)

the adequacy of the Corporation’s internal controls and any special audit steps adopted in light of control deficiencies.

(v)

Disclosure of Other Financial Information – The Committee shall:

(A)

review, and discuss generally with Management, the type and presentation of information to be included in, all public disclosure by the Corporation containing audited, unaudited or forward-looking financial information in advance of its public release by the Corporation, including, without limitation, earnings guidance and financial information based on unreleased financial statements;

(B)

discuss generally with Management the type and presentation of information to be included in earnings and any other financial information given to analysts and rating agencies, if any; and

(C)

satisfy itself that adequate procedures are in place for the review of the Corporation’s disclosure of financial information extracted or derived from the Corporation’s financial statements, other than the Corporation’s financial statements, MD&A and earnings press releases, and shall periodically assess the adequacy of those procedures.

(b)

External Auditor

(i)

Authority with Respect to External Auditor – As representative of the Corporation’s shareholders and as a committee of the Board, the Committee shall be directly responsible for the appointment, compensation, retention, termination and oversight of the work of the external auditor (including, without limitation, resolution of disagreements between Management and the auditor regarding financial reporting) for the purpose of preparing or issuing an audit report or performing other audit, review or attest services for the Corporation. In this capacity, the Committee shall have sole authority for recommending the person to be proposed to the Corporation’s shareholders for appointment as external auditor, whether at any time the incumbent external auditor should be

E - 5

removed from office, and the compensation of the external auditor. The Committee shall require the external auditor to confirm in an engagement letter to the Committee each year that the external auditor is accountable to the Board and the Committee as representatives of shareholders and that it will report directly to the Committee.

(ii)

Approval of Audit Plan – The Committee shall approve, prior to the external auditor’s audit, the external auditor’s audit plan (including, without limitation, staffing), the scope of the external auditor’s review and all related fees.

(iii)

Independence – The Committee shall satisfy itself as to the independence of the external auditor. As part of this process:

(A)

The Committee shall require the external auditor to submit on a periodic basis to the Committee a formal written statement confirming its independence under applicable laws and regulations and delineating all relationships between the auditor and the Corporation and the Committee shall actively engage in a dialogue with the external auditor with respect to any disclosed relationships or services that may impact the objectivity and independence of the external auditor and take, or, if applicable, recommend that the Board take, any action the Committee considers appropriate in response to such report to satisfy itself of the external auditor’s independence.

(B)

In accordance with applicable laws and regulations, the Committee shall pre–approve any non–audit services (including, without limitation, fees therefore) provided to the Corporation or its subsidiaries by the external auditor or any auditor of any such subsidiary and shall consider whether these services are compatible with the external auditor’s independence, including, without limitation, the nature and scope of the specific non–audit services to be performed and whether the audit process would require the external auditor to review any advice rendered by the external auditor in connection with the provision of non audit services. The Chair may approve additional non audit services that arise between Committee meetings, provided that the Chair reports any such approvals to the Committee at the next scheduled meeting.

(C)

The Committee shall establish a policy setting out the restrictions on the Corporation’s subsidiary entities hiring partners, employees, former partners and former employees of the Corporation’s external auditor or former external auditor.

(iv)

Rotating of Auditor Partner – The Committee shall evaluate the performance of the external auditor and whether it is appropriate to adopt a policy of rotating lead or responsible partners of the external auditors.

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(v)

Review of Audit Problems and Internal Audit – The Committee shall review with the external auditor:

(A)

any problems or difficulties the external auditor may have encountered, including, without limitation, any restrictions on the scope of activities or access to required information, and any disagreements with Management and any management letter provided by the auditor and the Corporation’s response to that letter;

(B)

any changes required in the planned scope of the internal audit; and

(C)

the internal audit department’s responsibilities, budget and staffing.

(vi)

Review of Proposed Audit and Accounting Changes – The Committee shall review major changes to the Corporation’s auditing and accounting principles and practices suggested by the external auditor.

(vii)

Regulatory Matters – The Committee shall discuss with the external auditor the matters required to be discussed by CAS 260 of the CICA Handbook – Assurance relating to the conduct of the audit.

(c)

Internal Audit Function – Controls

(i)

Regular Reporting – Internal audit personnel shall report regularly to the Committee.

(ii)

Oversight of Internal Controls – The Committee shall oversee Management’s design and implementation of and reporting on the Corporation’s internal controls and review the adequacy and effectiveness of Management’s financial information systems and internal controls. The Committee shall periodically review and approve the mandate, plan, budget and staffing of internal audit personnel. The Committee shall direct Management to make any changes it deems devisable in respect of the internal audit function.

(iii)

Review of Audit Problems – The Committee shall review with the internal audit personnel: any problem or difficulties the internal audit personnel may have encountered, including, without limitation, any restrictions on the scope of activities or access to required information, and any significant reports to Management prepared by the internal audit personnel and Management’s responses thereto.

