Algonquin Power & Utilities 40F 2010 Annual report | AQN Filing

Exhibit 99.3

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Management’s Discussion and Analysis

(All figures are in thousands of Canadian dollars, except per share and convertible debenture amounts or where otherwise noted)

Management of Algonquin Power & Utilities Corp. (“APUC”), the corporation continuing the business of Algonquin Power Co. (“Algonquin”), formerly Algonquin Power Income Fund (the “Fund”), has prepared the following discussion and analysis to provide information to assist its shareholders’ understanding of the financial results for the three and twelve months ended December 31, 2010. This Management’s Discussion and Analysis (“MD&A”) should be read in conjunction with APUC’s audited consolidated financial statements for the years ended December 31, 2010 and 2009. This material is available on SEDAR atwww.sedar.com and on the APUC website atwww.AlgonquinPowerandUtilities.com. Additional information about APUC, including the most recent Annual Information Form (“AIF”) can be found on SEDAR atwww.sedar.com.

This MD&A is based on information available to management as of March 2, 2011.

Caution concerning forward-looking statements and non-GAAP Measures

Certain statements included herein contain forward-looking information within the meaning of certain securities laws. These statements reflect the views of APUC with respect to future events, based upon assumptions relating to, among others, the performance of APUC’s assets and the business, interest and exchange rates, commodity market prices, and the financial and regulatory climate in which it operates. These forward looking statements include, among others, statements with respect to the expected performance of APUC, its future plans and its dividends to shareholders. Statements containing expressions such as “anticipates”, “believes”, “continues”, “could”, “expect”, “estimates”, “intends”, “may”, “outlook”, “plans”, “project”, “strives”, “will”, and similar expressions generally constitute forward-looking statements.

Since forward-looking statements relate to future events and conditions, by their very nature they require APUC to make assumptions and involve inherent risks and uncertainties. APUC cautions that although it believes its 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 the impact of movements in exchange rates and interest rates; the effects of changes in environmental and other laws and regulatory policy applicable to the energy and utilities sectors; decisions taken by regulators on monetary policy; and the state of the Canadian and the United States (“U.S.”) economies and accompanying business climate. APUC cautions that this list is not exhaustive, and other factors could adversely affect results. Given these risks, undue reliance should not be placed on these forward-looking statements, which apply only as of their dates. APUC reviews material forward-looking information it has presented, at a minimum, on a quarterly basis. APUC is not obligated to nor does it intend to update or revise any forward-looking statements, whether as a result of new information, future developments or otherwise, except as required by law.

The terms “adjusted net earnings” and “adjusted earnings before interest, taxes, depreciation and amortization” (“Adjusted EBITDA”) are used throughout this MD&A. The terms “adjusted net earnings” and Adjusted EBITDA are not recognized measures under Canadian generally accepted accounting principles (“GAAP”). There is no standardized measure of “adjusted net earnings” and Adjusted EBITDA, consequently APUC’s method of calculating these measures may differ from methods used by other companies and therefore may not be comparable to similar measures presented by other companies. A calculation and analysis of “adjusted net earnings” and Adjusted EBITDA can be found throughout this MD&A.

Conversion to a Corporation

On October 27, 2009, Algonquin completed a transaction (the “Unit Exchange Offer”) which provided Algonquin’s unitholders the opportunity to exchange their trust units of Algonquin, on a one-for-one basis, for common shares of an existing corporation. This existing corporation, Hydrogenics Corporation, transferred all of its operations and existing shares to a new corporation pursuant to a Plan of Arrangement prior to completion of the Unit Exchange Offer. The name of Hydrogenics Corporation was changed to Algonquin Power & Utilities Corp. following closing of the transaction.

The transaction resulted in the unitholders of Algonquin becoming shareholders of APUC, with no changes to Algonquin’s underlying business operations. Under the continuity of interest method of accounting, APUC’s transfer of assets, liabilities and equity of Algonquin are recorded at their net book value in APUC’s financial statements as at October 27, 2009. As a result of this conversion, certain terms such as shareholder/unitholder and dividend/distribution may be used interchangeably throughout this MD&A. Prior to October 27, 2009, all distributions to unitholders were in the form of trust unit distributions. References to APUC shall mean Algonquin with respect to activities and results occurring prior to October 27, 2009 and shall mean APUC with respect to activities and results occurring on or after October 27, 2009.

Overview

APUC is incorporated under the Canada Business Corporations Act. APUC currently conducts its business primarily through two separate and autonomous subsidiaries: Algonquin Power Co. (“APCo”) owns and operates a diversified portfolio of renewable energy assets and Liberty Utilities Co. (“Liberty Utilities”) owns and operates a portfolio of North American utilities.

APCo generates and sells electrical energy through a diverse portfolio of clean, renewable power generation and thermal power generation facilities across North America. As at December 31, 2010, APCo owns or has interests in 44 hydroelectric facilities operating in Ontario, Québec, Newfoundland, Alberta, New Brunswick, New York State, New Hampshire, Vermont, Maine and New Jersey with a combined generating capacity of approximately 165 MW. APCo also owns a 104 MW wind powered generating station in Manitoba and holds debt securities in a 26 MW wind powered generating station recently completed in Saskatchewan. The renewable energy facilities generally sell their electrical output pursuant to long term power purchase agreements (“PPAs”) with major utilities and have a weighted average remaining contract life of 16 years. Similarly, the 12 thermal energy facilities that APCo has an ownership and interest in operate under PPAs and have a weighted average remaining contract life of 6 years with a combined generating capacity of approximately 210 MW¹.

Liberty Utilities provides utility services related to electricity, natural gas, water and wastewater services. Liberty Water Co. (“Liberty Water”), a subsidiary of Liberty Utilities, provides water and wastewater utility services to approximately 75,000 customers through 19 water distribution and wastewater collection and treatment utility systems located in four U.S. States (Arizona, Illinois, Missouri and Texas). These utilities operate under rate regulation, generally overseen by the public utility commissions of the States in which they operate.

Liberty Energy Utilities Co. (“Liberty Energy”), a subsidiary of Liberty Utilities, provides local electrical and natural gas utility services. On January 1, 2011, in partnership with Emera Inc. (“Emera”), Liberty Energy acquired a California-based electricity distribution utility and related generation assets, and now provides electric distribution service to approximately 47,000 customers in the Lake Tahoe region (the “California Utility”). Liberty Energy has entered into agreements to acquire two additional utilities which currently provide electric and natural gas distribution services to approximately 125,000 customers in New Hampshire.

Business Strategy

APUC’s business strategy is to maximize long term shareholder value as a dividend paying, growth-oriented corporation in the power and utilities business sectors. APUC is committed to delivering a total shareholder return comprised of dividends augmented by capital appreciation arising through growth in dividends supported

During the fourth quarter, APCo determined that the generating capacity reported for each of its facilities was more appropriately reported based on APCo’s effective percentage ownership interest in the facility, rather than the total installed capacity of the facility; as a result, the generating capacity values set out in respect of some of the facilities included in APCo’s generating portfolio have been reduced from prior periods

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 5% and to grow its dividend supported by growth in cash flows, earnings and investment prospects.

APUC understands the importance of the dividend to its shareholders. APUC currently pays quarterly cash dividends to shareholders of $0.06 per share or $0.24 per share per annum. On March 3, 2011, the Board of Directors of APUC (the “Board”) approved an annual dividend increase of $0.02 per common share for a total annual dividend of $0.26, paid quarterly at a rate of $0.065 per common share. The Board also declared a dividend of $0.065 per share payable on April 15, 2011 to the shareholders of record on March 31, 2011.

APUC believes this level of dividends will continue to allow 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. Any increases in the level of dividends paid by APUC will be at the discretion of the Board and dividend levels shall be reviewed periodically by the Board in the context of cash available for distribution and earnings together with an assessment of the growth prospects available to the Company. APUC strives to achieve its results within a moderate risk profile consistent with top-quartile North American power and utility operations.

Independent Power:APCo develops, owns and operates a diversified portfolio of electrical energy generation facilities. Within this business there are three distinct divisions: Renewable Energy, Thermal Energy and Development. The Renewable Energy division operates APCo’s hydroelectric and wind power facilities. The Thermal Energy division operates co-generation, energy-from-waste, and steam production facilities. The Development division seeks to deliver continuing growth to APCo through development of APCo’s greenfield power generation projects, accretive acquisitions of electrical energy generation facilities as well as development of organic growth opportunities within APCo’s existing portfolio of renewable energy and thermal energy facilities.

Utilities: Liberty Utilities owns and operates utilities through its two wholly-owned subsidiaries, Liberty Energy and Liberty Water, in the electricity distribution, transmission and generation as well as natural gas distribution, water distribution and wastewater treatment sectors. These utilities share certain common infrastructure to generate economies of scale to support best-in-class customer care for its utility ratepayers. 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 its utility 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 accretively expand its business portfolio.

Major Highlights

Liberty Water Rate Cases

During the year ended December 31, 2010, Liberty Water completed rate case proceedings at nine utilities in Arizona and Texas which on an annualized basis are expected to contribute an additional U.S. $10.2 million in revenue in Liberty Water. 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 is expected to be concluded by the first quarter of 2011.

California Utility Acquisition and Senior Debt Financing

On January 1, 2011, following receipt of all U.S. state and federal regulatory approvals, APUC announced that, in partnership with Emera, Liberty Energy had acquired the assets comprising the California Utility. Liberty Energy 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, California Pacific Electric Company (“Calpeco”).

The acquisition of the California Utility was completed for a gross purchase price of approximately U.S. $131.8 million, subject to certain working capital and other closing adjustments. Upon closing, Emera exchanged previously announced subscription receipts into 8.532 million APUC common shares at a purchase price of $3.25 per share. The proceeds of the subscription receipts were utilized to fund Liberty Energy’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. 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.

Granite State/EnergyNorth Acquisition

On December 9th, 2010 APUC announced that Liberty Energy had entered into agreements to acquire all issued and outstanding shares of Granite State Electric Company (“Granite State”), a regulated electric distribution utility, and EnergyNorth Natural Gas, Inc. (“EnergyNorth”), a regulated natural gas distribution utility from National Grid USA (“National Grid”) for total consideration of U.S. $285.0 million.

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.

Closings of the transactions are subject to certain conditions including state and federal regulatory approval, and are expected to occur in the fall of 2011. 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. In connection with these acquisitions, Emera has committed to a treasury subscription of subscription receipts convertible into 12.0 million APUC common shares upon closing of the transactions at a purchase price of $5.00 per share representing an approximate 5% premium to APUC’s closing share price on December 8, 2010. The issuance of these subscription receipts is subject to regulatory approval.

Red Lily Wind Project

On February 28, 2011 APUC announced that the 26.4 MW wind generation facility in southeastern Saskatchewan (“Red Lily I”) commenced commercial operation under the PPA. APUC’s commitment 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, such interest payments and fees are expected to be approximately $2.4 million. APUC has the option to formally exchange its debt investment for a 75% equity position in the facility in 2016. SeeRenewable Energy - Divisional Outlookfor more discussion of this project.

New Wind Projects Under Development

75 MW Wind - Amherst Island:On February 25, 2011 APUC announced that the Ontario Power Authority (“OPA”) awarded a contract to the wholly owned 75 MW Amherst Island Wind Project, located on Amherst Island in the village of Stella, approximately 25 kilometers southwest of Kingston, Ontario. The contract was awarded as part of the second round of the OPA’s Feed-in Tariff (“FIT”) program.

The project, which will be developed by APCo, is currently contemplated to use more efficient Class III wind turbine generator technology that is estimated to produce approximately 247 GW-hrs of power annually. Funding of the total capital costs, currently estimated to be $220 million, will be arranged and announced when all required permitting and all other pre-construction conditions have been satisfied. 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 months.

On December 21st, 2010 APUC announced that Hydro-Québec Distribution has accepted proposals for the purchase of energy from the 24 MW Saint-Damase and 24 MW Val-Éo wind power generating projects. The projects were submitted with support from APUC in response to the community based call for offers announced in the spring of 2009.

25MW Wind - 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 APUC. The first 24 MW phase of the project is currently envisioned to consist of twelve 2 MW ENERCON Canada Inc. (“ENERCON”) E-82 wind turbine generators, producing approximately

86,000 MWh 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.

25 MW Wind - 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 APUC. The first 24 MW phase of the project is expected to be comprised of eight 3 MW ENERCON E-101 wind turbine generators, producing approximately 66,000 MW-hrs 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 interests of APUC in the Saint-Damase and Val- Éo projects is subject to final negotiations with the partners in the projects but, in any event, will not be less than 50% and 25%, respectively. Final funding of the projects will be arranged and announced when all required permitting has been met, and all other pre-construction conditions have been satisfied. Preliminary permitting began for both projects in early 2011, with all major authorizations targeted for completion by the end of 2012.

Credit Facility Renewal

On January 14, 2011 APUC announced that it has received commitments with a syndicate of banks for a new Algonquin Power Co. $142 million senior secured revolving credit Facility (“Facility”) with a three year term. The Facility syndicate is being led by National Bank of Canada. The other syndicate members are The Toronto-Dominion Bank, Bank of Montreal, and Canadian Imperial Bank of Commerce.

Liberty Water Senior Debt Financing

On December 22, 2010 Liberty Water entered into a U.S. $50 million private placement debt financing. The notes are senior unsecured with a 10 year term bearing interest at 5.6%. The notes are interest only 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.

2010 Annual results from operations

Key Selected Annual Financial Information


	Year ended December 31
	2010		2009		2008

Revenue	$	182,882	$	187,265	$	213,796

Adjusted EBITDA²	$	75,107	$	79,368		90,028

Cash provided by Operating Activities		45,180		48,031		77,223

Net earnings		19,639		31,257		(19,038	)

Adjusted net earnings³		19,915		30,503		18,788

Dividend/distributions to Shareholders/Unitholders¹		22,765		19,322		57,755

Per share/trust unit
Net earnings	$	0.21	$	0.39		(0.25	)
Adjusted net earnings³	$	0.21	$	0.38		0.25
Diluted net earnings	$	0.21	$	0.39		(0.25	)
Cash provided by Operating Activities	$	0.48	$	0.60		1.03
Dividends/distributions to Shareholders/Unitholders	$	0.24	$	0.24		0.75

Total Assets		980,917		1,013,413		978,515
Long Term Debt⁴		257,429		241,412		293,590

¹	Includes dividends/distributions to APUC shareholders/unitholders and Airsource units exchangeable into APCo trust units.

APUC uses Adjusted EBITDA to enhance assessment and understanding of the operating performance of APUC without the effects of depreciation and amortization expense which are derived from a number of non-operating factors, accounting methods and assumptions. Adjusted EBITDA is a non-GAAP measure - see applicable section later in this MD&A and the caution regarding non-GAAP measures on page 1.

APUC uses Adjusted net earnings to enhance assessment and understanding of the performance of APUC without the effects of gains or losses on derivative financial instruments which are derived from a number of non-operating factors, accounting methods and assumptions. Adjusted net earnings is a non-GAAP measure - see applicable section later in this MD&A and the caution regarding non-GAAP measures on page 1.

⁴	Includes the Airsource Senior Debt Financing which matures on October 31, 2011 and has been recorded as a current liability on the consolidated balance sheet.

For the year ended December 31, 2010, APUC reported total revenue of $182.9 million as compared to $187.3 million during the same period in 2009, a decrease of $4.4 million or 2.3%. The major factors resulting in the decrease in APUC revenue in the year ended December 31, 2010 as compared to the corresponding period in 2009, are set out as follows:


	Year ended
	December 31, 2010

Comparative Prior Period Revenue	$	187,265

Significant Changes:
Impact of the stronger Canadian dollar		(10,100	)
Impact of shutdown at Energy-from-Waste facility		(5,300	)
Effect of hydrology compared to prior year		(4,800	)
Change in operating model at Windsor Locks		(3,800	)
Closure of land fill gas facilities		(1,100	)
Acquisition of Tinker Hydro in Q1 2010		17,800
Red Lily I – development, construction and supervision fees		2,100
Liberty Water revenue increases primarily due to rate case approvals		2,800
All Other		(1,983	)


Current Period Revenue	$	182,882

A more detailed discussion of these factors is presented within the business unit analysis.

For the year ended December 31, 2010, APUC experienced an average U.S. exchange rate of approximately $1.030 as compared to $1.142 in the same period in 2009. As such, any year over year variance in revenue or expenses, in local currency, at any of APUC’s U.S. entities are affected by a change in the average exchange rate, upon conversion to APUC’s reporting currency.

Adjusted EBITDA in the year ended December 31, 2010 totalled $75.1 million as compared to $79.4 million during the same period in 2009, a decrease of $4.3 million or 5.4%. The decrease in Adjusted EBITDA is in part due to lower earnings from operations primarily resulting from lower average hydrology and wind resources in the Renewable Energy division and the impact of the outage at the Energy-From-Waste (“EFW”) facility, partially offset by the acquisition of 36.8 MW of electrical generating assets located in New Brunswick and Maine (the “Tinker Assets”) and the completion of various rate case proceedings in Liberty Water as compared to the same period in 2009. A more detailed analysis of these factors is presented within the reconciliation of Adjusted EBITDA to net earnings set out below (see Non-GAAP Performance Measures).