(iv)

Review of Internal Audit Personnel – The Committee shall review the appointment, performance and replacement of the senior internal auditing personnel and the activities, organization structure and qualifications of the persons responsible for the internal audit function.

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(d)

Risk Assessment and Risk Management

(i)

Risk Exposure – The Committee shall discuss with the external auditor, internal audit personnel and Management periodically the Corporation’s major financial risk exposures and the steps Management has taken to monitor and control such exposures.

(ii)

Investment Practices – The Committee shall review Management’s plans and strategies around investment practices, banking performance and treasury risk management.

(iii)

Compliance with Covenants – The Committee shall review Management’s procedures to ensure compliance by the Corporation with its loan covenants and restrictions, if any.

(e)

Legal Compliance

(i)

On at least a quarterly basis, the Committee shall review with the Corporation’s legal counsel, external auditor and Management any legal matters (including, without limitation, litigation, regulatory investigations and inquiries, changes to applicable laws and regulations, complaints or published reports) that could have a significant impact on the Corporation’s financial position, operating results or financial statements and the Corporation’s compliance with applicable laws and regulations.

(ii)

The Committee shall review and, if applicable, advise the Board with respect to the Corporation’s policies and procedures regarding compliance with applicable laws and regulations and shall notify Management and, if applicable, the Board, promptly after becoming aware of any material non–compliance by the Corporation with applicable laws and regulations.

(f)

Whistle Blowing – The Committee shall establish procedures for:

(i)

the receipt, retention and treatment of complaints received by the Corporation regarding accounting, internal accounting controls or auditing matters; and

(ii)

the confidential, anonymous submission by employees of the Corporation’s subsidiary entities of concerns regarding questionable accounting or auditing matters.

(g)

Related Party Transactions – The Committee shall review and approve any transaction between the Corporation and a related party and any transaction involving the Corporation and another party in which the parties’ relationship could enable the negotiation of terms on other than an independent, arms’ length basis.

(h)

Review of the Management’s Certifications and Reports – The Committee shall review and discuss with Management all certifications of financial information,

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management reports on internal controls and all other management certifications and reports relating to the Corporation’s financial position or operations required to be filed or released under applicable laws and regulations prior to the filing or release of such certifications or reports.

(i)

Liaison – The Committee shall review and ensure that appropriate liaison and co–operation exist between the external auditor and internal audit personnel and provide a direct channel of communication between external and internal auditors and the Committee.

(j)

Public Reports – The Committee shall prepare and/or approve any report that is required by law or regulation to be included in any of the Corporation’s public disclosure documents relating to the Committee.

(k)

Other Matters – The Committee may, in addition to the foregoing, perform such other functions as may be necessary or appropriate for the performance of its oversight function.

7.	REPORTING TO THE BOARD

7.1	Regular Reporting – If applicable, the Committee shall report to the Board following each meeting of the Committee and at such other times as the Committee may determine to be appropriate.

8.	EVALUATION OF COMMITTEE PERFORMANCE

8.1	Performance Review – The Committee shall periodically assess its performance.

8.2	Amendments to Charter

(a)

Review by Committee – On at least an annual basis, the Committee shall review and discuss the adequacy of this Charter and if applicable, recommend any proposed changes to the Board.

(b)

Review by Board – The Board will review and reassess the adequacy of the Charter on an annual basis and at such other times, as it considers appropriate.

9.	LEGISLATIVE AND REGULATORY CHANGES

9.1

Compliance – It is the Board’ intention that this mandate shall reflect at all times all legislative and regulatory requirements applicable to the Committee. Accordingly, this Charter shall be deemed to have been updated to reflect any amendments to such legislative and regulatory requirements and shall be formally amended at least annually to reflect such amendments.

10.	CURRENCY OF CHARTER

10.1	Currency of Charter – This Charter was approved by the Board of Directors of Algonquin Power & Utilities Corp. effective March 31, 2010.

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SCHEDULE F

Caution concerning forward-looking statements

Certain statements included in this AIF contain information that is forward-looking within the meaning of certain securities laws, including information and statements regarding prospective results of operations, financial position or cash flows. Forward-looking information is included throughout this Annual Information Form, including among other places, under the heading “General Development of the Business”, “Description of the Business” and “Legal Proceedings and Regulatory Actions”. These statements and information are forward-looking, and are based on factors or assumptions that were applied in drawing a conclusion or making a forecast or projection, including assumptions based on historical trends, current conditions and expected future developments, and other factors believed to be appropriate in the circumstances.