For the year ended December 31, 2010, net earnings totalled $19.6 million as compared to $31.3 million during the same period in 2009, a decrease of $11.6 million or 37.2%. Net earnings per share totalled $0.21 for the year ended December 31, 2010, as compared to net earnings per trust unit of $0.39 during the same period in 2009.

Net earnings for the year ended December 31, 2010 decreased by $4.2 million due to increased interest expense, $1.4 million in reduced interest dividend and other income primarily due to gains on the sale of excess land earned in 2009, $0.8 million due to lower earnings from operating facilities, $0.7 million due to lower non-cash gains on U.S. denominated liabilities resulting from the stronger Canadian dollar and $3.3 million due to increased management and administration expense as compared to the same period in 2009. These items were partially offset by an increase of $4.0 million related to lower write downs of property plant and equipment and note receivables, $1.8 million related to increased recoveries of future income tax expense primarily due to the reasons discussed inAnnual Corporate and Other Expenses – Income Taxes, $2.3 million resulting from reduced minority interest expense at the St. Leon facility primarily due to the lower wind resource experienced in the year ended December 31, 2010 as compared to the same period in 2009. In the comparable period, APUC incurred expenses of $4.7 million related to management internalization and $3.5 million related to corporatization expenses which were not incurred in the current period.

The decrease in net earnings was impacted by a change in unrealized mark-to-market gains on derivative financial instruments which reduced earnings by $16.0 million in the year ended December 31, 2010 as compared to 2009, as a result of changes in the forward interest rate curve and the stronger Canadian dollar, in addition to an expense increase of $2.5 million related to realized losses on derivative financial instruments contracts settled in the period. A more detailed analysis of realized and unrealized mark-to-market gains and losses on foreign exchange contracts and interest swap contracts can be found later in this report underTreasury Risk Management - Foreign currency risk.

During the year ended December 31, 2010, cash provided by operating activities totalled $45.2 million or $0.48 per share as compared to cash provided by operating activities of $48.0 million, or $0.60 per share during the same period in 2009. Cash provided by operating activities exceeded dividends declared by 2.0 times during the year ended December 31, 2010 as compared to 2.5 times dividends/distributions declared during the same period in 2009. The change in cash provided by operating activities after changes in working capital in the year ended December 31, 2010 is primarily due to increased realized losses from derivative instruments, increased interest expense and decreased cash flow from operating facilities as compared to the same period in 2009.

2010 Fourth quarter results from operations

Key Selected Fourth Quarter Financial Information


	Three months ended December 31
	2010		2009

Revenue	$	48,874	$	43,441

Adjusted EBITDA²	$	20,693	$	18,027

Cash provided by Operating Activities		18,299		11,894

Net earnings		16,888		(1,366	)

Adjusted net earnings³		18,034		11,504

Dividend/distributions to Shareholders/Unitholders¹		5,725		4,998

Per share/trust unit
Net earnings	$	0.18	$	(0.03	)
Adjusted net earnings³	$	0.19	$	0.14
Diluted net earnings	$	0.18	$	(0.03	)
Cash provided by Operating Activities	$	0.19	$	0.15
Dividends/distributions to Shareholders/Unitholders	$	0.06	$	0.06

Total Assets		980,917		1,013,413
Long Term Debt⁴		257,429		241,421

¹	Includes dividends/distributions to APUC shareholders/unitholders and Airsource units exchangeable into APCo trust units.

⁴	Includes the Airsource Senior Debt Financing which matures on October 31, 2011 and has been recorded as a current liability on the consolidated balance sheet.

For the three months ended December 31, 2010, APUC reported total revenue of $48.9 million as compared to $43.4 million during the same period in 2009, an increase of $5.4 million or 12.5%. The major factors resulting in the increase in APUC revenue in the three months ended December 31, 2010 as compared to the corresponding period in 2009 are set out as follows:


	Three months ended
	December 31, 2010

Comparative Prior Period Revenue	$	43,441

Significant Changes:
Acquisition of Tinker Hydro in Q1 2010		4,200
Liberty Water revenue increases primarily due to rate case approvals		1,400
Impact of shutdown at Energy-from-Waste facility		600
Effect of wind resource compared to prior year		600
Red Lily I – development, construction and supervision fees		600
Effect of hydrology compared to prior year		500
Change in operating model at Windsor Locks		(800	)
Impact of the stronger Canadian dollar		(900	)
Other		(767	)


Current Period Revenue	$	48,874

A more detailed discussion of these factors is presented within the business unit analysis.

For the three months ended December 31, 2010, APUC experienced an average U.S. exchange rate of approximately $1.032 as compared to $1.057 in the same period in 2009. As such, any year over year variance in revenue or expenses, in local currency, at any of APUC’s U.S. entities are affected by a change in the average exchange rate, upon conversion to APUC’s reporting currency.

Adjusted EBITDA in the three months ended December 31, 2010 totalled $20.7 million as compared to $18.0 million during the same period in 2009, an increase of $2.7 million or 14.8%. The increase in Adjusted EBITDA

is in part due to increased earnings from operations primarily resulting from the acquisition of the Tinker Assets and increased revenues from Liberty Water resulting from the completion of rate cases, partially offset by lower average hydrology in the Renewable Energy division and the impact of the stronger Canadian dollar as compared to the same period in 2009. A more detailed analysis of these factors is presented within the reconciliation of Adjusted EBITDA to net earnings set out below (see Non-GAAP Performance Measures).

For the three months ended December 31, 2010, net earnings totalled $16.9 million as compared to net loss of $1.4 million during the same period in 2009, an increase of $18.3 million. Net earnings per share totalled $0.18 for the three months ended December 31, 2010, as compared to net loss per share of $0.03 during the same period in 2009.

Net earnings for the three months ended December 31, 2010 increased by $5.4 million due to increased earnings from operating facilities, $4.9 million related to increased recoveries of income tax expense primarily due to the reasons discussed inAnnual Corporate and Other Expenses – Income Taxes, and $4.0 million related to lower write downs of property plant and equipment and note receivables, as compared to the same period in 2009. These items were partially offset by increased expenses of $2.4 million due to increased management and administration expense, $1.1 million due to increased interest expense, $0.6 million due to increased amortization expense and $0.2 million due to lower non-cash gains on U.S. denominated liabilities resulting from the stronger Canadian dollar as compared to the same period in 2009. In the comparable period, APUC incurred expenses of $4.7 million related to management internalization, $3.5 related to corporatization expenses which were not incurred in the current period.

The change in unrealized mark-to-market losses/(gains) on derivative financial instruments resulting from changes in foreign exchange rates relate to contract periods which extend to fiscal 2013. Unrealized mark-to-market losses on derivative financial instruments resulting from changes in interest rates relate to contract periods which extend to fiscal 2015. A more detailed analysis of realized and unrealized mark to market gains and losses on foreign exchange contracts and interest swap contracts can be found later in this report underTreasury Risk Management - Foreign currency risk.

During the three months ended December 31, 2010, cash provided by operating activities totalled $18.3 million or $0.19 per share as compared to cash provided by operating activities of $11.9 million, or $0.15 per trust unit during the same period in 2009. Cash provided by operating activities exceeded dividends declared by 3.2 times during the quarter ended December 31, 2010 as compared to 2.4 times distributions during the same period in 2009. The change in cash provided by operating activities after changes in working capital in the three months ended December 31, 2010, is primarily due to increased cash from operations, partially offset by increased interest expense and increased management and administration expense as compared to the same period in 2009.

Outlook

APCo

The APCo Renewable Energy division is expected to perform at long-term average resource conditions for hydrology and below average wind resources in the first quarter of 2011.

APCo’s load supply and energy procurement contracts in northern Maine and the Independent System Operator New England (“ISO-NE”) market (the “Energy Services Business”) anticipates that, based on the expected load forecast for its existing contracts, it will provide approximately 30,000 MW-hrs of energy to its customers in the first quarter of 2011 and, based on long term average hydrology for this period, the Tinker Assets are anticipated to provide 40% of the energy required to service this load. Subsequent to December 31, 2010, the Energy Services Business entered into a three year contract with Maine Public Service Company, a regulated electric transmission and distribution utility serving approximately 36,000 electricity customer accounts in Northern Maine (“MPS”) 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.

The capital upgrade at the EFW facility, completed in July 2010, is expected to result in higher throughput and lower operating costs at the facility in the first quarter of 2011 as compared to the same period in 2010 when the facility was temporarily shut down as a result of an unplanned outage experienced in January 2010. APCo Thermal Energy division’s Sanger facility should meet APCo’s expectations for the first quarter of 2011 and be

in line with 2010 results. Hydro-mulch sales are expected to be similar to 2010 sales due to continuing low demand for hydro-mulch in the U.S.

APCo Thermal Energy division’s Windsor Locks facility will continue to sell a portion of its electricity capacity and all of its steam capacity to the industrial host with the balance of the electrical capacity available to be sold either into the ISO-NE day-ahead market or to retail customers through the Energy Services Business. The facility did not commit any portion of its electrical capacity to the forward reserve market (“FRM”) for the winter of 2011 due to unacceptably low auction prices. It is anticipated that performance during the first quarter of 2011 will be strong, resulting from moderate natural gas prices and a cold winter in the north-east U.S. that has resulted in high electricity prices. APCo has completed preliminary engineering for a repowering project at the Windsor Locks facility and is in negotiations with Ahlstrom regarding this project. For a more detailed description of the options and expected impact seeDevelopment Division - Windsor Locks.

Liberty Water

Liberty Water is forecasting modest customer growth in 2011 with the continuing economic recovery in the United States. Liberty Water provides water distribution and wastewater collection and treatment services, primarily in the southern and southwestern U.S. where communities have traditionally experienced long term growth and that provide continuing future opportunities for organic growth.

On December 11, 2011, the Arizona Corporate Commission (“ACC”) approved an order authorizing a rate increase of U.S. $0.9 million for Rio Rico Utilities Inc., effective February 1, 2011. It is anticipated that the regulatory review of the proposed rates and tariffs for the Bella Vista, Northern Sunrise, and Southern Sunrise facilities will be completed in Q1 2011. Total revenue increases from rate cases completed in Arizona and Texas represent an additional U.S. $10.2 million in annualized revenue. 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.

Liberty Energy

In 2009, APUC announced plans to acquire the California Utility assets in partnership with Emera. The acquisition was approved by both the California Public Utilities Commission (“CPUC”) and the Public Utilities Commission of Nevada in the fourth quarter of 2010. Subsequent to these approvals, the transaction was completed on January 1, 2011 for a purchase price of approximately U.S. $131.8 million, subject to certain working capital and other closing adjustments. The acquisition was funded in part with the proceeds of a U.S. $70 million senior unsecured private debt placement at the utility. Liberty Energy’s ownership share of the cost of acquisition of the California Utility was primarily funded through the proceeds of subscription receipts held by Emera for 8.532 million APUC common shares at a price of $3.25 per share.

On December 9, 2010, Liberty Energy entered into agreements to acquire all issued and outstanding shares of Granite State and EnergyNorth from National Grid for total consideration of U.S. $285.0 million.

Liberty Energy is pursuing additional investments in electric distribution utilities and electric transmission assets, sharing certain common infrastructure between utilities to support best in-class-customer care for its subsidiary utility ratepayers.

LOGO

APCo: Renewable Energy


	Three months ended December 31								Twelve months ended December 31
	Long Term Average Resource		2010			2009			Long Term Average Resource		2010			2009
Performance (MW-hrs sold)
Quebec Region		72,575		84,125			73,650			276,825		275,850			299,900
Ontario Region		34,750		20,200			30,350			144,725		90,225			134,800
Manitoba Region		105,000		97,150			89,625			372,000		343,100			364,500
New England Region		15,425		13,380			16,200			65,275		47,900			81,725
New York Region		24,100		24,375			24,750			91,100		79,550			95,000
Western Region		13,400		10,450			10,875			67,250		59,100			58,200
Maritime Region		39,575		55,525			2,425			148,250		148,550			7,025


Total		304,825		305,205			247,875			1,165,425		1,044,275			1,041,150

Revenue
Energy sales			$	21,867		$	16,604				$	80,117		$	68,227
Less:
Cost of Sales – Energy*				(431	)		—					(5,047	)		—

Net Energy Sales			$	21,436		$	16,604				$	75,070		$	68,227

Other Revenue				563			—					2,122			—

Total Net Revenue			$	21,999		$	16,604				$	77,192		$	68,227

Expenses
Operating expenses				(7,013	)		(6,619	)				(24,434	)		(22,279	)
Interest and Other income				151			433					783			1,226


Division operating profit (including other income)			$	15,137		$	10,418				$	53,541		$	47,174

*	Cost of Sales – Energy consists of energy purchases by the Energy Services Business, where this energy is sold to customers pursuant to fixed rate energy contracts.

As APCo’s hydroelectric generating facilities in the New York and New England regions primarily sell their output at market rates, the average revenue earned per MW-hr sold can vary significantly from the same period in the prior period or year. APCo’s hydroelectric generating facilities in the Maritime region primarily sell their output to the Energy Services Business which, in turn, sells this energy at fixed price contracts to local electric utilities and commercial buyers in Northern Maine. APCo’s facilities in the other regions are subject to varying rates, by facility, as set out in each facility’s individual PPA. As such, while most of APCo’s PPAs include annual rate increases, a change to the weighted average production levels resulting in higher average production from facilities that earn lower energy rates can result in a lower weighted average energy rate earned by the division, as compared to the same period in the prior year.

2010 Annual Operating Results

For the twelve months ended December 31, 2010 the Renewable Energy division produced 1,044,275 MW-hrs of electricity, as compared to 1,041,150 MW-hrs produced in the same period in 2009, an increase of 0.3%. The level of production in 2010 represents sufficient renewable energy to supply the equivalent of 58,000 homes on an annualized basis with renewable power. Using new standards of thermal generation, as a result of renewable energy production, the equivalent of 575,000 tons of CO2 gas was prevented from entering the atmosphere in 2010.

For the year ended December 31, 2010, the division generated electricity equal to 90% of long-term projected average resources (wind and hydrology) as compared to 102% during the same period in 2009. Over 2010, the Maritime and Quebec regions experienced resources generally consistent with long-term averages. The Manitoba, New York and Western regions experienced resources within 15% of long-term averages. The Ontario region experienced resources approximately 40% below long-term averages and the New England region experienced resources approximately 25% below long-term averages. The lower wind resource in the Manitoba region in the first quarter and fourth quarters of 2010 was similar to lower wind resources experienced at other wind farms in North America.

For the year ended December 31, 2010, revenue from energy sales in the Renewable Energy division totalled $80.1 million, as compared to $68.2 million during the same period in 2009, an increase of $11.9 million or 17.4%. As the purchase of energy by the Energy Services Business is a significant revenue driver and component of variable operating expenses, the division compares ‘net energy sales’ (energy sales revenue less energy purchases) as a more appropriate measure of the division’s sales results. For the year ended December 31, 2010, net revenue from energy sales in the Renewable Energy division totalled $75.1 million, as compared to $68.2 million during the same period in 2009, an increase of $6.8 million or 10.0%.

Revenue from APCo’s New England and New York region facilities increased $0.8 million due to an increase in weighted average energy rates of approximately 15.8% and decreased $2.4 million due to decreased average hydrology, as compared to the same period in 2009. Revenue from the Manitoba region increased $1.0 million due to an increase in weighted average energy rates of approximately 5.9%, offset by a decrease of $1.2 million due to a weaker wind resource, as compared to the same period in 2009. The power purchase agreement associated with the St. Leon facility requires the facility to generate a minimum amount of dependable energy during the annual contract year ending April 30. Energy generated above the dependable amount earns revenue at lower, non-dependable rates. As a result of the lower production experienced in the first quarter of 2010, during the annual contract year ending April 30, 2010, the facility earned revenue primarily at the dependable rates as compared to the same period in 2009 when a greater proportion of revenue was earned at the non-dependable rates. Revenue generated by the Ontario, Quebec and Western regions increased by $1.9 million due to an increase in weighted average energy rates of approximately 6.3%, primarily the result of increased rates at the Long Sault facility in the Ontario region, as compared to the same period in 2009. The increases in revenue at APCo’s Ontario, Quebec and Western regions were offset by a decrease of $4.8 million due to lower energy production, primarily the result of lower production from reduced hydrologic resources available at the Long Sault facility in the Ontario region, as compared to the same period in 2009. The Maritime region, in conjunction with the Energy Services Business, generated $17.7 million in revenue, before energy purchases. This revenue arose from electricity sales under sales agreements with local electric utilities and wholesale consumers in Northern Maine ($14.0 million) and New Brunswick ($1.9 million) and merchant sales of production in excess of customer demand ($1.7 million).

Other revenue for the year ended December 31, 2010 totalled $2.1 million, as compared to nil during the same period in 2009. Other revenue represents amounts earned related to the development and construction of the Red Lily I wind project.

The division reported decreased revenue of $0.6 million from U.S. operations as a result of the stronger Canadian dollar as compared to the same period in 2009.

For the year ended December 31, 2010, energy purchase costs of the Energy Services Business totalled U.S. $4.9 million. In 2010, the Energy Services Business purchased approximately 74,900 MW-hrs of energy at market and fixed rates averaging U.S. $65 per MW-hr. The Maritime region generated approximately 65% of the load required to service its customers as well as the Energy Services Business’ customers in 2010. The energy purchases represent a combination of the load requirement of the Energy Services Business’ customers and the timing of this demand as compared to the energy produced by the Tinker Assets and the timing of this production. The division reported increased energy costs of $0.1 million as a result of the Canadian dollar exchange rates.