Since forward-looking statements relate to future events and conditions, by their very nature they require making assumptions and involve inherent risks and uncertainties. APUC cautions that although it is believed that the assumptions are reasonable in the circumstances, these risks and uncertainties give rise to the possibility that actual results may differ materially from the expectations set out in the forward-looking statements. Material risk factors include those set out in this AIF under “Risk Factors. Readers are cautioned that such risks and uncertainties may cause APUC’s actual results to vary materially from those expressed in, or implied by, the forward-looking statements and information. Given these risks, undue reliance should not be placed on these forward-looking statements, which apply only as of their dates. Other than as specifically required by law, APUC undertakes no obligation to update any forward-looking statements or information to reflect new information, subsequent or otherwise.

SCHEDULE G

GLOSSARY OF TERMS

In this Annual Information Form, the following terms have the meanings set forth below, unless otherwise indicated.

“3793257” means 3793257 Canada Inc., a corporation incorporated under the CBCA. See “Corporate Structure – Intercorporate Relationships – Subsidiaries”.

“AAP LP” has the meaning ascribed thereto under “Corporate Structure – Intercorporate Relationships – Subsidiaries”.

“ADEQ” means the Arizona Department of Environmental Quality. See “Description of the Business – Production Method, Principal Markets, Distribution Methods and Material Facilities – Utilities: Water and Wastewater”.

“AES” means Algonquin Energy Services Inc., a Delaware corporation. See “Corporate Structure – Intercorporate Relationships – Subsidiaries”.

“AESO” means the Alberta Electric System Operator. See “Description of the Business – Production Method, Principal Markets, Distribution Methods and Material Facilities – Power Generation: Renewable – Hydroelectric”.

“Agreement” has the meaning ascribed thereto under “General Development of the Business—Recent Developments – 2012 – Corporate – Business Associations with APMI and Senior Executives”.

“AirSource” has the meaning ascribed thereto under “Corporate Structure – Intercorporate Relationships – Subsidiaries”.

“AirSource Senior Debt” has the meaning ascribed thereto under “General Development of the Business – Three Year History – Fiscal 2011”.

“Algonquin” or the “Fund” means Algonquin Power Income Fund. See “General Development of the Business – General – The Unit Exchange”.

“Algonquin Holdco” means Algonquin Power Fund (America) Holdco Inc., a Delaware corporation. See “Corporate Structure – Intercorporate Relationships – Subsidiaries”.

“APA” means Algonquin Power (America) Inc. See “Corporate Structure – Intercorporate Relationships – Subsidiaries”.

“APC” means Algonquin Power Corporation Inc. See “Description of the Business – Production Method, Principal Markets, Distribution Methods and Material Facilities – Power Generation: Renewable – Hydroelectric”.

“APCo” means Algonquin Power Co. See “Corporate Structure – Name, Address and Incorporation”.

“APCo Facility” has the meaning ascribed thereto under “General Development of the Business – Three Year History – Fiscal 2011”.

“APEFW” means Algonquin Power Energy From Waste Inc. See “Corporate Structure – Intercorporate Relationships – Subsidiaries”.

“APFA” means Algonquin Power Fund (America) Inc. See “Corporate Structure – Intercorporate Relationships – Subsidiaries”.

“APFC” means Algonquin Power Fund (Canada) Inc. See “Corporate Structure – Intercorporate Relationships – Subsidiaries”.

“APMI” means Algonquin Power Management Inc. See “General Development of the Business – Three Year History – Fiscal 2009”.

“APOT” means Algonquin Power Operating Trust. See “Corporate Structure – Intercorporate Relationships – Subsidiaries”.

“APT” means Algonquin Power Trust. See “Corporate Structure – Intercorporate Relationships – Subsidiaries”.

“APUC” or the “Corporation” means Algonquin Power & Utilities Corp including, for reporting purposes only, the direct or indirect subsidiaries of APUC and partnership interests held by APUC and its subsidiaries. See “Corporate Structure – Name, Address and Incorporation”.

“APUC Businesses” means the two businesses through which APUC primarily conducts its operations: independent power generation and utilities (water, gas and electric). See “General Development of the Business – General—Business Strategy”.

“Atmos” means ATMOS Energy Corporation. See “Corporate Structure – Intercorporate Relationships – Subsidiaries”.

“Audit Committee” means APUC’s audit committee. See “Directors and Officers – Audit Committee – Audit Committee Charter”.

“Avoided Costs” means costs a utility does not incur to add new generating capacity to the system by purchasing electricity from an independent or parallel generator. See “Description of the Business – General Description of the Regulatory Regimes in which the Business Operates – Power Generation Regulatory Regimes”.

“AWPH” means American Wind Portfolio Holdings LLC. See “General Development of the Business – Recent Developments – 2012”.

“BCI” means Brampton Cogeneration Inc.

“BCI Facility” has the meaning ascribed thereto under “Corporate Structure – Intercorporate Relationships – Subsidiaries”.

“Belle Rivière” has the meaning ascribed thereto under “Corporate Structure – Intercorporate Relationships – Subsidiaries”.

“Board” means the APUC Board of Directors.

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“By-Laws” means the by-laws of APUC.

“California Utility” has the meaning ascribed thereto under “General Development of the Business – Three Year History – Fiscal 2010”.

“Calpeco” means California Pacific Electric Company, LLC, a California limited liability company. See “Corporate Structure – Intercorporate Relationships – Subsidiaries”.

“Campbellford Facility” has the meaning ascribed thereto under “Corporate Structure – Intercorporate Relationships – Subsidiaries”.

“Campbellford LP” means Algonquin Power (Campbellford) Limited Partnership. See “Corporate Structure – Intercorporate Relationships – Subsidiaries”.

“Canadian ERs” means the updated Final Essential Requirements for Mandatory Reporting for use in Canadian Partner jurisdictions. See “Risk Factors – Operational Risk Management – Specific Environmental Risks”.

“Caribou Facility” has the meaning ascribed thereto under “General Development of the Business – Three Year History – Fiscal 2010”.

“CBCA” means the Canada Business Corporations Act.

“CC” means Compensation Committee. See “Directors and Officers – Corporate Governance and Compensation Committees”.

“CDP” means the Carbon Disclosure Project. See “Risk Factors – Operational Risk Management – Specific Environmental Risks”.

“CGC” means Corporate Governance Committee. See “Directors and Officers – Corporate Governance and Compensation Committees”.

“Change of Control” means the acquisition of voting control or direction over 66 2/3% or more of the outstanding Common Shares by any person or group of persons acting jointly or in concert. See “Description of Capital Structure – Convertible Debentures – Series 3 Debentures”.

“Chapais” means Chapais Energie, Société en Commandité. See “Corporate Structure – Intercorporate Relationships – Other Interests in Energy Related Developments”.

“Clarica” means The Clarica Life Insurance Company. See “Description of the Business – Production Method, Principal Markets, Distribution Methods and Material Facilities – Power Generation: Renewable – Hydroelectric”.

“CL&P” means the Connecticut Light and Power Company. See “Description of the Business – Production Method, Principal Markets, Distribution Methods and Material Facilities – Power Generation: Thermal – Cogeneration”.

“Cochrane” means Cochrane Power Corporation. See “Description of the Business – Production Method, Principal Markets, Distribution Methods and Material Facilities – Power Generation: Thermal – Cogeneration”.

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“COD” means commercial operation dates. See “General Development of the Business – Recent Developments – 2012”.

“Common Shares” means a new class of common shares created pursuant to a certificate and articles of arrangement dated October 27, 2009. See “Corporate Structure – Name, Address and Incorporation”.

“Corporation” means APUC.

“Corporation St-Laurent” has the meaning ascribed thereto under “Corporate Structure – Intercorporate Relationships – Subsidiaries”.

“Court Street” means Court Street Investments, Inc., a Massachusetts corporation. See “Corporate Structure – Intercorporate Relationships – Subsidiaries”.

“Co-Owners” means Algonquin Power (Long Sault) Partnership and N-R Power Partnership as co-owners of the Long Sault Rapids Facility. See “Description of the Business – Production Method, Principal Markets, Distribution Methods and Material Facilities – Power Generation: Renewable – Hydroelectric”.

“CPUV” means California Pacific Utilities Ventures, LLC, a California limited liability company. See “Corporate Structure – Intercorporate Relationships – Subsidiaries”.

“Current Market Price” is defined in the Series 3 Trust Indenture to mean the weighted average trading price of the Common Shares on the TSX for the 20 consecutive trading days ending on the fifth trading day preceding the date of the applicable event. See “Description of Capital Structure – Convertible Debentures – Series 3 Debentures”.

“DEP” means the US Department of Energy.

“Dickson Dam Facility” has the meaning ascribed thereto under “Corporate Structure – Intercorporate Relationships – Subsidiaries”.

“ECAC” means the Energy Cost Adjustment Clause. See “Description of the Business – Production Method, Principal Markets, Distribution Methods and Material Facilities – Liberty Utilities: Electrical Distribution”.

“EffiSolar” means EffiSolar Energy Corporation. See “General Development of the Business – Significant Acquisitions and Investments – 2011 – Cornwall Solar”.

“EFW Facility” has the meaning ascribed thereto under “Corporate Structure – Intercorporate Relationships – Subsidiaries”.

“Electricity Act” means the Electricity Act (New Brunswick). See “Description of the Business – Production Method, Principal Markets, Distribution Methods and Material Facilities – Power Generation: Renewable – Hydroelectric”.

“EnergyNorth” means EnergyNorth Natural Gas Inc. See “Corporate Structure – Intercorporate Relationships – Subsidiaries”.