For the year ended December 31, 2010, operating expenses excluding energy purchases totalled $24.4 million, as compared to $22.3 million during the same period in 2009, an increase of $2.2 million or 9.7%. Operating expenses were impacted by $1.5 million of increased expenses at the St. Leon facility, primarily resulting from scheduled payments under the extended warranty and operation and maintenance agreement with Vestas, $0.6 million of increased operating expenses at the U.S. hydroelectric facilities, and $2.9 million related to operating costs associated with the Tinker Assets and the Energy Services Business as compared to the same period in 2009. These increases were partially offset by $0.6 million in decreased operating costs at Canadian facilities, primarily due to lower variable operating costs tied to lower revenue and lower repair and maintenance projects

commenced in 2010. Operating expenses include costs incurred in the period of $1.1 million associated with the pursuit of various growth and development activities, including operating expenses associated with the construction supervision work on the Red Lily I wind project, as compared to development costs incurred of $2.1 million in the same period in 2009. Operating expenses in 2010 were lower due to a reimbursement of $0.9 million related to costs previously expensed by APUC in connection with the development of the Red Lily I wind project. The division reported decreased expenses of $0.5 million from U.S. operations as a result of the stronger Canadian dollar as compared to the same period in 2009.

For the year ended December 31, 2010, Renewable Energy’s operating profit totalled $53.5 million, as compared to $47.2 million during the same period of 2009, representing an increase of $6.4 million or 13.5%. Renewable Energy’s operating profit did not meet APCo’s expectations primarily due to a lower than expected wind resource in the Manitoba region in the first quarter of 2010 and lower hydrology in the second and third quarters of 2010.

2010 Fourth Quarter Operating Results

For the quarter ended December 31, 2010, the Renewable Energy division produced 305,205 MW-hrs of electricity, as compared to 247,875 MW-hrs produced in the same period in 2009, an increase of 23.1%. The increased generation is primarily due to the acquisition of the Tinker Hydro facility in January 2010 and therefore did not form part of the production in the comparable period in 2009. The level of production in 2010 represents sufficient renewable energy to supply the equivalent of 68,000 homes on an annualized basis with renewable power. Using new standards of thermal generation, as a result of renewable energy production, the equivalent of 168,000 tons of CO2 gas was prevented from entering the atmosphere in the fourth quarter of 2010.

During the quarter ended December 31, 2010, the division generated electricity equal to long-term projected average resources (wind and hydrology) as compared to 93% during the same period in 2009. In the fourth quarter of 2010, the Maritimes and Quebec regions experienced resources significantly higher than long-term averages, producing approximately 40% and 15% above long-term average resources, respectively. The New York region experienced resources approximately equal to the long-term average, while the Manitoba and New England regions experienced resources of approximately 10% below long-term averages. The Ontario and Western regions experienced results significantly below long-term average resources.

For the quarter ended December 31, 2010, revenue from energy sales in the Renewable Energy division totalled $21.9 million, as compared to $16.6 million during the same period in 2009, an increase of $5.3 million or 31.7%. As the purchase of energy by the Energy Services Business is a significant revenue driver and component of variable operating expenses, the division compares ‘net energy sales’ (energy sales revenue less energy purchases) as a more appropriate measure of the division’s sales results. For the quarter ended December 31, 2010, net revenue from energy sales in the Renewable Energy division totalled $21.4 million, as compared to $16.6 million during the same period in 2009, an increase of $4.8 million or 29.1%.

Revenue from APCo’s New England and New York region facilities increased $0.2 million due to an increase in weighted average energy rates of approximately 15.5%, offset by $0.3 million due to decreased average hydrology, as compared to the same period in 2009. Revenue from the Manitoba region increased $0.6 million primarily due to a stronger wind resource, as compared to the same period in 2009. Revenue generated by the Ontario, Quebec and Western regions increased by $0.2 million due to an increase in weighted average energy rates of approximately 2.0%, primarily the result of increased rates at the Long Sault facility in the Ontario region, and $0.2 million due to increased energy production, primarily the result of increased production in the Quebec region, as compared to the same period in 2009. The Maritime region, in conjunction with the Energy Services Business, generated $4.2 million in revenue, before energy purchases. This revenue consists of sales to local electric utilities and wholesale consumers in Northern Maine ($2.6 million) and New Brunswick ($0.6 million) and merchant sales of production in excess of customer demand and other revenue ($0.9 million).

Other revenue for the three months ended December 31, 2010 totalled $0.6 million, as compared to nil during the same period in 2009. Other revenue represents amounts earned related to the development and construction of the Red Lily I wind project.

For the quarter ended December 31, 2010, energy purchase costs by the Energy Services Business totalled U.S. $0.4 million. During the quarter, the Energy Services Business purchased approximately 9,500 MW-hrs of energy at market and fixed rates averaging $44 per MW-hr. The Maritime region generated approximately 95% of the load required to service its customers as well as the Energy Services Business’ customers in the three months ended December 31, 2010. The energy purchases represent a combination of the load requirement of

the Energy Services Business’ customers and the timing of this demand as compared to the energy produced by the Tinker Assets and the timing of this production.

For the quarter ended December 31, 2010, operating expenses excluding energy purchases totalled $7.0 million, as compared to $6.6 million during the same period in 2009, an increase of $0.4 million or 6.0%. Operating expenses were impacted by $0.2 million of increased expenses at the St. Leon facility, primarily resulting from scheduled payments under the extended warranty and operation and maintenance agreement with Vestas and $1.0 million related to operating costs associated with the Tinker Assets and the Energy Services Business, as compared to the same period in 2009. These increases were partially offset by $0.4 million in decreased operating costs at Canadian facilities primarily due to lower variable operating costs. Operating expenses include costs incurred in the period of $0.8 million associated with the pursuit of various growth and development activities, including operating expenses associated with the construction supervision work on the Red Lily I wind project as compared to development costs incurred of $0.9 million in the same period in 2009. The division reported decreased expenses of $0.2 million from U.S. operations as a result of the stronger Canadian dollar as compared to the same period in 2009.

For the quarter ended December 31, 2010, Renewable Energy’s operating profit totalled $15.1 million, as compared to $10.4 million during the same period of 2009, representing an increase of $4.7 million or 45.3%. For the quarter ended December 31, 2010, Renewable Energy’s operating profit met APCo’s expectations primarily due to improved hydrology in the quarter in the Quebec and Maritime regions.

Divisional Outlook – Renewable Energy

The APCo Renewable Energy division is expected to perform at long-term average resource conditions for hydrology and below long-term average wind resources in the first quarter of 2011.

The construction phase of the Red Lily I project is now complete with commercial operation occurring under the SaskPower PPA in February 2011. The power purchase agreement with SaskPower is for 25 years and includes a 2% annual increase throughout the term of the agreement. APUC’s investment of $19.6 million in the Red Lily I facility has been initially structured as senior and subordinated debt bearing a blended interest rate of 8.43%. The balance of the total expected project construction costs of $71.2 million have been financed by senior debt from third party lenders in the amount of $31.0 million and an equity contribution from an independent investor estimated to be $20.6 million. In addition to interest payments on its debt financing, APUC is entitled to certain supervisory fees, estimated at $1.3 million in the first full year of operation. Total interest and fee payments in 2011 are estimated to be approximately $2.4 million representing approximately 75% of net cash flows from the facility. APUC has the option to formally exchange its debt investment and fee interest in the project for a 75% equity interest, exercisable in February 2016.

The Energy Services Business anticipates that, based on the expected load forecast for its existing contracts, it will provide approximately 30,000 MW-hrs of energy to its customers in the first quarter of 2011. Based on historical long term average levels of hydroelectric energy generation for the first quarter of 2011, the Tinker Assets are anticipated to provide 40% of the energy required by the Energy Services Business to service its customers which provides a natural hedge on supply costs of the Energy Services Business. In respect of each customer delivery obligation, the Energy Services Business has in place fixed price financial energy contracts to operationally hedge the price of the customer supply obligation and to minimize the volatility of the energy price. These contracts in combination with the expected Tinker production are used to balance the monthly customer load.

Subsequent to December 31, 2010, the Energy Services Business 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 customer load associated with this bid is approximately 135,000 MW-hrs.

As a result of certain legislation passed in Quebec (Bill C93), APCo’s Renewable Energy division is required to undertake technical assessments of eleven of the twelve hydroelectric facility dams owned or leased within the Province of Quebec. As a result of the assessments and a preliminary evaluation of the associated remedial work, APCo currently estimates capital expenditures of approximately $17.1 million related to compliance with the legislation. The timing of when the actual capital costs need to be made is determined as part of the technical assessments.

APCo anticipates that these expenditures will be invested over a period of several years approximately as follows:


	Total		2011		2012		2013		2014		2015

Estimated Bill C-93 Capital Expenditures		17,100		800		5,000		5,500		3,000		2,800

The majority of these capital costs are associated with the Donnacona, St. Alban, Belleterre, and Mont-Laurier facilities. APCo does not anticipate any significant impact on power generation or associated revenue while the dam safety work is ongoing. APCo continues to explore several alternatives to mitigate the capital costs of the modifications, including cost sharing with other stakeholders and revenue enhancements which can be achieved through the modifications.

APCo: Thermal Energy Division


	Three months ended December 31						Twelve months ended December 31
	2010			2009			2010			2009
Performance (MW-hrs sold)		120,600			147,482			465,390			571,505
Performance (tonnes of waste processed)		43,535			42,189			90,690			161,102

Revenue
Energy sales	$	12,185		$	13,819		$	52,609		$	62,209
Less:
Cost of Sales – Fuel *		(5,492	)		(5,224	)		(22,348	)		(26,517	)

Net Energy Sales Revenue	$	6,693		$	8,595		$	30,261		$	35,692

Waste disposal sales		4,164			3,786			9,039			14,468
Other revenue		311			545			1,209			3,848

Total net revenue	$	11,168		$	12,926		$	40,509		$	54,008
Expenses
Operating expenses *		(6,127	)		(7,121	)		(23,948	)		(30,782	)
Interest and other income		100			140			495			821


Division operating profit(including interest and dividend income)	$	5,141		$	5,945		$	17,056		$	24,047

*	Cost of Sales – Fuel consists of natural gas and fuel costs at the Sanger and Windsor Locks facilities.

APCo’s Sanger and Windsor Locks generation facilities purchase natural gas from different suppliers and in different regional hubs. As a result, the average landed cost per unit of natural gas will differ between facility and regional changes in the average landed cost for natural gas may result in one facility showing increasing costs per unit while the other showing decreasing costs, as compared to the same period in the prior year.‘Cost of Sales – Fuel’ is calculated as the volume of natural gas consumed by a facility times the average landed cost of natural gas. As a result, a facility may record a higher aggregate expense for natural gas as a result of a lower average landed cost for natural gas combined with a consumption of a higher volume of natural gas.

2010 Annual Operating Results

In 2010, the EFW facility processed 90,690 tonnes of municipal solid waste as compared to 161,102 tonnes processed in the same period of 2009, a decrease of 43.7%. The significantly reduced throughput was a result of the unplanned outage experienced in January 2010 which resulted in the facility being temporarily shut down. The major capital upgrades to the facility were completed at the end of the second quarter and the facility was restarted on July 14, 2010. The status of this facility is discussed in further detail inDivisional Outlook – Thermal Energy, below. This level of production resulted in the diversion of approximately 65,000 tonnes of waste from landfill sites in 2010.

For the year ended December 31, 2010, the Thermal Energy Division produced 465,390 MW-hrs of energy as compared to 571,505 MW-hrs of energy in the comparable period of 2009. During the year ended December 31, 2010, the business unit’s performance decreased by 83,800 MW-hrs at the Windsor Locks facility, 23,000 MW-hrs at the land-fill gas (“LFG”) facilities and 3,500 MW-hrs from EFW’s steam turbine, partially offset by an increase of 3,900 MW-hrs at the Sanger facility, as compared to the same period in 2009.

The decrease in electrical generation at the Windsor Locks facility was the expected result of the expiry of the PPA with Connecticut Light & Power in April 2010 and the change in operating model for the facility to one where revenues are earned from payments under the continuing energy sales agreement with the co-located electricity and thermal energy host augmented by capacity and energy payments from the ISO-NE and associated markets. As a result, the facility will only generate additional energy beyond that needed to service the existing industrial customer when market conditions warrant, resulting in reduced energy production compared to the historic operating model. The decrease in electrical generation at the EFW facility was the result of the unplanned outage which occurred in January 2010.

For the year ended December 31, 2010, APCo ceased generating energy at the LFG facilities, initiated a process to close these facilities and sold the generating assets. SeeAPUC Annual Corporate and other Expenses for additional details related to the write down in the carrying value of these assets.

For the year ended December 31, 2010, revenue in the Thermal Energy division totalled $62.9 million, as compared to $80.5 million during the same period in 2009, a decrease of $17.7 million or 21.9%. As natural gas expense is a significant revenue driver and component of operating expenses, the division compares ‘net energy sales revenue’ (energy sales revenue less natural gas expense) as a more appropriate measure of the division’s results. During the year ended December 31, 2010, net energy sales revenue at the Thermal Energy division totalled $30.3 million, as compared to $35.7 million during the same period in 2009, a decrease of $5.4 million or 15.2%.

For the year ended December 31, 2010, energy sales revenue in the Thermal Energy division totalled $52.6 million, as compared to $62.2 million during the same period in 2009, a decrease of $9.6 million or 15.4%. The decrease in revenue from energy sales was primarily due to a decrease of $6.7 million at the Windsor Locks facility as a result of decreased production, partially offset by an increase of $3.0 million as a result of increased energy rates, in part due to a higher average landed price per mmbtu for natural gas and the change in operating model of the facility and a decrease of $1.3 million as a result of the closure of the LFG facilities, as compared to the same period in 2009. The decreases were partially offset by an increase in revenue from energy sales $0.4 million at the Sanger facility as a result of increased energy rates, in part due to higher average landed price per mmbtu for natural gas and $0.5 million at the Sanger facility as a result of increased production, as compared to the same period in 2009. The natural gas expense at the Sanger and Windsor Locks facilities is discussed in detail below. The division reported decreased energy sales revenue of $5.4 million from operations as a result of the stronger Canadian dollar, as compared to the same period in 2009.

Revenue from waste disposal sales in 2010 totalled $9.0 million, as compared to $14.5 million during the same period in 2009, a decrease of $5.4 million or 37.6%. The EFW facility generated lower revenue in the period as it was temporarily shut down between January and July 2010 as a result of the unplanned outage.

Other revenue for the year ended December 31, 2010 totalled $1.2 million, as compared to $3.8 million during the same period in 2009, a decrease of $2.6 million or 68.6%. The decrease in other revenue was primarily due to a decrease of $1.6 million at the hydro-mulch facility due to reduced customer demand. In the comparable period in 2009, other revenue included $0.6 million from APCo’s LFG facilities which were not operational in the current period. The division reported decreased other revenue of $0.5 million as a result of the stronger Canadian dollar, as compared to the same period in 2009.

For the year ended December 31, 2010, fuel costs at Sanger and Windsor Locks totalled U.S. $21.7 million, as compared to U.S. $23.0 million during the same period in 2009, a decrease of U.S. $1.3 million. The overall natural gas expense at the Windsor Locks facility decreased $1.8 million (10%), primarily the result of a 14% reduction in volume of natural gas consumed, partially offset by a 5% increase in the average landed cost of natural gas per mmbtu, as compared to the same period in 2009. The average landed cost of natural gas at the Windsor Locks facility was U.S. $4.84 per mmbtu. The reduction in natural gas expense was partially offset by an increase in the overall natural gas expense at Sanger of $0.5 million (12%), primarily the result of an 11% increase in the average landed cost of natural gas per mmbtu. The average landed cost of natural gas at the Sanger facility was U.S. $4.79 per mmbtu. The division reported decreased fuel costs of $2.9 million as a result of the stronger Canadian dollar as compared to the same period in 2009.

For the year ended December 31, 2010, operating expenses, excluding fuel costs at Windsor Locks and Sanger, totalled $23.9 million, as compared to $30.8 million during the same period in 2009, a decrease of $6.8 million. The decrease in operating expenses for the quarter was primarily due to reduced operating costs of

$5.1 million at the EFW facility resulting from the outage at the facility, reduced material costs of $0.9 million at the hydro-mulch facility resulting from lower production, and $1.7 million of lower costs due to the closing of the LFG facilities partially offset by increased natural gas expense of $1.3 million at the Brampton Cogeneration Inc. (“BCI”) facility as a result of decreased steam production at EFW and increased steam production from BCI’s auxiliary boiler as compared to the same period in 2009. Operating expenses included costs of $0.5 million associated with the pursuit of various growth and development activities, as compared to nil in the same period in 2009. The division reported decreased operating expenses of $1.4 million as a result of the stronger Canadian dollar as compared to the same period in 2009.

Interest and other income for the year ended December 31, 2010 totalled $0.5 million, as compared to $0.8 million in the same period in 2009. During the year ended December 31, 2010, APUC determined that earnings from equity investments should be presented at the corporate level rather than at a divisional level. As a result, the comparable figures have been reclassified to conform to the presentation adopted in the current year.