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“Entrada” means Entrada Del Oro Sewer Company, Inc. See “Corporate Structure – Intercorporate Relationships – Subsidiaries”.

“Éoliennes” means Corporation D’Investissements Éoliennes Algonquin Power. See “Corporate Structure – Intercorporate Relationships – Subsidiaries”.

“EPA” means the Environmental Protection Agency.

“EPA Rule” means the final Mandatory Greenhouse Gas Reporting Rule. See “Risk Factors – Operational Risk Management – Specific Environmental Risks”.

“ERs” means the Final Essential Requirements for Mandatory Reporting. See “Risk Factors – Operational Risk Management – Specific Environmental Risks”.

“ESA” means energy services agreement. See “General Development of the Business – Three Year History – Fiscal 2011”.

“ESPP” means employee share purchase plan.

“EUA” means the Electric Utilities Act (Alberta). See “Description of the Business – Production Method, Principal Markets, Distribution Methods and Material Facilities – Power Generation: Renewable – Hydroelectric”.

“Event of Default” has the meaning ascribed thereto under “Description of Capital Structure – Convertible Debentures – Series 3 Debentures”.

“Federal Authorities” means, together, the Attorney General of Canada and Seaway Management. See “Legal Proceedings and Regulatory Actions – Legal Proceedings—Côte Ste-Catherine Water Lease Dues”.

“FERC” means the United States Federal Energy Regulatory Commission. See “Description of the Business – General Description of the Regulatory Regimes in which the Business Operates – Power Generation Regulatory Regimes”.

“First Wind” means First Wind Holdings, LLC. See “Material Contracts”.

“FIT” has the meaning ascribed thereto under “General Development of the Business – Significant Acquisitions and Investments – 2011 – Cornwall Solar”.

“Fleur de Lis LP” has the meaning ascribed thereto under “Corporate Structure – Intercorporate Relationships – Subsidiaries”.

“FPA” means the U.S. Federal Power Act.

“Gamesa” means Gamesa Corporación Tecnológica, S.A. See “General Development of the Business – Recent Developments – 2012”.

“gpd” means gallons per day. See “Description of the Business – Production Method, Principal Markets, Distribution Methods and Material Facilities – Utilities: Water and Wastewater”.

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“Granite State” means Granite State Electric Company. See “Corporate Structure – Intercorporate Relationships – Subsidiaries”.

“Green Power” means electricity generated from renewable energy sources that do not contribute to greenhouse gas emissions. See “Description of the Business – General Description of the Regulatory Regimes in which the Business Operates – Power Generation Regulatory Regimes”.

“HOEP” means Hourly Ontario Energy Price.

“ICC” means Illinois Commerce Commission.

“ISO-NE” means Independent System Operator New England. See “Description of the Business – Production Method, Principal Markets, Distribution Methods and Material Facilities – Power Generation: Thermal – Cogeneration”.

“ITC” means investment tax credit.

“IUB” means Iowa Utilities Board.

“Kineticor” has the meaning ascribed thereto under “Description of the Business – Production Method, Principal Markets, Distribution Methods and Material Facilities – Power Generation: Development”.

“Kirkland” means Kirkland Lake Power Corp. See “Description of the Business – Production Method, Principal Markets, Distribution Methods and Material Facilities – Power Generation: Thermal – Cogeneration”.

“Liberty Energy” means Liberty Energy Utilities Co. See “Corporate Structure – Intercorporate Relationships – Subsidiaries”.

“Liberty Energy (NH)” means Liberty Energy Utilities (New Hampshire) Corp., a Delaware corporation registered in New Hampshire. See “Corporate Structure – Intercorporate Relationships – Subsidiaries”.

“Liberty Facility” has the meaning ascribed thereto under “General Development of the Business – Recent Developments—2012”.

“Liberty Midstates” means Liberty Energy (Midstates) Corp., a Missouri corporation. See “Corporate Structure – Intercorporate Relationships – Subsidiaries”.

“Liberty Utilities” means Liberty Utilities Company. See “Corporate Structure – Name, Address and Incorporation”.

“Liberty Water” means Liberty Water Co., a Delaware company. See “Corporate Structure – Intercorporate Relationships – Subsidiaries”.

“Loyalist LP” has the meaning ascribed thereto under “Corporate Structure – Intercorporate Relationships – Subsidiaries”.

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“LSR Royalty Interest” means a royalty in the form of cash flows generated by the Long Sault Rapids Facility. See “Corporate Structure – Intercorporate Relationships – Other Interests in Energy Related Developments”.

“LSR Subordinate Note” has the meaning ascribed thereto under “Corporate Structure – Intercorporate Relationships – Other Interests in Energy Related Developments”.

“LU GP1” means Liberty Utilities Finance GP 1, a special purpose financing company and a Delaware general partnership. See “Corporate Structure – Intercorporate Relationships – Subsidiaries”.

“LU GP2” means Liberty Utilities Finance GP 2, a special purpose financing company and a Delaware general partnership. See “Corporate Structure – Intercorporate Relationships – Subsidiaries”.

“Manitoba Hydro” means the Manitoba Hydro-Electric Board.

“Meeting” means the annual general meeting held on June 23, 2010.

“Midwest Gas Utilities” means certain natural gas distribution utility assets located in Missouri, Iowa, and Illinois. See “General Development of the Business – Significant Acquisitions and Investments – 2011 – Midwest Gas Utility Acquisition”.

“Midwest Purchase Agreements” means the share purchase agreements by and between Atmos and Liberty Midstates entered into on May 12, 2011. See “General Development of the Business – Significant Acquisitions and Investments – 2011 – Midwest Gas Utility Acquisition”.

“MIPA” means Membership Interest Purchase and Sale Agreement. See “Material Contracts”.

“Ministry” means the Minister of Energy and Infrastructure. See “Description of the Business – Production Method, Principal Markets, Distribution Methods and Material Facilities – Power Generation: Development”.

“Mont-Laurier Partnership” means Algonquin Power (Mont-Laurier) Limited Partnership. See “Corporate Structure – Intercorporate Relationships – Subsidiaries”.

“MPS” means Maine Public Service Company.

“MPSC” means Missouri Public Service Commission.

“MW” means megawatt.

“National Grid” means National Grid USA. See “Corporate Structure – Intercorporate Relationships – Subsidiaries”.

“NB Power” means New Brunswick Power Corporation.

“NBSO” means New Brunswick System Operator. See “Description of the Business – Production Method, Principal Markets, Distribution Methods and Material Facilities – Power Generation: Renewable – Hydroelectric”.

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“NHPUC” means New Hampshire Public Utilities Commission.

“Northern Maine Gen Co.” means Algonquin Northern Maine Gen Co., a Wisconsin company. See “Corporate Structure – Intercorporate Relationships – Subsidiaries”.

“Northland” means Northland Power Inc. See “Description of the Business – Production Method, Principal Markets, Distribution Methods and Material Facilities – Power Generation: Thermal – Cogeneration”.

“NTP” means Notice to Proceed. See “Description of the Business – Production Method, Principal Markets, Distribution Methods and Material Facilities – Power Generation: Development”.

“OATT” means open access transmission tariff. See “Description of the Business – General Description of the Regulatory Regimes in which the Business Operates – Power Generation Regulatory Regimes”.

“OEB” means the Ontario Energy Board.

“OEFC” means Ontario Electric Financial Corporation.

“Offering” means a public offering completed by APUC on October 27, 2011 of 15,100,000 common shares at a price of $5.65 per share, for gross proceeds of approximately $85.3 million. See “General Development of the Business – Three Year History – Fiscal 2011”.

“Off-peak” means the hours other than On-peak hours. See “Description of the Business – Production Method, Principal Markets, Distribution Methods and Material Facilities – Power Generation: Renewable – Hydroelectric”.

“On-peak” means between 7:00 a.m. and 11:00 p.m., local time, Monday to Friday, inclusive, but excluding public holidays. See “Description of the Business – Production Method, Principal Markets, Distribution Methods and Material Facilities – Power Generation: Renewable – Hydroelectric”.

“Parties” has the meaning ascribed thereto under “General Development of the Business—Recent Developments – 2012 – Corporate – Business Associations with APMI and Senior Executives”.

“Peel” means the Regional Municipality of Peel, Ontario.

“PG&E” means Pacific Gas & Electric Company. See “Description of the Business – Production Method, Principal Markets, Distribution Methods and Material Facilities – Power Generation: Thermal – Cogeneration”.

“Plan Shares” has the meaning ascribed thereto under “Dividends – Dividend Reinvestment Plan.”

“Power Pool” means the Power Pool of Alberta. See “Description of the Business – Production Method, Principal Markets, Distribution Methods and Material Facilities – Power Generation: Renewable – Hydroelectric”.

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“Power Sales Contracts” has the meaning ascribed thereto under “General Development of the Business – Recent Developments—2012”.

“PPAs” means long term power purchase agreements. See “General Development of the Business – General – Business Strategy”.

“Projects” means the four wind power projects in the United States acquired by APCo from Gamesa. See “General Development of the Business – Recent Developments—2012”.

“PTAM” means the Post Test Year Adjustment Mechanism. See “Description of the Business – Production Method, Principal Markets, Distribution Methods and Material Facilities – Liberty Utilities: Electrical Distribution”.

“Purchase Agreement” means the asset purchase agreement by and between Sierra Pacific Power Company d/b/a NV Energy and Calpeco dated April 22, 2009 in relation to the California Utility. See “General Development of the Business – Three Year History – Fiscal 2010”.