For the year ended December 31, 2010, the Thermal Energy division’s operating profit totalled $17.1 million, as compared to $24.0 million during the same period in 2009, representing a decrease of $7.0 million or 29%. Operating profit in the Thermal Energy division did not meet overall expectations for the year ended December 31, 2010, primarily due to the unplanned outage at the EFW facility, the change in operating model at Windsor Locks and lower demand for hydro-mulch resulting from the current economic slow down in the U.S.

2010 Fourth Quarter Operating Results

During the quarter ended December 31, 2010, the EFW facility processed 43,535 tonnes of municipal solid waste as compared to 42,189 tonnes processed in the same period of 2009, an increase of 3.2%. This level of production resulted in the diversion of approximately 32,000 tonnes of waste from municipal solid waste landfill sites in 2010.

During the quarter ended December 31, 2010, the business unit produced 120,600 MW-hrs of energy as compared to 147,482 MW-hrs of energy in the comparable period of 2009. During the quarter ended December 31, 2010, the business unit’s performance decreased by 25,300 MW-hrs at the Windsor Locks facility and 5,600 MW-hrs at the LFG facilities, partially offset by an increase of 3,000 MW-hrs at the Sanger facility and 1,000 MW-hrs at the EFW facility, as compared to the same period in 2009. See the discussion of the annual operating results regarding the decrease in electrical generation at the Windsor Locks facility.

During the quarter ended December 31, 2010, APCo sold the generating assets at the LFG facilities. SeeAPUC Annual Corporate and other Expenses for additional details related to the write-down in the carrying value of these assets.

For the quarter ended December 31, 2010, revenue in the Thermal Energy division totalled $16.7 million, as compared to $18.2 million during the same period in 2009, a decrease of $1.5 million, or 8.2%. As natural gas expense is a significant revenue driver and component of operating expenses, the division compares ‘net energy sales revenue’ (energy sales revenue less natural gas expense) as a more appropriate measure of the division’s results. For the quarter ended December 31, 2010, net energy sales revenue at the Thermal Energy division totalled $6.7 million, as compared to $8.6 million during the same period in 2009, a decrease of $1.9 million.

For the quarter ended December 31, 2010, energy sales revenue in the Thermal Energy division totalled $12.2 million, as compared to $13.8 million during the same period in 2009, a decrease of $1.6 million or 11.8%. The decrease in revenue from energy sales was primarily due to a decrease of $1.8 million at the Windsor Locks facility as a result of decreased production, partially offset by an increase of $1.0 million as a result of increased energy rates, in part due to a higher average landed price per mmbtu for natural gas and the change in operating model of the facility and a decrease of $0.3 million as a result of the closure of the LFG facilities, as compared to the same period in 2009. The decrease in revenue was partially offset by $0.1 million at the BCI facility as a result of increased price for steam, as compared to the same period in 2009. The natural gas expense at the Sanger and Windsor Locks facilities is discussed in detail below. The division reported decreased energy sales revenue of $0.4 million from operations as a result of the stronger Canadian dollar, as compared to the same period in 2009.

Revenue from waste disposal sales for the quarter ended December 31, 2010 totalled $4.2 million, as compared to $3.8 million during the same period in 2009. The increase was a result of the EFW facility processing a higher throughput of municipal solid waste as compared to the same period in 2009.

Other revenue for the quarter ended December 31, 2010 totalled $0.3 million, as compared to $0.5 million during the same period in 2009. The decrease in other revenue was due to decreased revenue at the hydro-mulch facility due to reduced customer demand in the quarter.

For the quarter ended December 31, 2010, fuel costs at Sanger and Windsor Locks totalled U.S $5.4 million, as compared with U.S $4.9 million in the same period in 2009, an increase of U.S. $0.5 million. The overall natural gas expense at the Windsor Locks facility increased $0.5 million (14%), primarily the result a 45% increase in the average landed cost of natural gas per mmbtu, partially offset by a 21% reduction in volume of natural gas consumed, as compared to the same period in 2009. The average landed cost of natural gas at the Windsor Locks facility during the quarter was $5.00 per mmbtu. This was partially offset by a decrease in the natural gas expense at Sanger of $0.1 million (4%), primarily the result of a 10% decrease in the average landed cost of natural gas per mmbtu, partially offset by a 7% increase in the volume of natural gas consumed as compared to the same period in 2009. The average landed cost of natural gas at the Sanger facility during the quarter was U.S. $4.40 per mmbtu. The division reported decreased fuel costs of $0.2 million as a result of the stronger Canadian dollar as compared to the same period in 2009.

For the quarter ended December 31, 2010, operating expenses, excluding fuel costs at Windsor Locks and Sanger, totalled $6.1 million, as compared to $7.1 million during the same period in 2009, a decrease of $1.0 million. The decrease in operating expenses for the quarter was primarily due to reduced material costs of $0.2 million at the hydro-mulch facility resulting from lower production, $0.1 million of reduced operating costs at BCI and $0.8 million of reduced operating costs at the LFG facilities partially offset by $0.3 million in increased operating costs at the Windsor Locks facility as compared to the same period in 2009.

Interest and other income for the three months ended December 31, 2010 totalled $0.1 million, consistent with the same period in 2009.

For the quarter ended December 31, 2010, the Thermal Energy division’s operating profit totalled $5.1 million, as compared to $5.9 million during the same period in 2009, representing a decrease of $0.8 million or 13.5%. Operating profit in the Thermal Energy division did not meet overall expectations for the quarter ended December 31, 2010, primarily due to lower than expected earnings at the Windsor Locks facility as a result of decreased production volume.

Divisional Outlook – Thermal Energy

The capital upgrade completed at the EFW facility is expected to result in higher throughput and lower operating costs at the facility which should positively affect operating profit generated by the facility in 2011 as compared to the same period in 2010 when the facility was temporarily shut down as a result of an unplanned outage experienced in January 2010. APCo Thermal Energy division’s Sanger facility should meet APCo’s expectations for the first quarter of 2011 and be in line with 2010 results. Hydro-mulch sales are expected to be similar to 2010 sales due to continuing low demand for hydro-mulch in the U.S.

Algonquin has completed preliminary engineering for a repowering project at the Windsor Locks facility and is in negotiations with the steam host regarding this project. SeeAPCo Development Division – Windsor Locks for further discussion on the potential repowering project.

APCo: Development Division

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. The Development division is led by six full time employees who have access to, and support from, all of APCo’s available resources to assist it in the development of projects. Typically, the division draws upon the support of the finance, engineering, technical services, and environmental and regulatory compliance groups. It also 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 power purchase agreement, 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.

Industry Outlook

Environmental concerns, increases in electricity demand and fossil fuel price volatility have combined to create the impetus for governments, regulatory bodies and utilities to diversify their mix of power generation. This diversification has largely been focused on developing a larger proportion of renewable power and high-efficiency gas generation. Consequently, a favourable policy environment has emerged for independent producers and developers of renewable and thermal power generation, particularly in the areas of wind, hydroelectric and natural gas generation. Additionally, there has been a general recognition that energy produced by independent producers which is priced in the context of market competition offer a lower cost means of production to utilities.

An increasing amount of attention has been paid to the environmental value of both renewable and efficient means of power production and the ability of the power industry to offset the ill-effects of production by higher polluting fossil fuels. To the extent that a renewable or efficient source of energy can offset a fossil fuelled generating source, it can, in some cases, generate a carbon credit which can then be sold to a third party. Despite the fact that there is no nationally recognized carbon reduction program in either the U.S. or Canada, there remain several regional organizations that have been established with targets to reduce carbon emissions. Globally, the value of the carbon market doubled for three consecutive years from U.S. $31.2 billion in 2006 to U.S. $138.9 billion in 2009. This should enhance the ability to develop future renewable sources of generation.

Divisional Outlook - Development

It is anticipated 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. In May 2009, the Ontario government passed the Green Energy Act (“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 similar legislation. British Columbia has announced the Clean Energy Act and Nova Scotia is pursuing the 2010 Renewable Electricity Plan and will be establishing pricing for its ensuing Community FIT program in April of 2011. Both of these proposed pieces of legislation have set aggressive

targets for the development of new, renewable power production. They also introduce the concept of fixed pricing based on a FIT for some categories of new renewable power projects. The combination of increased renewable production targets and appropriate fixed pricing will present investment opportunities for APCo to consider in the future.

Current Development Projects

Amherst Island

On February 25, 2011, APUC announced that the OPA has awarded a FIT contract to the wholly-owned 75 MW Amherst Island Wind Project, located on Amherst Island in the village of Stella, approximately 25 kilometers southwest of Kingston, Ontario. The contract has been awarded as part of the second round of the OPA’s FIT program.

The project, which will be developed by APCo, is currently contemplated to use more efficient Class III wind turbine generator technology. While final turbine selection remains to be made, modelling the higher energy capture ratios of turbines, such as the Vestas V100 or Repower MM100, forecast that the available wind resource would produce approximately 247 GW hrs of power annually. Funding for the total capital costs currently estimated to be $220 million will be arranged and announced when all required permitting and all other pre-construction conditions have been satisfied. 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 months.

Quebec Community Wind Projects

In July 2010, APCo worked with Société en Commandite Val-Eo, a 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 contracts that stipulate the use of ENERCON turbines.

The quantum of the interests of APUC in the Saint-Damase and Val- Éo projects is subject to final negotiations with the partners in the projects but, in any event, will not be less than 50% and 25%, respectively. Final funding of the projects will be arranged and announced when all required permitting has been met, and all other pre-construction conditions have been satisfied. Preliminary permitting will begin for both projects in early 2011, with all major authorizations targeted for completion by the end of 2012.

St. 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 APUC. The first 24 MW phase of the project is currently envisioned to consist of twelve 2MW ENERCON E-82 wind turbine generators, producing approximately 86,000 MW-hrs 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.

Val Eo

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 APUC. The first 24 MW phase of the project is expected to be comprised of eight 3MW ENERCON E-101 wind turbine generators, producing approximately 66,000 MW-hrs 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.

Red Lily II

In addition to the now completed Red Lily I project, APCo has secured additional land options related to property around Red Lily I to facilitate a 106 MW expansion (“Red Lily II”). The viability of the expanded project will be conditional upon a review of the actual operating results from Red Lily I. During the first quarter of 2010, APCo responded to the request for quotations issued by SaskPower by submitting requested information pertaining to Red Lily II.

Successful development of wind projects is subject to significant risks and uncertainties including the ability to obtain financing on acceptable terms within deadlines imposed by the utility, reaching agreement with any other

external parties involved in the project, currency fluctuations affecting the cost of major capital components such as wind turbines, price escalation for construction labour and other construction inputs and construction risk that the project is built without mechanical defects and is completed on time and within budget estimates.

Windsor Locks

The Windsor Locks facility is a 54 MW natural gas power 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 Windsor Locks, LLC (“Ahlstrom”), a leading paper and non-woven materials manufacturer, pursuant to an energy services agreement (“ESA”) which expires in 2017.

The balance of Windsor Locks’ electrical generating capacity is sold to customers through the ISO-NE electrical market. The facility currently participates in the ISO-NE Forward Capacity Market and the day-ahead energy market. Assuming acceptable auction pricing is available in April 2011, the additional electrical capacity of approximately 26 MW at the Windsor Locks facility will be made available into the summer 2011 Forward Reserve Market. In addition, APCo’s Energy Services Business will use the production from the Windsor Locks facility to support retail industrial electrical sales in the ISO-NE market.

APCo has completed preliminary engineering and environmental permitting work for the installation of a 14.2 MW combustion gas turbine which is more appropriately sized to meet the electrical and steam requirements of Ahlstrom. The total expected capital cost for this project is estimated at approximately U.S. $20 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 to 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 Windsor Locks of approximately $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. APCo also believes that this project would qualify for a combined heat and power Investment Tax Credit (“ITC”) grant program 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. APCo’s decision to make any investment in new capital for this site will be based on an assessment of the incremental earnings against such additional investment.

During 2011, it is expected that APCo will continue to earn revenue from steam and electrical sales to Ahlstrom, steam and electrical capacity payments made by Ahlstrom, as well as energy and capacity payments through sales to ISO-NE. Under the expected NE-ISO operating protocol APCo will need to acquire approximately 0.9 million MMBTU of natural gas annually in addition to the amount of natural gas purchased to serve the needs of Ahlstrom (in respect of which APCo receives reimbursement from Ahlstrom under the ESA).

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.

In addition to Red Lily II, APCo is currently collecting wind data on three sites in Saskatchewan and responded to Saskatchewan’s Request for Qualifications to procure up to 175 MW of wind power from one or more independent power producers. These sites have met the qualifications and APCo will likely submit project proposals into future RFPs.

Discussions with the OPA indicate that energy procurement initiatives have been positively influenced by the GEA. The GEA is intended to provide the catalyst for the development of 50,000 new green economy jobs and is viewed by APCo as positive for the development of renewable energy in Ontario. The Development division is maintaining relationships with potential partners for the development of a number of projects that could qualify under anticipated procurement initiatives undertaken by the OPA in accordance with the GEA.

APCo had previously submitted applications for approximately 120 MW of on-shore wind energy projects in eastern Ontario under the GEA’s FIT program. The on-shore wind price set by the FIT program is $0.135 per KWh. In February 2011, APCo received notification that a power purchase agreement was awarded for its 75 MW Amherst Island wind project, approximately 25km from Kingston, Ontario. APCo has received confirmation from the OPA that the remaining 45 MW of applications submitted under the FIT program are now being reviewed under the Economic Connection Test.

APCo has applied to become applicant of record for three Crown land sites in Ontario under the Ministry of Natural Resources wind power site release program.

Each project being contemplated is subject to a significant level of due diligence and financial modeling to ensure it satisfies return and diversification objectives established for the Development division. Accordingly, the likelihood of proceeding with some or all of these projects depends on the outcome of due diligence, material contract negotiations, the structure of future calls for tender, and request for proposal programs. To maximize APCo’s opportunities for development, new renewable and high efficiency thermal energy generating facilities are being pursued utilizing a variety of technologies and in diverse geographic locations.

Future Development Projects – Existing Facilities

APCo is exploring multiple options related to the St. Leon facility including pursuing a future adjacent project and/or pursuing an increase in the installed capacity of the existing facility. The projects being reviewed have a potential generation capacity of over 85 MW. In the event these projects are developed, it is currently estimated to require an investment of approximately $250 million.

Future Development Projects – 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.

LOGO

LIBERTY WATER


	Twelve months ended December 31						Twelve months ended December 31
	2010			2009			2010			2009
Number of
Wastewater connections								35,420			34,679
Wastewater treated (millions of gallons)								2,000			1,925

Water distribution connections								37,666			36,919
Water sold (millions of gallons)								5,500			5,900
		U.S. $			U.S. $			Can $			Can $
Assets for regulatory purposes (U.S. $)		155,258			147,581

Revenue
Wastewater treatment	$	19,979		$	17,983		$	20,704		$	20,601
Water distribution		15,877			14,996			16,453			17,179
Other Revenue		603			640			629			733

	$	36,459		$	33,619		$	37,786		$	38,513
Expenses
Operating expenses		(21,250	)		(20,055	)		(22,074	)		(23,158	)
Other income		82			1,220			85			1,368


Business Unit operating profit (including other income)	$	15,291		$	14,784		$	15,797		$	16,723

Liberty Water is committed to being a leading utility provider of safe, high quality and reliable water and wastewater services while providing stable and predictable earnings from its utility operations. Liberty Water has presented the division’s results in both the reporting currency and its functional currency. Liberty Water believes that since the division’s operations are entirely in the U.S., it is useful to show the results in Liberty Water’s functional currency without the impact of foreign exchange.

Liberty Water reports total connections, inclusive of vacant connections rather than customers. Liberty Water had 35,420 wastewater connections as at December 31, 2010, as compared to 34,679 as at December 31, 2009, an increase of 741 in the period or 2.1%. Liberty Water had 37,666 water distribution connections as at December 31, 2010, as compared to 36,919 as at December 31, 2009, representing an increase of 747 in the period or 2.0%. Total connections include approximately 1,900 vacant wastewater connections and 1,400 vacant water distributions connections as at December 31, 2010. Bad debt expense in 2010 decreased by approximately $0.1 million compared to 2009. Liberty Water’s change in water distribution and wastewater treatment customer base during the period is primarily due to the acquisition of a small utility in Texas during the first quarter of 2010 and modest growth at Liberty Water’s other facilities.

Liberty Water has investments in regulatory assets of U.S. $155.3 million across four states as at December 31, 2010, as compared to U.S. $147.6 million as at December 31, 2009 and has substantially completed proceedings in Texas and Arizona to allow it to earn its full regulatory return on its investment in regulatory assets.

2010 Annual Operating Results

During the year ended December 31, 2010, Liberty Water provided approximately 5.5 billion U.S. gallons of water to its customers, treated approximately 2.0 billion U.S. gallons of wastewater and sold approximately 345 million U.S. gallons of treated effluent.

For the year ended December 31, 2010, Liberty Water’s revenue totalled U.S. $36.5 million as compared to U.S. $33.6 million during the same period in 2009, an increase of U.S. $2.8 million or 8.4%.