“Purchase Agreements” means the share purchase agreements by and between National Grid and Liberty Energy entered into on December 8, 2010 and amended and restated on January 11, 2011. See “General Development of the Business – Three Year History – Fiscal 2010”.

“Put Date” has the meaning ascribed thereto under “Description of Capital Structure – Convertible Debentures – Series 3 Debentures”.

“Put Price” has the meaning ascribed thereto under “Description of Capital Structure – Convertible Debentures – Series 3 Debentures”.

“QFs” means Qualifying Facilities. See “Description of the Business – General Description of the Regulatory Regimes in which the Business Operates – Power Generation Regulatory Regimes”.

“QF Status” means Qualifying Facility status. See “Risk Factors – Regulatory Climate and Permitting Risks – APCo”.

“Québec AG” means the Attorney General of Québec. See “Risk Factors – Legal Proceedings—Côte Ste-Catherine Water Lease Dues”.

“PURPA” means the Public Utilities Regulatory Policies Act. See “Description of the Business – General Description of the Regulatory Regimes in which the Business Operates – Power Generation Regulatory Regimes”.

“Red Lily I” means a 26.4 MW wind generation facility in southeastern Saskatchewan. “General Development of the Business – Significant Acquisitions and Investments – 2011 – Red Lily Wind Project”.

“Redemption Date” means May 16, 2011. See “General Development of the Business – Three Year History – Fiscal 2011”.

“Region” means the Region of Peel.

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“Reinvestment Plan” has the meaning ascribed thereto under “Dividends – Dividend Reinvestment Plan.”

“RGGI” means the Regional Greenhouse Gas Initiative. See “Risk Factors – Operational Risk Management – Specific Environmental Risks”.

“Rights Plan” means APUC’s Shareholders’ Rights Plan adopted at the Meeting. See “General Development of the Business – Three Year History – Fiscal 2010”.

“RPPI” means the Renewable Power Production Incentive program. See “Description of the Business – General Description of the Regulatory Regimes in which the Business Operates – Power Generation Regulatory Regimes”.

“run of the river” means a facility where there is a continuous discharge of water without storage and release of water. See “Description of the Business – Production Method, Principal Markets, Distribution Methods and Material Facilities – Power Generation: Renewable – Hydroelectric”.

“S.E.N.C.” has the meaning ascribed thereto under “Corporate Structure – Intercorporate Relationships – Subsidiaries”.

“Sanger LLC” means Algonquin Power Sanger LLC, a California limited liability company. See “Corporate Structure – Intercorporate Relationships – Subsidiaries”.

“Seaway Management” means The St. Lawrence Seaway Management Corporation. See “Risk Factors – Legal Proceedings—Côte Ste-Catherine Water Lease Dues”.

“Senior Indebtedness” has the meaning ascribed thereto under “Description of Capital Structure – Convertible Debentures – Series 3 Debentures”.

“Senior Indebtedness Postponement Provisions” has the meaning ascribed thereto under “Description of Capital Structure – Convertible Debentures – Series 3 Debentures”.

“Senior Executives” means two executives of APUC, Ian Robertson and Christopher Jarratt. See “Corporate Structure – Intercorporate Relationships – Subsidiaries”.

“Senior Unsecured Debentures” means $135 million in senior unsecured debentures issued by APCo on July 25, 2011 by way of private placement. See “General Development of the Business – Three Year History – Fiscal 2011”.

“Series 1A Debentures” means the 7.50% convertible unsecured subordinated debentures issued by the Corporation in connection with the Unit Exchange on October 27, 2009 due 2014. See “General Development of the Business – Three Year History – Fiscal 2011”.

“Series 2A Debentures” means APUC’s 6.35% convertible unsecured subordinated debentures due November 30, 2016. See “General Development of the Business – Recent Developments – 2012”.

“Series 2A Redemption Date” means February 24, 2012. See “General Development of the Business – Recent Developments – 2012”.

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“Series 3 Conversion Price” means $4.20 per Common Share. See “Description of Capital Structure – Convertible Debentures – Series 3 Debentures”.

“Series 3 Debentures” or the “APUC Debentures” means a public offering completed on December 2, 2009 of approximately $55 million principal amount of 7% convertible unsecured subordinated debentures due June 30, 2017. See “General Development of the Business – Three Year History – Fiscal 2009”.

“Series 3 Interest Payment Date” means June 30 and December 31 in each year, commencing on June 30, 2010. See “Description of Capital Structure – Convertible Debentures – Series 3 Debentures”.

“Series 3 Maturity Date” has the meaning ascribed thereto under “Description of Capital Structure – Convertible Debentures – Series 3 Debentures”.