Revenue from water distribution totalled U.S. $15.9 million as compared to U.S. $15.0 million during the same period in 2009, an increase of U.S. $0.9 million or 5.9%. The annual water distribution revenue was impacted by an increase of U.S. $0.6 million at the four Texas Silverleaf facilities primarily due to the implementation of rate increases, U.S. $0.3 million related to the acquisition of a facility in Galveston, Texas (“Galveston”) and U.S. $0.1 million at the Litchfield Park Service Company (“LPSCo”) facility due to a net increase in revenues from residential customers offset by decreased revenues from commercial customers in the first quarter of 2010, partially offset by decreased revenue of U.S. $0.1 million at the four facilities as compared to the same period in 2009.

Revenue from wastewater treatment totalled U.S. $20.0 million, as compared to U.S. $18.0 million during the same period in 2009, an increase of U.S. $2.0 million or 11.1%. The annual wastewater treatment revenue was impacted by increased revenue, primarily due to the implementation of rate increases, of U.S. $1.0 million at the four Texas Silverleaf and Woodmark facilities. The Tall Timbers, LPSCo and Black Mountain facilities saw increased revenue of U.S. $1.0 million primarily due to the combination of the implementation of rate increases and higher residential customer demand. The annual wastewater treatment revenue was also impacted by increased revenue of U.S. $0.3 million related to the acquisition of Galveston as compared to the same period in 2009. These increases were partially offset by decreased wastewater treatment revenue of U.S. $0.1 million due to lower treated effluent revenue at the Gold Canyon facility as compared to the same period in 2009.

For the year ended December 31, 2010, operating expenses totalled U.S. $21.3 million, as compared to U.S. $20.1 million during the same period in 2009. Overall expenses increased U.S. $1.2 million or 6.0% as compared to the same period in 2009. Operating expenses increased U.S. $0.8 million as a result of increased wages, salary and other operating costs, $0.3 million related to rate case costs which, based on the rate case decisions, must be expensed, $0.2 million relating to legal expenses and U.S. $0.2 million as a result of increased equipment rental and transportation costs, partially offset by decreases of U.S. $0.1 million in reduced repair and maintenance expenses and $0.4 million in reduced contracted services expenses as compared to the same period in 2009.

During the year ended December 31, 2009, Liberty Water earned other income of U.S. $1.2 million on the disposition of excess land. During the year ended December 31, 2010, Liberty Water did not dispose of any significant land or other assets.

For the year ended December 31, 2010, Liberty Water’s operating profit totalled U.S. $15.3 million as compared to U.S. $14.8 million in the same period in 2009, an increase of U.S. $0.5 million or 3.4%. Excluding other income, which includes a non-recurring gain on disposition of other assets (2009 - U.S. $1.2 million), operating profits increased by $1.6 million or 12.1%. Liberty Water’s operating profit did not meet expectations for the year ended December 31, 2010 primarily due to delays in receiving final decisions in respect of its current rate cases.

Measured in Canadian dollars, for the year ended December 31, 2010, Liberty Water’s revenue totalled $37.8 million as compared to $38.5 million during the same period in 2009, a decrease of $0.7 million. Revenue from wastewater treatment totalled $20.7 million, as compared to $20.6 million during the same period in 2009, a decrease of $0.1 million. Revenue from water distribution totalled $16.5 million, as compared to $17.2 million during the same period in 2009, a decrease of $0.7 million. Liberty Water reported decreased revenue from operations of $3.6 million in 2010 as a result of the stronger Canadian dollar as compared to the same period in 2009.

Measured in Canadian dollars, for the year ended December 31, 2010, operating expenses totalled $22.1 million, as compared to $23.2 million during the same period in 2009. Liberty Water reported lower expenses

from operations of $2.3 million as a result of the stronger Canadian dollar, as compared to the same period in 2009.

For the year ended December 31, 2010, Liberty Water’s operating profit totalled $15.8 million as compared to $16.7 million in the same period in 2009, a decrease of $0.9 million or 5.5%. Excluding other income, which includes a non-recurring gain on disposition of other assets (2009 - $1.4 million), operating profits increased by $0.4 million or 2.3%. Liberty Water’s operating profit did not meet expectations for the year ended December 31, 2010 primarily due to delays in receiving final decisions in respect of its current rate cases.


	Three months ended December 31						Three months ended December 31
	2010			2009			2010			2009
Number of
Wastewater connections								35,420			34,679
Wastewater treated (millions of gallons)								500			450

Water distribution connections								37,666			36,919
Water sold (millions of gallons)								1,400			1,400

		U.S. $			U.S. $			Can $			Can $
Assets for regulatory purposes (U.S. $)		155,258			147,581

Revenue
Wastewater treatment		5,334			4,526			5,436			4,815
Water distribution		4,096			3,496			4,174			3,719
Other Revenue		189			142			174			153

	$	9,619		$	8,164		$	9,784		$	8,687

Expenses
Operating expenses		(5,143	)		(4,660	)		(5,245	)		(4,976	)
Other income		17			(40	)		17			(43	)


Business Unit operating profit (including other income)	$	4,493		$	3,464		$	4,556		$	3,668

2010 Fourth Quarter Operating Results

During the quarter ended December 31, 2010, Liberty Water provided approximately 1.4 billion U.S. gallons of water to its customers, treated approximately 500 million U.S. gallons of wastewater and sold approximately 90 million U.S. gallons of treated effluent.

For the quarter ended December 31, 2010, Liberty Water’s revenue totalled U.S. $9.6 million as compared to U.S. $8.2 million during the same period in 2009, an increase of U.S. $1.4 million or 17.5%.

Revenue from water distribution totalled U.S. $4.1 million, as compared to U.S. $3.5 million during the same period in 2009, an increase of U.S. $0.6 million or 16.5%. The fourth quarter water distribution revenue was impacted by an increase of $0.1 million at the four Texas Silverleaf facilities primarily due to increased customer demand, U.S. $0.4 million at the LPSCo facility primarily due to the implementation of rate increases and U.S. $0.1 million related to the acquisition of Galveston as compared to the same period in 2009. In addition, the division experienced increased customer demand at four water distribution facilities as compared to the same period in 2009.

Revenue from wastewater treatment totalled U.S. $5.3 million, as compared to U.S. $4.5 million during the same period in 2009, an increase of U.S. $0.8 million or 17.9%. The fourth quarter wastewater treatment revenue was impacted by increased revenue of U.S. $0.2 million at the four Texas Silverleaf and Tall Timbers facilities primarily due to increased customer demand, increased revenue of U.S. $0.6 at the Woodmark, Black Mountain and the LPSCo facilities, primarily due to the implementation of rate increases and U.S. $0.1 million related to the acquisition of Galveston as compared to the same period in 2009.

For the quarter ended December 31, 2010, operating expenses totalled U.S. $5.1 million, as compared to U.S. $4.7 million during the same period in 2009. Overall expenses increased U.S. $0.5 million or 10.4% as compared to the same period in 2009. Operating expenses increased due to increased legal, insurance and property taxes of U.S. $0.4 million, $0.3 million related to rate case costs which, based on the rate case

decisions, must be expensed, partially offset by decreases of U.S. $0.1 million related to wages, salary and other operating costs and U.S. $0.1 million related to bad debt expense as compared to the same period in 2009. In the comparable period, the division capitalized U.S. $0.6 million related to rate case costs which were previously expensed due to the adoption of rate regulated accounting during the fourth quarter of 2009.

For the quarter ended December 31, 2010, Liberty Water’s operating profit totalled U.S. $4.5 million as compared to U.S. $3.5 million in the same period in 2009, an increase of U.S. $1.0 million or 29.7%. Liberty Water’s operating profit did not meet expectations for the three months ended December 31, 2010 primarily due to delays in receiving final decisions in respect of its current rate cases.

Measured in Canadian dollars, for the quarter ended December 31, 2010, Liberty Water’s revenue totalled $9.8 million, as compared to $8.7 million during the same period in 2009. Revenue from wastewater treatment totalled $5.4 million, as compared to $4.8 million during the same period in 2009, an increase of $0.6 million. Revenue from water distribution totalled $4.2 million, as compared to $3.7 million in the same period in 2009, an increase of $0.4 million. Liberty Water reported decreased revenue from operations of $0.3 million in the fourth quarter of 2010 as a result of the stronger Canadian dollar as compared to the same period in 2009.

Measured in Canadian dollars, for the quarter ended December 31, 2010, operating expenses totalled $5.2 million, as compared to $5.0 million during the same period in 2009. Liberty Water reported lower expenses from operations of $0.2 million as a result of the stronger Canadian dollar, as compared to the same period in 2009.

For the quarter ended December 31, 2010, Liberty Water’s operating profit totalled $4.6 million as compared to $3.7 million in the same period in 2009, an increase of $0.9 million or 24.2%. Liberty Water’s operating profit did not meet expectations for the three months ended December 31, 2010 primarily due to delays in receiving final decisions in respect of its current rate cases.

Outlook – Liberty Water

Liberty Water expects continuing modest customer growth in 2011. Liberty Water provides water distribution and wastewater collection and treatment services, primarily in the southern and southwestern U.S. where communities have traditionally experienced long-term growth and that provide continuing future opportunities for organic growth.

Revenue increases from rate cases completed in Arizona and Texas on an annualized basis will contribute an additional U.S. $10.2 million in revenue in Liberty Water. 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 is expected to be concluded by the first quarter of 2011.

Liberty Water continues to work with key stakeholders, including regulators, to help manage issues related to the issuance of decisions in its rate cases in a timely manner.

Completed Rate Cases

Date of Rate Increases

Annual U.S. $ Revenue
Increase Requested

Annual U.S. $ Revenue Increase
Granted

Facility

Arizona

Black Mountain

October 2010

1.0 million

0.7 million

Litchfield Park Service Company

December 2010

11.6 million

7.1 million

Rio Rico

February 2011

1.6 million

0.9 million

Texas

Texas Utilities (Silverleaf – 4 utilities)

October 2009

1.2 million

Tall Timbers

July 2009

0.2 million

Woodmark

January 2010

0.1 million


Rate Cases Awaiting Recommended Order & Opinion	Estimated Annual U.S. $ Revenue Increase Requested
Facility
Arizona
Bella Vista, Northern and Southern Sunrise	$	1.1 million

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 Water 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.

In Arizona, the ACC requires a full regulatory process for all rate cases using a historic test year. On August 5, 2010, Liberty Water received a recommended order (“ROO”) for its Black Mountain Sewer Company recommending an annualized rate increase of approximately $0.7 million. The ROO was approved in entirety at the Commission’s open meeting held in August.

On October 5, 2010, Liberty Water received a ROO for the LPSCo facility proposing an annualized revenue increase of $8.1 million. At the ACC open meeting held on December 10, 2010 to consider the ROO, the approved revenue increase was reduced to $7.1 million. As part of the LPSCo 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. LPSCo is entitled to recover the foregone revenue from the phase in of rates including carrying charges under terms to be determined during the second phase of the LPSCo rate case which focuses on amounts charged for hookup fees. This phase is expected to occur later in 2011.

On December 11, 2011, the ACC approved an order authorizing an annualized rate increase of $0.9 million for Rio Rico Utilities Inc., effective February 1, 2011. It is anticipated that the regulatory review of the proposed rates and tariffs for Bella Vista, Northern Sunrise, and Southern Sunrise will be completed in Q1 2011.

In Texas, the Texas Commission on Environmental Quality (“TCEQ”) allows the utility’s customers a period of 90 days from the effective date of the proposed rates to object to the imposition of interim rates pending final rates determination. If greater than 10% of a specific Texas utility’s customers object to the new proposed rates, the proposed rates would be subjected to a full regulatory hearing process administered by the TCEQ in order to finalize the rates. If fewer than 10% of the customers record an objection to the proposed rates, those proposed rates are likely to be adopted and declared final as proposed. Any difference between the interim rates charged and collected and the final rates as approved by TCEQ will be subject to a retroactive adjustment and refund on the customers’ subsequent monthly bill.

Liberty Water entered into negotiated settlements with the customers of the Texas Silverleaf and Tall Timbers facilities, resulting in the achievement of the full estimated annualized revenue increase of $1.2 million and $0.2 million, respectively. The Woodmark facility did not receive objections from 10% of the customer base and also achieved the full estimated annualized revenue increase of $0.1 million.

LOGO

LIBERTY ENERGY

Liberty Energy’s business strategy is to build its portfolio of electric and natural gas distribution utilities and electric transmission assets, sharing certain common infrastructure between utilities to support best-in-class customer care for its utility ratepayers.

In 2009, Liberty Energy announced plans to acquire the California Utility, in partnership with Emera. The acquisition was approved by both the CPUC and the Public Utilities Commission of Nevada in the fourth quarter of 2010. The transaction was completed on January 1, 2011 for a purchase price of approximately U.S. $131.8 million, subject to certain working capital and other closing adjustments. The acquisition 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. Liberty Energy’s ownership share of the cost of acquisition of the California Utility was primarily funded through the proceeds of subscription receipts held by Emera for 8.532 million APUC common shares at a price of $3.25 per share.

On December 9, 2010, Liberty Energy entered into agreements to acquire all issued and outstanding shares of Granite State, a regulated New Hampshire electric utility, and EnergyNorth, a regulated New Hampshire natural gas utility from National Grid for total consideration of U.S. $285.0 million which represents a multiple of 1.136 times the aggregate expected regulatory assets. 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.

Granite State provides electric service to over 43,000 customers in 21 communities in New Hampshire. Granite State’s load and customer counts have shown a consistent 1.6% compounded annual growth over the past 10 years. EnergyNorth provides natural gas services to over 83,000 customers in five counties and 30 communities in New Hampshire. EnergyNorth has a well diversified customer base with no individual customer accounting for more than 3% of gas volumes delivered. Both Granite State and EnergyNorth have capable and experienced work forces which will continue with the businesses following closing.

In connection with these acquisitions, Emera has agreed to a treasury subscription of subscription receipts convertible into 12.0 million APUC common shares upon closing of the transactions at a purchase price of $5.00 per share representing an approximate premium of 5% to the closing price on December 8, 2010. Delivery of the 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 of acquisition of Granite State and EnergyNorth. The issuance of these subscription receipts is subject to regulatory approval.

APUC: Corporate


	Three months ended December 31						Twelve months ended December 31
	2010			2009			2010		��	2009
Corporate and other expenses:
Administrative expenses and management costs		5,126			2,742			14,886			11,562
Write down of property and notes		2,492			6,457			2,492			6,457
Management internalization expense		—			4,693			—			4,693
Other corporatization expenses		—			3,460			—			3,460
Loss / (Gain) on foreign exchange		(54	)		(258	)		(528	)		(1,261	)
Interest expense		6,719			5,645			25,612			21,387
Interest, dividend and other Income		(985	)		(738	)		(3,599	)		(2,986	)
Loss (gain) on derivative financial instruments		(1,842	)		(1,515	)		1,103			(17,318	)
Income tax recovery		(15,539	)		(10,662	)		(20,228	)		(17,927	)

2010 Annual Corporate and Other Expenses

During the year ended December 31, 2010, management and administrative expenses totalled $14.9 million, as compared to $11.6 million in the same period in 2009. The expense increase in the twelve months ended December 31, 2010 results from increased capital taxes resulting from APUC’s effective conversion to a corporation in 2009, increased legal, audit, tax and other professional fees associated with APUC being registered with the SEC as a foreign private issuer, Algonquin continuing to be registered as reporting issuer in 2010, the corporate reorganization of the Liberty Water division and additional salaries related to the internalization of management and administering APUC’s operations as compared to the same period in 2009. In the comparable period, administrative expenses of $2.2 million were considered costs related to APUC’s conversion to a corporation and classified as other corporatization expenses.

In December 2010, APCo wrote down its investment in three small hydro facilities and recognized an impairment charge on property, plant and equipment of $1.8 million representing the difference between the carrying value of the assets and their fair value. The fair value of the facilities was estimated based on prior transactions involving sales of comparable facilities. In December 2010, the equipment at the Crossroads thermal facility in New Jersey met the conditions for“asset held for sale”. The equipment was sold subsequent to December 31, 2010. The carrying value was written down to its fair value less cost to sell resulting in a loss of $0.7 million, which was included in earnings for the period. The fair value of the equipment was based on the sales price.

In the comparable period in 2009, APCo decided to dispose of its investments in its remaining LFG facilities and its 50% ownership in the Drayton Valley facility. As a result of testing its investments for recoverability using a net realizable value valuation technique, APCo determined that these assets were impaired as at December 31, 2009. Accordingly, for the year ended December 31, 2009, APCo recognized an impairment charge of $1.1 million against the outstanding principal balance of a note receivable related to its LFG operations. APCo also wrote down the carrying value of its remaining LFG facilities and its 50% investment in the Valley Power facility to their estimated current fair value. This resulted in a write-down of property and equipment of $4,854 in the period representing the difference between the carrying value of the assets and their net realizable values.

During the year ended December 31, 2010, there were no costs recorded in association with management internalization. During the comparable period in 2009, APUC recorded an expense of $4.7 million with regards to an agreement to acquire the Manager’s interest in the management services agreement and internalize management in exchange for shares of APUC. On December 21, 2009, the Board ratified an agreement in principal with the shareholders of APMI to acquire the management contract and internalize management. Senior management expenses have been recorded within the Administrative Expense category on a go forward basis.

During the year ended December 31, 2010, there were no costs recorded associated with converting Algonquin to a corporation. During the comparable period, APUC recorded an expense of $3.5 million associated with costs of converting the Fund to a corporation.

Foreign exchange gains and losses primarily represent unrealized gains or losses on U.S. dollar denominated debt and working capital balances held by Canadian operating entities and do not impact current cash position. During the twelve months ended December 31, 2010, APUC classified all of its power generation operating facilities based in the U.S. as self-sustaining. As a result, foreign exchange translation gains and losses of U.S. denominated debt and working capital balances in these U.S. operating entities after January 1, 2010 no longer flow though the consolidated statement of operations. For the twelve months ended December 31, 2010, APUC reported a foreign exchange gain in relation to U.S. assets held by Canadian entities of $0.5 million as compared to a gain of $1.3 million during the same period in 2009. The twelve months ended December 31, 2010 experienced a decrease in value of the U.S. dollar of 5.4% which resulted in unrealized gains on APUC’s U.S. dollar denominated debt and working capital balances held by Canadian entities. In the comparable period in 2009, APUC’s power generation operating facilities based in the U.S. were classified as integrated and the decrease in the value of the U.S. dollar of 14.2% experienced in the period resulted in unrealized translation gains on APUC’s U.S. dollar denominated debt and working capital balances held by its integrated U.S. operating facilities.

For the twelve months ended December 31, 2010, interest expense totalled $25.6 million as compared to $21.4 million in the same period in 2009. Interest expense increased as a result of higher levels of convertible debentures and increased interest rates charged on variable rate debt, partially offset by decreased interest expense resulting from lower average borrowings on APUC’s variable interest rate credit facilities, as compared to the prior year.

For the twelve months ended December 31, 2010, interest, dividend and other income totalled $3.6 million as compared to $3.0 million in the same period in 2009. Interest, dividend and other income primarily consists of dividends from APUC’s share investments in the Kirkland and Cochrane facilities and interest related to APUC’s subordinated debt interest in the Red Lily I project. The income earned on the investments in the Kirkland and Cochrane facilities was previously allocated to interest and other income in the Thermal Energy division.

Loss on derivative financial instruments consists of realized and unrealized mark-to-market losses on foreign exchange forward contracts, interest rate swaps and forward energy contracts during the quarter. The unrealized portion of any mark-to-market gains or losses on derivative instruments does not impact APUC’s current cash position.

An income tax recovery of $20.2 million was recorded in the twelve months ended December 31, 2010, as compared to a recovery of $17.9 million during the same period in 2009. There are two primary reasons for the income tax recovery for the year. First, in the fourth quarter of 2010, APUC completed the Liberty Water portion of its overall capital structure project. The objective of the capital structure project was to ensure that APUC’s operating subsidiaries each have a capital structure that is appropriate for the business sector and functional currency in which it operates. Therefore as part of this process, APUC converted certain Canadian dollar denominated intercompany notes with Liberty Water into US dollar denominated notes resulting in a realized foreign exchange loss for tax purposes, thereby creating a future tax asset of approximately $12 million that is

now available as additional tax shelter in future years. Secondly, on October 27, 2009, Algonquin effectively converted from a publicly traded income trust to a publicly traded corporation. Included in future income tax recoveries for the year ended December 31, 2010 is $6.6 million related to the recognition of deferred credits from the utilization of future income tax assets which were set up based on the new corporate structure on October 27, 2009.

2010 Fourth Quarter Corporate and Other Expenses

During the quarter ended December 31, 2010, management and administrative expenses totalled $5.1 million, as compared to $2.7 million in the same period in 2009. The expense increase in the three months ended December 31, 2010 results from those factors identified in the discussion of the annual expense noted above as compared to the same period in 2009.

In December 2010, APCo wrote down its investment in three small hydro facilities and determined that the equipment at the Crossroads thermal facility in New Jersey met the conditions for“asset held for sale”. See the discussion in the annual corporate and other expenses section above for details related to this expense.

In the comparable period in 2009, APCo decided to dispose of its investments in its remaining LFG facilities and its 50% ownership in the Drayton Valley facility. See the discussion in the annual corporate and other expenses section above for details related to this expense.

During the year ended December 31, 2010, there were no costs recorded associated with converting the Fund to a corporation. During the comparable period, APUC recorded an expense of $3.5 million associated with costs of converting the Fund to a corporation.

For the quarter ended December 31, 2010, interest expense totalled $6.7 million as compared to $5.6 million in the same period in 2009. Interest expense increased as a result of higher levels of convertible debentures, and increased average interest rates charged on APUC’s variable interest rate credit facilities, partially offset by lower average borrowings on APUC’s variable interest rate credit facilities, as compared to the prior year.

For the quarter ended December 31, 2010, interest, dividend and other income totalled $1.0 million as compared to $0.7 million in the same period in 2009. Interest, dividend and other income primarily consists of dividends from APUC’s share investment in the Kirkland and Cochrane facilities and interest related to APUC’s subordinated debt interest in the Red Lily I project. The income earned on the investments in the Kirkland and Cochrane facilities was previously allocated to interest and other income in the Thermal Energy division.

An income tax recovery of $15.5 million was recorded in the three months ended December 31, 2010, as compared to a recovery of $10.7 million during the same period in 2009. The income tax recovery for the three months ended December 31, 2010 results from those factors identified in the discussion of the annual income

tax expense noted above. Included in future income tax recoveries for the three months ended December 31, 2010 is $2.4 million related to the recognition of deferred credits from the utilization of future income tax assets which were set up based on the new corporate structure on October 27, 2009.

NON-GAAP PERFORMANCE MEASURES

Reconciliation of Adjusted EBITDA to net earnings

EBITDA is a non-GAAP metric used by many investors to compare companies on the basis of ability to generate cash from operations. APUC uses these calculations to monitor the amount of cash generated by APUC as compared to the amount of dividends paid by APUC. APUC uses Adjusted EBITDA to assess the operating performance of APUC without the effects of depreciation and amortization expense which are non-cash and derived from a number of non-operating factors, accounting methods and assumptions. APUC believes that presentation of this measure will enhance an investor’s understanding of APUC’s operating performance. Adjusted EBITDA is not intended to be representative of cash provided by operating activities or results of operations determined in accordance with GAAP.

The following table is derived from and should be read in conjunction with the audited Consolidated Statement of Operations. This supplementary disclosure is intended to more fully explain disclosures related to Adjusted EBITDA and provides additional information related to the operating performance of APUC. Investors are cautioned that this measure should not be construed as an alternative to GAAP consolidated net earnings.


	Three months ended December 31						Twelve months ended December 31
	2010			2009			2010			2009

Net earnings (loss)	$	16,888		$	(1,366	)	$	19,639		$	31,257

Add:
Income tax recovery		(15,539	)		(10,662	)		(20,228	)		(17,927	)
Interest expense		6,719			5,645			25,612			21,387
Write down of property, plant and equipment		2,492			5,354			2,492			5,354
Write down of note receivable		—			1,103			—			1,103
Management internalization costs		—			4,693			—			4,693
Other corporatization costs		—			3,460			—			3,460
(Gain) / loss on derivative financial instruments		(1,842	)		(1,515	)		1,103			(17,318	)
Gain on foreign exchange		(54	)		(258	)		(528	)		(1,261	)
Amortization		11,900			11,350			46,573			45,883
Other		129			223			444			2,737


Adjusted EBITDA	$	20,693		$	18,027		$	75,107		$	79,368

For the year ended December 31, 2010, Adjusted EBITDA totalled $75.1 million as compared to $79.4 million, a net decrease of $4.3 million or 5.4% as compared to the same period in 2009. For the quarter ended December 31, 2010, Adjusted EBITDA totalled $20.7 million as compared to $18.0 million, an increase of $2.7 million or 14.8% as compared to the same period in 2009. The major factors impacting Adjusted EBITDA are set out below. A more detailed analysis of these factors is presented within the business unit analysis.


	Three months ended December 31 2010			Twelve months ended December 31 2010

Comparative Prior Period Adjusted EBITDA	$	18,027		$	79,368

Significant Changes:
Administration and management costs		(2,400	)		(3,300	)
Hydro Renewable – primarily due to lower hydrology		200			(3,400	)
Lower results from stronger Canadian dollar		(100	)		(3,000	)
Windsor Locks – change in operating model		—			(2,300	)
St. Leon – primarily due to a lower wind resource		800			(1,900	)
EFW – impact of shutdown		700			(1,700	)
Liberty Water gain on sale of excess land		—			(1,400	)
Acquisition of Tinker Hydro in Q1 2010		2,800			9,900
Red Lily – development fees		600			2,100
Liberty Water revenue increases primarily due to rate case approvals		1,600			2,000
Other		(1,534	)		(1,261	)


Current Period Adjusted EBITDA	$	20,693		$	75,107

Reconciliation of adjusted net earnings to net earnings

Adjusted net earnings is a non-GAAP metric used by many investors to compare net earnings from operations without the effects of certain volatile primarily non-cash items that generally have no current economic impact and are viewed as not directly related to a company’s operating performance. Net earnings of APUC can be impacted positively or negatively by gains and losses on derivative financial instruments, including foreign exchange forward contracts, interest rate swaps as well as to movements in foreign exchange rates on foreign currency denominated debt and working capital balances. APUC uses adjusted net earnings to assess the performance of APUC without the effects of gains or losses on foreign exchange, foreign exchange forward contracts and interest rate swaps as these are not reflective of the performance of the underlying business of APUC. APUC believes that analysis and presentation of net earnings or loss on this basis will enhance an investor’s understanding of the operating performance of APUC’s businesses. It is not intended to be representative of net earnings or loss determined in accordance with GAAP.

The following table is derived from and should be read in conjunction with the audited Consolidated Statement of Operations. This supplementary disclosure is intended to more fully explain disclosures related to adjusted net earnings and provides additional information related to the operating performance of APUC. Investors are cautioned that this measure should not be construed as an alternative to consolidated net earnings in accordance with GAAP.

The following table shows the reconciliation of net earnings to adjusted net earnings exclusive of these items:


	Three months ended December 31						Twelve months ended December 31
	2010			2009			2010			2009

Net earnings (loss)	$	16,888		$	(1,366	)	$	19,639		$	31,257

Add:
Loss (gain) on derivative financial instruments, net of tax		(1,292	)		(757	)		(1,688	)		(13,378	)
Write down of property and notes, net of tax		2,492			6,379			2,492			6,379
Management internalization expense, net of tax		—			4,693			—			4,693
Other corporatization expenses, net of tax		—			2,813			—			2,813
Gain on foreign exchange, net of tax		(54	)		(258	)		(528	)		(1,261	)


Adjusted net earnings	$	18,034		$	11,504		$	19,915		$	30,503

Adjusted net earnings per share unit	$	0.19		$	0.14		$	0.21		$	0.38

For the year ended December 31, 2010, adjusted net earnings totalled $19.9 million as compared to $30.5 million, a decrease of $10.6 million as compared to the same period in 2009. The decrease in adjusted net earnings in the twelve months ended December 31, 2010 is primarily due to higher interest expense and management and administrative expenses as compared to the same period in 2009.

For the three months ended December 31, 2010, adjusted net earnings totalled $18.0 million as compared to adjusted net earnings of $11.5 million, an increase of $6.5 million as compared to the same period in 2009. The increase in adjusted net earnings in the three months ended December 31, 2010 is primarily due to increased earnings from operations and increased future income tax recoveries, partially offset by increased interest expense as compared to the same period in 2009.

SUMMARY OF PROPERTY, PLANT AND EQUIPMENT EXPENDITURES


	Three months ended December 31					Twelve months ended December 31
	2010		2009			2010		2009
APCo
Renewable Energy Division
Capital expenditures	$	979	$	480		$	2,331	$	1,114
Acquisition of operating entities		—		—			40,281		—

Total	$	979	$	480		$	42,612	$	1,114

Thermal Energy Division
Capital expenditures	$	434	$	664		$	11,596	$	3,521

Total	$	434	$	664		$	11,596	$	3,521


LIBERTY WATER
Capital Investment in regulatory assets	$	4,584	$	(427	)	$	6,644	$	6,174
Acquisition of operating entities		—		—			2,121		—

	$	4,584	$	(427	)	$	8,765	$	6,174

LIBERTY ENERGY
Capital Investment in regulatory assets	$	—	$	—		$	—	$	—
Acquisition of operating entities		3,123		317			3,123		1,177

	$	3,122	$	317		$	3,123	$	1,177

Consolidated (includes Corporate)
Capital expenditures	$	1,595	$	1,144		$	14,187	$	4,742
Capital investment in regulatory assets		4,584		(427	)		6,644		6,174
Acquisition of operating entities		3,123		317			45,524		1,177

Total	$	9,302	$	1,034		$	66,240	$	12,093

APUC’s consolidated capital expenditures in the twelve months ended December 31, 2010 increased as compared to the same period in 2009 primarily due to the major capital upgrades completed at the EFW facility, the acquisition of the Tinker Assets and the Energy Services Business, costs associated with the acquisition by Liberty Energy of the California Utility and the acquisition by Liberty Water of a water distribution and wastewater treatment facility in Texas.

Property, plant and equipment expenditures for 2011 fiscal year are anticipated to be between $27 million and $34 million, including approximately $8.0 million related to ongoing requirements by Liberty Water, $3.0 million related to Liberty Energy’s share of ongoing requirements at the California Utility, $6.5 million related to the APCo Thermal division, and $8.0 million related to the APCo Renewable Energy division.

APUC anticipates that it can generate sufficient liquidity through internally generated operating cash flows, working capital and bank credit facilities to finance its property, plant and equipment expenditures and other commitments.

2010 Annual Property Plant and Equipment Expenditures

During the year ended December 31, 2010, APCo incurred capital expenditures of $14.2 million, as compared to $4.7 million during the comparable period in 2009. APCo also invested $40.2 million to acquire operating assets/entities during the twelve months ended December 31, 2010, as compared to nil million during the comparable period in 2009.

During the twelve months ended December 31, 2010, APCo Renewable Energy division’s capital expenditures were $2.3 million, as compared to $1.1 million in the comparable period in 2009. There were no individual projects in excess of $0.5 million initiated in the current period. The APCo Renewable Energy division’s acquisition of operating assets relate to the Tinker Assets located in New Brunswick and Maine.

During the twelve months ended December 31, 2010, APCo Thermal Energy division’s capital primarily relate to the EFW facility where major maintenance was completed subsequent to the end of the quarter. In the comparable period, the expenditures primarily related to minor capital projects at the hydro-mulch facility and the EFW facility.

During the twelve months ended December 31, 2010, Liberty Water invested maintenance capital of $6.6 million into regulatory assets, as compared to an investment of $6.2 million in the comparable period. During the twelve months ended December 31, 2010, Liberty Water acquired a water and wastewater utility near Galveston

Texas for approximately $2.0 million. In the comparable period in 2009, Liberty Water’s expenditures primarily related to the completion and commissioning of projects initiated in 2008.

During the twelve months ended December 31, 2010, Liberty Energy incurred costs associated with the acquisition by Liberty Energy of the California Utility of $3.0 million, as compared to $1.2 million in the comparable period.

As previously noted, these investments have been included in the rate case applications completed as well as those currently underway. In the comparable period, the expenditures primarily related to investment in additional wells, engineering work regarding wastewater treatment operations and arsenic treatment at the LPSCo facility. The expenditures in the comparable period are included in the rate case applications which are currently in process.

2010 Four Quarter Property Plant and Equipment Expenditures

During the three months ended December 31, 2010, APCo incurred capital expenditures of $1.6 million, as compared to $1.1 million during the comparable period in 2009.

During the three months ended December 31, 2010, APCo Renewable Energy division’s capital expenditures were not significant, consistent with the comparable period in 2009.

During the three months ended December 31, 2010, APCo Thermal Energy division’s capital expenditures were not significant, consistent with the comparable period in 2009.

During the three months ended December 31, 2010, Liberty Water invested maintenance capital of $4.6 million into regulatory assets, as compared to $0.4 million in the comparable period.

During the three months ended December 31, 2010, Liberty Energy incurred costs associated with the acquisition by Liberty Energy of the Calpeco facility of $3.0 million, as compared to $0.3 million in the comparable period.

LIQUIDITY AND CAPITAL RESERVES

The following table sets out the amounts drawn, letters of credit issued and outstanding amounts available to APUC and its subsidiaries as at December 31, 2010 under the senior banking Facility:


	2010 Q4			2010 Q3			2010 Q2			2010 Q1			2009 Q4

Committed and available Facility	$	142,000	*	$	163,400		$	162,800		$	177,950		$	179,500


Funds Drawn on Facility		(64,500	)		(108,900	)		(102,800	)		(91,650	)		(94,000	)
Letters of Credit issued		(33,100	)		(33,800	)		(34,600	)		(32,400	)		(33,100	)


Remaining available Facility	$	44,400	*	$	20,700		$	25,400		$	53,900		$	52,400


Cash on Hand		5,100			3,100			2,400			750			2,800


Total liquidity and capital reserves	$	49,500		$	23,800		$	27,800		$	54,650		$	55,200

*	Reflects availability under a new three year Facility announced on January 14, 2011.

As at and for the period ended December 31, 2010, APUC and Algonquin are in compliance with the covenants under the Facility.

As at December 31, 2010, CAD $64.5 million had been drawn on the Facilities as compared to CAD $94.0 million as at December 31, 2009. On December 22, 2010, Liberty Water obtained a U.S. $50 million long-term private placement financing. The notes are senior unsecured with a 10 year term bearing interest at 5.6%. The notes are interest only until June 2016 when annual principal repayments of U.S. $5.0 million annually commence. Proceeds were used to reduce amounts outstanding under the Facility. In addition to amounts actually drawn, there was $33.1 million in letters of credit outstanding as at December 31, 2010.