“Series 3 Trust Indenture” means the trust indenture dated as of December 2, 2009 between APUC and the Debenture Trustee. See “Description of Capital Structure – Convertible Debentures”.

“Shareholders” means registered holders of shares of APUC. See “Dividends – Dividend Reinvestment Plan.”.

“Squa Pan Facility” has the meaning ascribed thereto under “General Development of the Business – Three Year History – Fiscal 2010”.

“St. Leon Facility” has the meaning ascribed thereto under “Corporate Structure – Intercorporate Relationships – Subsidiaries”.

“St. Leon II” has the meaning ascribed thereto under “Corporate Structure – Intercorporate Relationships – Subsidiaries”.

“St. Leon II Facility” has the meaning ascribed thereto under “Corporate Structure – Intercorporate Relationships – Subsidiaries”.

“St. Leon GP” has the meaning ascribed thereto under “Corporate Structure – Intercorporate Relationships – Subsidiaries”.

“St. Leon LP” has the meaning ascribed thereto under “Corporate Structure – Intercorporate Relationships – Subsidiaries”.

“St. Leon Trust” has the meaning ascribed thereto under “Corporate Structure – Intercorporate Relationships – Subsidiaries”.

“St. Ulrich LP” has the meaning ascribed thereto under “Corporate Structure – Intercorporate Relationships – Subsidiaries”.

“Strategic Agreement” means the strategic investment agreement between APUC and Emera entered into on April 29, 2011. See “General Development of the Business – Three Year History – Fiscal 2011”.

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“Subscription Agreement” has the meaning ascribed thereto under “General Development of the Business – Significant Acquisitions and Investments – 2011 – California Utility Acquisition”.

“Subscription Agreement (Calpeco)” has the meaning ascribed thereto under “Description of Capital Structure – Common Shares”.

“Subscription Agreement (National Grid)” has the meaning ascribed thereto under “General Development of the Business – Significant Acquisitions and Investments – 2011 – New Hampshire Utility Acquisition”

“TCE” means trichloroethylene. See “Risk Factors – Operational Risk Management – Specific Environmental Risks”.

“TCEQ” means the Texas Commission on Environmental Quality. See “Description of the Business – Production Method, Principal Markets, Distribution Methods and Material Facilities – Utilities: Water and Wastewater”.

“Tinker Facility” has the meaning ascribed thereto under “General Development of the Business – Three Year History – Fiscal 2010”.

“Tinker Assets” means the 36.8MW of electrical generating assets of Tinker Gen Co. in New Brunswick. See “Corporate Structure – Intercorporate Relationships – Subsidiaries”.

“Tinker Gen Co.” means Algonquin Tinker Gen Co., a Wisconsin company. See “Corporate Structure – Intercorporate Relationships – Subsidiaries”.

“TMO” means Transition Management Office. See “Risk Factors – Acquisitions and Divestitures – Transition Management Office”.

“Trafalgar” has the meaning ascribed thereto under “General Development of the Business—Recent Developments – 2012 – Corporate – Business Associations with APMI and Senior Executives – Trafalgar”.

“Treasury Purchase” means newly issued Plan Shares purchased from APUC under the Reinvestment Plan. See “Dividends – Dividend Reinvestment Plan”.

“Trust Units” has the meaning ascribed thereto under “Corporate Structure – Name, Address and Incorporation”.

“Unit Exchange” has the meaning ascribed thereto under “General Development of the Business – General – The Unit Exchange”.

“Valley Power Facility” has the meaning ascribed thereto under “Corporate Structure – Intercorporate Relationships – Subsidiaries”.

“Vestas” means Vestas-Canadian Wind Technology, Inc. See “Description of the Business – Production Method, Principal Markets, Distribution Methods and Material Facilities – Power Generation: Renewable – Wind Power”.

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“Water Services” means Algonquin Water Services LLC. See “Corporate Structure – Intercorporate Relationships – Subsidiaries”.

“Wind Farm Buyer” means APFA. See “Material Contracts”.

“Wind Farm Seller” means Gamesa Energy USA, LLC, a Delaware limited liability company. See “Material Contracts”.

“Windlectric” means Windlectric Inc. See “Corporate Structure – Intercorporate Relationships – Subsidiaries”.

“Windsor LLC” means Algonquin Power Windsor Locks LLC, a Connecticut limited liability company. See “Corporate Structure – Intercorporate Relationships – Subsidiaries”.

“WPPI” means Wind Power Production Incentive. See “Description of the Business – Production Method, Principal Markets, Distribution Methods and Material Facilities – Power Generation: Renewable – Wind Power”.

“Yankee Gas” means the Yankee Gas Service Company. See “Description of the Business – Production Method, Principal Markets, Distribution Methods and Material Facilities – Power Generation: Thermal – Cogeneration”.

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