Subsequent to the year end, Algonquin concluded negotiations with its bank syndicate on the renewal of the Facility for a three year term with a maturity date of February 14, 2014. Algonquin reduced the total of the Facility as part of its capital structure initiatives to term out some of the short-term borrowings under the Facility.

Under the terms of the new banking agreement, as at December 31, 2010, Algonquin had $44.4 million of committed and available bank facilities remaining and $5.1 million of cash resulting in $49.5 million of total liquidity and capital reserves.

APUC expects to continue to reduce its level of short term borrowings under the Facility through obtaining appropriate long term debt through refinancing certain project specific financings or additional medium to long-term notes. APUC has received and is currently assessing several financing offers to term out the remainder of its short term bank credit facility and project debt coming due in the next three quarters. APUC anticipates concluding its assessments on these offers by the second quarter of 2011.

CONTRACTUAL OBLIGATIONS

Information concerning contractual obligations as of December 31, 2010 is shown below:


	Total		Due less than 1 year		Due 1 to 3 years		Due 4 to 5 years		Due after 5 years
Long-term debt obligations¹	$	259,131	$	70,490	$	3,238	$	68,395	$	117,008
Convertible Debentures	$	185,342		—		—		62,469		122,873
Interest on long-term debt obligations	$	164,830		25,670		48,198		35,889		55,073
Purchase obligations	$	33,506		33,506		—		—		—
Derivative financial instruments:
Currency forward	$	45		45		—		—		—
Interest rate swap	$	5,439		1,959		2,504		976		—
Energy forward contracts	$	378		378		—		—		—
Capital lease obligations	$	523		212		243		68		—
Other obligations	$	9,255		466		931		931		6,927


Total obligations	$	658,449	$	132,726	$	55,114	$	168,728	$	301,881

Long term obligations include regular payments related to long term debt and other obligations.

SHAREHOLDER’S EQUITY AND CONVERTIBLE DEBENTURES

On October 27, 2009, all of Algonquin’s trust units were exchanged for shares of APUC that began to be publicly traded on the Toronto Stock Exchange (“TSX”) while Algonquin’s trust units concurrently ceased trading on the TSX.

As at December 31, 2010, APUC had 95,422,778 issued and outstanding shares on a fully diluted basis. On January 1, 2011, following Emera’s exercise of its subscription receipts, APUC had 103,945,778 issued and outstanding shares on a fully diluted basis. The shares issued to Emera were in connection with APUC’s partnership with Emera entered into on April 23, 2009 wherein APUC agreed to issue approximately 8.5 million shares of APUC at a price of $3.25 per share to finance a portion of the acquisition of the California Utility.

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 share at meetings of the holders of common shares; and upon liquidation, dissolution or winding up of APUC, to receive a pro rata share of any remaining property and assets of APUC. All shares are of the same class and with equal rights and privileges and are not subject to future calls or assessments.

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

In 2009, APUC’s consideration received from the acquisition exceeded $26,970, the minimum contemplated under the agreements, and, as a result APUC is entitled to 50% of any additional proceeds from the assets formerly owned by Highground. CJIG is entitled to the remaining 50% of any proceeds in excess of the minimum amount. During the twelve months ended December 31, 2010, APUC received $0.2 million (2009 - $1.0 million) from CJIG as APUC’s share of the 50% of additional proceeds from the further liquidation of the assets held by Highground. This has been recorded as an increased amount assigned to the equity originally issued.

The remaining investments, formerly held by Highground, currently consist of two non-liquid debt assets having an approximate principal amount of $2.2 million. Debt representing $1,000 matured in December 2010 and the balance of the debt matures in the fourth quarter of 2012. Negotiations with the borrower of the $1,000 are currently underway to secure repayment. APUC’s 50% share of any additional proceeds from liquidation of the remaining Highground assets will be recorded when received as additional proceeds from the issuance of equity.

On December 21, 2009, the Board reached an agreement with the shareholders of APMI to internalize all management functions of APCo which were provided by the Manager. At a meeting of the shareholders held in June 2010, shareholders approved the issuance of shares in respect of the internalization of management. As a result, APUC acquired the interest previously held by APMI in the management services agreement through the issuance of 1,180,180 APUC shares during the quarter ended June 30, 2010. The management services agreement has since been terminated.

In July 2004, the Fund issued 85,000 convertible unsecured debentures at a price of $1,000 for each debenture maturing on July 31, 2011 (“Series 1 Debentures”). The Series 1 Debentures bore interest at 6.65% per annum and were convertible into trust units of the Fund at the option of the holder at a conversion price of $10.65 per trust unit, being a ratio of approximately 93.9 trust units for each $1,000 principal. On October 27, 2009, there were 84,964 convertible debentures outstanding with a face value of $84,964.

Pursuant to the CD Exchange Offer, on October 27, 2009, $63,755 of the outstanding Series 1 Debentures were exchanged for convertible debentures bearing interest at 7.5%, maturing on November 30, 2014 (“Series 1A Debentures”) convertible unsecured subordinated debentures in a principal amount of $66,943. The remaining Series 1 Debentures having a face value of $21,209, not converted to Series 1A Debentures pursuant to the CD Exchange Offer, were exchanged for 6,607,027 shares of APUC.

The Series 1A Debentures pay interest semi-annually in arrears on January 1 and July 1 each year and are convertible into shares of APUC at the option of the holder at a conversion price of $4.08 per share, being a ratio of approximately 245.1 shares for each $1,000 principal. The Series 1A Debentures may not be redeemed by APUC prior to January 1, 2011. During the period of January 2, 2011 until January 1, 2012, the debentures may be redeemed by APUC provided that the weighted-average trading price of the underlying share price on the TSX for the 20 consecutive trading days is equal to or exceeds a price of $5.10 (125% of the conversion price of $4.08). During the period of January 2, 2012 until the debenture’s maturity, APUC can redeem the debentures for 100% of the face value of debenture with cash, or for 105% of the face value of debenture with additional shares.

During the three months ended December 31, 2010, a principal amount of $982 of Series 1A Debentures were converted into 240,646 shares of APUC and a principal amount of $4,473 Series 1A Debentures were converted into 1,096,335 shares of APUC during the twelve months ended December 31, 2010. On December 31, 2010, there were 62,470 Series 1A Debentures outstanding with a face value of $62,470. Subsequent to the end of the quarter, $72 Series 1A Debentures were converted to 17,558 shares of APUC.

In November 2006, the Fund issued 60,000 convertible unsecured debentures at a price of $1,000 for each debenture maturing on November 30, 2016 (“Series 2 Debentures”). The Series 2 Debentures bore interest at 6.2% per annum and were convertible into trust units of the Fund at the option of the holder at a conversion price of $11.00 per trust unit, being a ratio of approximately 90.9 trust units for each $1,000 principal. During the three months ended December 31, 2009 and prior to October 27, 2009, Series 2 Debentures valued at $33,000 were exchanged into 3,000 trust units. These trust units were converted to shares of APUC as a result of the Unit Exchange. On October 27, 2009, there were 59,967 Series 2 Debentures outstanding with a face value of $59,967.

Pursuant to the CD Exchange Offer, on October 27, 2009, all of the outstanding Series 2 Debentures were exchanged for convertible unsecured subordinated debentures bearing interest at 6.35%, maturing on November 30, 2016 (“Series 2A Debentures”) in a principal amount of $59,967. The Series 2A Debentures pay interest semi-annually in arrears on April 1 and October 1 each year and are convertible into shares of APUC at the option of the holder at a conversion price of $6.00 per share, being a ratio of approximately 166.7 shares for each $1,000 principal. The Series 2A Debentures may not be redeemed by APUC prior to January 1, 2011. During the period of January 2, 2011 until January 1, 2012, the debentures may be redeemed by APUC provided that the weighted-average trading price of the underlying share price on the TSX for the 20

consecutive trading days is equal to or exceeds a price of $7.50 (125% of the conversion price of $6.00). During the period of January 2, 2012 until the debenture’s maturity, APUC can redeem the debentures for 100% of the face value of debenture with cash, or for 105% of the face value of debenture with additional shares. On December 31, 2010, there were 59,967 Series 2A Debentures outstanding with a face value of $59,967.

On December 2, 2009, APUC issued 63,250 convertible unsecured debentures at a price of $1,000 for each debenture maturing on June 30, 2017 (“Series 3 Debentures”). APUC received net proceeds of $60.7 million after underwriting expenses and before additional issuance costs (gross proceeds of $63.3 million). The Series 3 Debentures bear interest at 7.0% per annum, payable semi-annually in arrears on June 30 and December 30 each year, and are convertible into common shares of APUC at the option of the holder at a conversion price of $4.20 per common share, being a ratio of approximately 238.1 common shares for each $1,000 principal. The Series 3 Debentures may not be redeemed by APUC prior to December 31, 2012. During the period of January 1, 2013 until December 31, 2014, the Series 3 Debentures may be redeemed by APUC provided that the weighted-average trading price of the underlying share price on the TSX for the 20 consecutive trading days is equal to or exceeds a price of $5.25 (125% of the conversion price of $4.20). During the period of January 1, 2015 until the Series 3 Debentures’ maturity, APUC can redeem the Series 3 Debentures for 100% of the face value of the Series 3 Debentures with cash, or for 105% of the face value of the Series 3 Debentures with additional shares.

On December 31, 2009, there were 63,250 Series 3 Debentures outstanding with a face value of $63,250.

During the three months and year ended December 31, 2010, a principal amount of $345 of Series 3 Debentures was converted into 82,142 shares APUC. On December 31, 2010, there were 62,905 Series 3 Debentures outstanding with a face value of $62,905. Subsequent to the end of the quarter, $105 Series 3 Debentures were converted to 24,999 shares.

SHAREHOLDERS’ RIGHTS PLAN

APUC has adopted a Shareholders’ Rights Plan (the “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 and shareholders with adequate time to evaluate any unsolicited take-over bid and, if appropriate, to seek out alternatives to maximize shareholder value. The TSX has accepted notice for filing of the Rights Plan and 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 shares of APUC and be represented by certificates representing the 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 shares of APUC 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 shares of APUC 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 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 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 shares but must extend the bid for a further ten days to allow all other shareholders to tender.

STOCK OPTION PLAN

On June 23, 2010, APUC’s shareholders approved a stock option plan (the “Plan”) that permits the grant of share options to key officers, directors, employees and selected service providers. The aggregate number of shares that may be reserved for issuance under the Plan must not exceed 10% of the number of Shares outstanding at the time the options are granted. The number of shares subject to each option, the option price, the expiration date, the vesting and other terms and conditions relating to each option shall be determined by the Board from time to time. An option holder may elect to surrender any portion of the vested options which is then exercisable in exchange for the In-the-Money Amount. In accordance with the Plan, the “In-The-Money

Amount” represents the excess, if any, of the market price of a share at such time over the option price, in each case such In-the-Money amount being payable by APUC in cash or shares at the election of APUC. As APUC does not expect to settle these instruments in cash, these options are accounted for as equity awards.

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

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

The estimated fair value of options, including the effect of estimated forfeitures, is recognized as expense on the straight-line basis over the options’ vesting periods while ensuring that the cumulative amount of compensation cost recognized at least equals the value of the vested portion of the award at that date. At December 31, 2010, APUC recorded $108 (2009 - $nil) in compensation expense. As at December 31, 2010, there was $562 (2009 - $nil) of total unrecognized compensation costs related to non-vested options granted under the Plan. The cost is expected to be recognized over a period of 1.9 years.

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

MANAGEMENT OF CAPITAL STRUCTURE

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

APUC’s objectives when managing capital are:

•

To maintain its capital structure consistent with investment grade credit metrics appropriate to the sectors in which APUC operates;

•

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

•

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

•

To ensure generation of cash is sufficient to fund sustainable dividends to shareholders as well as meet current tax and internal capital requirements;

•

To maintain sufficient cash reserves on hand to ensure sustainable dividends made to shareholders; and

•

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

APUC monitors its cash position on a regular basis to ensure funds are available to meet current normal as well as capital and other expenditures. In addition, APUC continuously reviews its capital structure to ensure its individual business units are using a capital structure which is appropriate for their respective industries.

RELATED PARTY TRANSACTIONS

•

Up to December 21, 2009, APMI provided management services to the Fund including advice and consultation concerning business planning, support, guidance and policy making and general management services. On December 21, 2009, the Board reached an agreement (“Management Internalization Agreement”) with APMI to internalize all management functions of Algonquin which were provided by APMI. APUC acquired APMI’s interest in the management services agreement, with consideration paid in the form of issuance of 1,158,748 APUC shares (the “Shares”). For accounting purposes, the expense has been measured at $4,693 using a price for each Share of $4.03, the adjusted closing market price on December 21 2009, the date the agreement was ratified. Therefore,

for the three and twelve months ended December 31, 2010, APMI was not paid a management fee. For the three and twelve months ended December 31, 2009, APMI was paid on a cost recovery basis for costs incurred and charged $211 and $850 respectively.

•

APUC has leased its head office facilities since 2001 from an entity owned by the shareholders of APMI on a triple net basis. Base lease costs for the three and twelve months ended December 31, 2010 were $82 (2009 - $82) and $327 (2009 - $331) respectively. Based on a review of the real estate leasing market at the time, APUC believes the lease was entered into on terms equivalent to fair market value for prime office space of similar size and quality.

•

APUC utilizes chartered aircraft, including the use of an aircraft owned by an affiliate of APMI. In 2004, APUC entered into an agreement and remitted $1.3 million to the affiliate as an advance against expense reimbursements (including engine utilization reserves) for APUC’s business use of the aircraft. Under the terms of this arrangement, APUC will have priority access to make use of the aircraft for a specified number of hours at a cost equal solely to the third party direct operating costs incurred when flying the aircraft. During the three and twelve months ended December 31, 2010, APUC incurred costs in connection with the use of the aircraft of $60 (2009 - $60) and $430 (2009 - $367), respectively, and amortization expense related to the advance against expense reimbursements of $13 (2009 - $35) and $112 (2009 - $153), respectively. At December 31, 2010, the remaining amount of the advance was $554 (2009 - $666) and is recorded in other assets.

•

Affiliates of APMI hold 60% of the outstanding Class B limited partnership units issued by St. Leon Wind Energy LP (“St. Leon LP”), an indirect subsidiary of APUC and the legal owner of the St. Leon facility. The holders of the Class B Units are entitled to 2.5% of the income allocations and cash distributions from St. Leon LP for a five year period commencing June 17, 2008 growing to a maximum of 10% by year fifteen. In any particular period, cash distributions to the holders of the Class B Units are only to be made after distributions have been made to the other partners, in an aggregate amount equal to the debt service on the outstanding debt in respect of such period. The related party holders of the Class B units are entitled to cash distributions of $77 (2009 - $71) and $266 (2009 - $292) for the three and twelve months ended December 31, 2010, respectively.

•

During 2007, Algonquin allowed its offer to acquire Clean Power Income Fund to expire and earned a termination fee of $1.8 million of which APUC agreed to pay APMI $0.1 million. This amount has been accrued and included in accounts payable on the consolidated balance sheet.

•

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

•

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

•

APMI is one of the two original developers of Red Lily I and both developers are entitled to a royalty fee based on a percentage of operating revenue and a development fee from the equity owner of Red Lily I. The royalty fee is initially equal to 0.75% of gross energy revenue, increasing every five years to a maximum of 2% after twenty-five years. APUC has agreed to acquire APMI’s interest in this royalty 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 the portion of such fee which will be paid following commercial operation of the facility. APUC received and recognized $0.2 million in other revenue related to this fee in the twelve months ended December 31, 2010.

•

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

•

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

•

A member of the Board of Directors of APUC is an executive at Emera. A contract with a subsidiary of Emera to purchase energy on ISO-NE and provide scheduling services on ISO-NE was included as part of the acquisition of the Energy Services Business associated with the Tinker Acquisition. The contract expired in the three months ended March 31, 2010 and was not renewed. As a result of this contract, during the three months ended March 31, 2010, a subsidiary of Emera provided services to and

purchased energy on ISO-NE on behalf of the Energy Services Business. In this capacity, APUC paid a subsidiary of Emera an amount of $1,368 (2009 - $nil) which was included as an operating expense on the consolidated statement of operations.

•

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

•

During the period ended June 30, 2010, APUC entered into a one year contract with a subsidiary of Emera to provide lead market participant services for fuel capacity and forward reserve markets in ISO-NE for the Windsor Locks facility. During the three and twelve months ended December 31, 2010 APUC paid U.S. $69 (2009 - $nil) and U.S. $196 (2009 - $nil) in relation to this contract. In the same period, APUC issued a letter of credit to a subsidiary of Emera in an amount of U.S. $500 in conjunction with this contract. Subsequent to December 31, 2010, this letter of credit was replaced with a corporate guarantee.

•

APUC believes that the transactions with Emera noted above were in accordance with normal commercial terms.

Business associations with APMI and Senior Executives.

There are a number of continuing business relationships between APUC and one of Ian Robertson and Chris Jarratt (“Senior Executives”), APMI and related affiliates. These relationships include joint ownership of certain generating facility assets, business relationships between the parties and payment of fees associated with previous transactions. The Board has initiated a process to review all of the remaining business associations with Senior Executives, APMI and related affiliates in order to reduce, streamline and simplify these relationships. Any acquisitions associated with this process will only proceed if they are expected to be accretive to APUC.

The Board has formed a special committee and intends to engage independent consultants to assist with this process and expects to conclude this process over the next three months.

The co-owned assets and remaining business associations consist of the following:

i)	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.

ii)

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.

iii)

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. As of December 31, 2010, this amount is accrued and included in accounts payable on the consolidated balance sheet.

iv)

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 after tax equity cash flows commencing in 2014.

v)	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, 2010, $554 of the advance remained.

vi)

Office lease

APUC has leased its head office facilities on a triple net basis from an entity partially owned by Senior Executives. The lease expires in December 31, 2012. Based on a review of the real estate leasing market at the time, APUC believes the lease was on terms equivalent to fair market value for prime office space of similar size and quality.

vii)

Operations services

Staff managed by APUC operate an additional three hydroelectric generating facilities where Senior Executives hold an interest. Each facility is charged on a full cost recovery basis for these staff. Effective January 1, 2011, management of these facilities is being undertaken by a non-APUC related entity. APUC is providing some transition services to the non-APUC entity.

viii)

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.

ix)

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, 2010 this amount is accrued and included in accounts payable on the consolidated balance sheet.

x)	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 agreed to acquire 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.

xi)

Trafalgar

APCo owns debt on seven hydroelectric facilities owned by Trafalgar Power Inc. and an affiliate (“Trafalgar”). In 1997, Algonquin moved to foreclose on the assets, and subsequently Trafalgar went into bankruptcy. Trafalgar had previously won a $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 then reached 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 costs with the proceeds from the lawsuits being shared after reimbursement of legal costs. The Second Circuit Court of Appeals recently dismissed all the claims against APCo in the civil proceedings and remanded one issue to the District Court. The bankruptcy proceedings are continuing.

TREASURY RISK MANAGEMENT

APUC attempts to proactively manage the risk exposures of its subsidiaries in a prudent manner. APUC ensures that both APCo and Liberty Water 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, any 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 may encounter. A further assessment of APUC and its subsidiaries’ business risks is also set out in the most recent AIF.

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 45% of EBITDA and 60% 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 $15.5 million and increased reported expenses from U.S. operations of approximately $11.5 million or a net impact of $4.0 million ($0.038 per share) on an annual basis.

The change in unrealized mark-to-market losses/(gains) on derivative financial instruments resulting from changes in foreign exchange rates relate to contract periods which extend to fiscal 2013. Unrealized mark-to-market losses on derivative financial instruments resulting from changes in interest rates relate to contract periods which extend to fiscal 2015. The following charts provides a summary of the year to date changes between realized and unrealized mark-to-market gains and losses of derivative financial instruments:


	Year ended December 30
	2010			2009			Change

Foreign Exchange Contracts:
Change in unrealized mark-to-market gain on derivative financial instruments	$	(1,424	)	$	(15,682	)	$	14,258
Realized loss/(gain) on derivative financial instruments		(620	)		284			(904	)

	$	(2,044	)	$	(15,398	)	$	13,354

Interest Rate Swap Contracts:
Change in unrealized mark-to-market gain on derivative financial instruments	$	(2,787	)	$	(7,424	)	$	4,637
Realized loss on derivative financial instruments		5,929			5,504			425

	$	3,142		$	(1,920	)	$	5,062

Energy Forward Purchase Contracts:
Change in unrealized mark-to-market gain on derivative financial instruments	$	(2,931	)	$	—		$	(2,931	)
Realized loss on derivative financial instruments		2,936		$	—		$	2,936

	$	5		$	—		$	5

Derivative Financial Instruments Total:
Change in unrealized mark-to-market gain on derivative financial instruments	$	(7,142	)	$	(23,106	)	$	15,964
Realized loss on derivative financial instruments		8,245			5,788		$	2,457

Total loss/(gain) on derivative financial instruments	$	1,103		$	(17,318	)	$	18,421

The following chart provides a summary of the quarter over quarter changes between realized and unrealized mark-to-market gains and losses of derivative financial instruments:


	Three months ended December 31
	2010			2009			Change

Foreign Exchange Contracts:
Change in unrealized mark-to-market gain on derivative financial instruments	$	(697	)	$	(1,261	)	$	564
Realized gain on derivative financial instruments		(28	)		(148	)		120

	$	(725	)	$	(1,409	)	$	684

Interest Rate Swap Contracts:
Change in unrealized mark-to-market loss/(gain) on derivative financial instruments	$	(2,333	)	$	(1,627	)	$	(706	)
Realized loss on derivative financial instruments		1,294			1,520			(226	)

	$	(1,039	)	$	(107	)	$	(932	)

Energy Forward Purchase Contracts:
Change in unrealized mark-to-market gain on derivative financial instruments	$	(482	)	$	—		$	(482	)
Realized loss on derivative financial instruments		404		$	—			404

	$	(78	)	$	—		$	(78	)

Derivative Financial Instruments Total:
Change in unrealized mark-to-market gain on derivative financial instruments	$	(3,512	)	$	(2,888	)	$	(624	)
Realized loss on derivative financial instruments		1,670			1,372			298

Total loss/(gain) on derivative financial instruments	$	(1,842	)	$	(1,516	)	$	(326	)

APUC previously managed this risk primarily through the use of forward contracts as it required U.S. dollar cash inflows to meet Canadian dollar cash outflows. As a result of the current business strategy and lower payout ratio, APUC has determined that the prior practice of hedging 100% of its U.S. currency exposure is no longer appropriate and is taking steps to eliminate its existing forward currency contract program. During the twelve months ended December 31, 2010, APUC terminated forward contracts of $36.8 million. APUC’s policy is not to utilize derivative financial instruments for trading or speculative purposes. For the twelve months ended December 31, 2010, APUC realized cash gains of $0.5 million on managing its forward contracts.

The following chart sets out as at December 31, 2010 the amounts, hedge proceeds and average hedged rates over the term of the foreign exchange forward contracts outstanding. The remaining contracts were terminated subsequent to the end of the quarter:


	Total			2011		2012

Total U.S. $ Hedged	$	3,000		$	—	$	3,000
Total Can. $ Proceeds	$	3,000			—		3,000


Average Hedged Rate	$	1.000			n/a	$	1.000

Unrealized Gain (loss)	$	(45	)		n/a		(45	)

Impact of a $0.10 move in exchange rates	$	300			n/a	$	300

Based on the fair value of the forward contracts using the exchange rates as at December 31, 2010, the exercise of these forward contracts will result in the use of cash of $45 in fiscal 2012. Assuming a decrease in the strength of the U.S. dollar relative to the Canadian dollar of $0.10 at December 31, 2010, with a corresponding increase in the forward yield curve, the fair value of the outstanding forward exchange contracts would increase by $0.3 million in fiscal 2012.

Market price risk

The majority of APCo’s electricity generating facilities sell their output pursuant to long-term PPAs. However, certain of APCo’s hydroelectric facilities in the New England and New York regions 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.

Credit/Counterparty risk

APUC and its subsidiaries are subject to credit risk through its trade receivables. APUC does not believe this risk to be significant as approximately 72% of APCo Renewable Energy division’s revenue, approximately 70% of APCo Thermal Energy division’s revenue, and over 56% of 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+		20,500		25	%
Manitoba Hydro		AA		19,700		24	%
Ontario Electricity Financial Corporation		A+		8,400		10	%
Maine Public Service				4,600		6	%
National Grid		A-		3,100		4	%
Public Service Company of New Hampshire		BBB		2,800		3	%

Total			$	59,100		72	%
Thermal Energy Division
Pacific Gas and Electric Company		BBB+		15,700		25	%
Regional Municipality of Peel		AAA		14,500		23	%
Ahlstrom		1R3		11,400		18	%
Connecticut Light and Power Company		BBB		5,800		9	%

Total			$	65,700		70	%

*	Ratings by Dunn & Bradstreet or Standard & Poor’s as of February 2011

The remaining revenue is primarily earned by Liberty Water. In this regard, the credit risk related to Liberty Water accounts receivable balances of U.S. $5.0 million is spread over approximately 70,000 customers, resulting in an average outstanding balance of approximately $72.00 per customer. Liberty Water has processes in place to monitor and evaluate this risk on an ongoing basis including background credit checks and security deposits from new customers.

Interest rate risk

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 Facility has an outstanding balance drawn of CAD $64.5 million as at December 31, 2010. Assuming the current level of borrowings over an annual basis, a 1% change in the variable rate charged would impact interest expense by CAD $0.6 million annually. Algonquin had fixed for floating interest rate swap in an amount of CAD $100.0 million which expired on December 31, 2010. At December 31, 2010, the mark-to-market value of the interest rate swap was nil (2009 – $3.3 million net liability).

•

APCo’s project debt at the St. Leon facility had a balance of $68.8 million as at December 31, 2010. Assuming the current level of borrowings over an annual basis, a 1% change in the variable rate charged would impact interest expense by $0.7 million annually. Although the underlying debt with the project lenders carries variable rate of interest tied to the Canadian bank’s prime rate, APCo has entered into a fixed for floating interest rate swap on this project specific debt until September 2015 which mirrors the underlying debt’s interest and principal repayment schedule. This minimizes volatility in the interest expense on this debt. The financial impact of interest rate changes are effectively offset between the change in interest expense and the change in value of the interest rate swap. APCo has effectively fixed its interest expense on its senior debt facility at 5.47%. At December 31, 2010, the mark-to-market value of the interest rate swap was a net liability of $5.4 million (2009 – net liability of $5.0 million).

•

APCo’s project debt at its Sanger cogeneration facility has a balance of U.S. $19.2 million as at December 31, 2010. Assuming the current level of borrowings over an annual basis, a 1% change in the variable rate charged would impact interest expense by U.S. $0.2 million annually.

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. APUC’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.

APUC currently pays a dividend of $0.24 per share per year. On March 3, 2011, the Board approved an annual dividend increase of $0.02 per common share for a total annual dividend of $0.26, paid quarterly at a rate of $0.065 per common share. The Board determines the amount of dividends to be paid, consistent with APUC’s commitment to the stability and sustainability of future dividends, after providing for amounts required to administer and operate APUC and its subsidiaries, for capital expenditures in growth and development opportunities, to meet current tax requirements and to fund working capital that, in its judgment, ensure APUC’s long-term success. Based on the level of dividends paid during the three and twelve months ended December 31, 2010, cash provided by operating activities exceeded dividends declared by 3.2 times and 2.0 times respectively.

As at December 31, 2010, APUC had cash on hand of $5.1 million and $44.4 million available to be drawn on the Facility. The Facility was renewed subsequent to December 31, 2010 and therefore the Facility has been classified on the consolidated balance sheet as a long term liability.

APUC reduced its level of short-term borrowings through the renewal of the Facility on February 14, 2011 for a three year term and through a U.S. $50 million private placement debt financing at Liberty Water on December 22, 2010. In addition, APUC continues to seek to reduce short term borrowings by obtaining appropriate long term debt through refinancing certain project specific financings or additional medium to long term notes. See the Liquidity and Capital Reserves section for a more detailed discussion and chart of the funds available to APUC and its subsidiaries under the Facility.

The Facility and project specific debt total approximately $257.4 million with maturities set out in the Contractual Obligation table. In the event that APUC was required to replace the Facility and project debt with borrowings having less favourable terms or higher interest rates, the level of cash generated for dividends and reinvestment into the company may be negatively impacted. APUC attempts to manage the risk associated with floating rate interest loans through the use of interest rate swaps.

The cash flow generated from several of APUC’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 APUC losing its investment in such operating facility. APUC actively manages cash availability at its operating facilities to ensure they are adequately funded and minimize the risk of this possibility.

Commodity price risk

APCo’s exposure to commodity prices is primarily limited to exposure to natural gas price risk. Liberty Water is not subject to any material commodity price risk. In this regard, a discussion of this risk is set out as follows:

•

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 expenses of approximately $1.0 million on an annual basis. However, because the facility’s energy price is linked to the price of natural gas, this increase would result in a corresponding increase in revenue of $1.2 million or a net increase in operating profits of approximately $0.2 million.

•

APCo’s Windsor Locks facility’s ESA includes provisions which reduce its exposure to natural gas price risk buts 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 expenses of approximately $1.0 million on an annual basis. However, historically, changes in the price of natural gas are generally matched with changes in market electricity prices which should result in a minimal impact on operating profit.

•

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 expenses of approximately $0.1 million on an annual basis. However, because the facility’s energy price is linked to the price of natural gas, this increase would result in a corresponding increase in revenue of $0.2 million or a net increase in operating profits of approximately $0.1 million.

•

APCo’s Energy Services Business provides the 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 2011. While the Tinker Assets are expected to provide the majority of the energy required to service these customers, the Energy Services Business 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 the Energy Services Business 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 though the use of short-term financial energy hedge contracts. APCo has committed to acquire approximately 12,000 MW-hrs of net energy over the next 2 months at an average rate of approximately $70 per MW-hr. The mark-to-market value of these forward energy hedge contracts at December 31, 2010 was a net liability of U.S. $0.4 million.

Subsequent to December 31, 2010, APCo entered into a financial energy hedge contract to acquire approximately 215,000 MW-hrs of energy over a three year period starting March 1, 2011 at an average rate of approximately $50 per MW-hr.

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 more detailed assessment of APUC’s business risks is also set out in the most recent AIF.

Mechanical and Operational Risks

APUC is entirely dependant upon the operations and assets 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. The water distribution networks of the Liberty Water 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 diversification of APUC’s operations, both operationally (APCo and Liberty Water) and geographically (Canada and U.S.), the use of regular maintenance programs, maintaining adequate

insurance and the establishment of reserves for expenses. In addition, APCo’s existing long term PPAs minimize the risk of reductions in average energy pricing.

Regulatory Risk

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

Liberty Water’s facilities are subject to rate setting by State regulatory agencies. Liberty Water has five ongoing rate cases before regulatory bodies in Arizona and Texas in varying stages of completion. More details regarding the status of these proceedings are set out in Outlook – Liberty Water. The time between the incurrence of costs and the granting of the rates to recover those costs by utility commissions 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.

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 Water, and while Liberty Water 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 Water regularly works with these authorities to manage the affairs of the business.

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.

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 Renewable Energy division’s 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 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 APCo Thermal Energy division’s EFW facility owns the property on which its facility operates. EFW’s current waste incineration agreement expires in 2012 with two five year options to extend. 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 Water’s facilities operate under agreements with a state or municipal regulator to provide the sole water distribution and/or wastewater treatment services in its area of operations, as set out in the agreements. In general, these facilities are operated with the assumption that their services will be required in perpetuity and there are no contractual decommissioning requirements. In order to remain in compliance with the applicable regulatory bodies, Liberty Water 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 Water is allowed to earn a return on its investment.

Environmental Risks

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. APCo has assessed the likelihood of these risks becoming a contingent environmental liability as remote; therefore APCo 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 operating 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 7 full time equivalent positions based out of head office and have an annual budget of approximately $1.0 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.

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 Water 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 wastewater treatment facility include potential air quality and odour management issues, wastewater spills and surface and ground water contamination. In order to monitor and mitigate these risks, and to remain within the regulatory requirements appropriate for the specific facility, Liberty Water 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 Water 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.

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.

Specific Environmental Risks

Greenhouse Gas Initiatives:

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 several states where APCo operates facilities including Connecticut and New Jersey. 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 2010, 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.

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 (“WCI”). This group recently released details of its Regional Cap-and-Trade Program, which is scheduled to start on January 1, 2012. 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. As this process has just begun, it is too early to determine the potential financial impact on APCo and means available to mitigate this financial impact, if any.

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 at the end of June 2008. 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.

Renewable Energy Division:

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. This is discussed in greater detail within the analysis of results in the Renewable Energy Division.

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 Quebec facilities, as there are fewer facilities in Ontario and they are of newer construction.

Liberty Water:

Liberty Water owns and operates the LPSCo facility, a water distribution and waste-water treatment utility servicing the City of Litchfield Park,and parts of the City of Goodyear, the City of Avondale and the County of Maricopa, Arizona, 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 LPSCo 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, LPSCo 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 LPSCo. EPA’s monitoring and control efforts have not indicated that the concentrations are being reduced or fully captured. Additional remedial efforts by the EPA to stop advancement and reduce TCE concentrations are underway. In the event that any wells exceed EPA permitted TCE level, LPSCo 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

LPCSo’s customers. In addition, LPSCo has identified alternate sites where replacement wells can be established to replace this lost capacity. The cost of establishing a new well is estimated to be between $2.0 million and $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, volume of water available at the new site, and acquisition of land and groundwater rights. Liberty Water does not believe it is exposed to a material liability and has not recorded a contingent environmental liability on its financial statements.

APUC’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, 2010.

Seasonal fluctuations and 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. It is, however, anticipated that due to the geographic diversity of the facilities, variability of total revenues will be minimized. For Liberty Water’s water utilities, demand for water 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 or rainfall is more frequent than normal the demand for water may decrease adversely affecting revenues.

Wind resource

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 the facility. 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.

Litigation risks and other contingencies

APUC and certain of its subsidiaries are involved in various litigations, 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.

As reported in previous public filings of Algonquin and as discussed above under“Related Party Transactions”, APUC and an affiliate of APMI are involved in civil proceedings and bankruptcy proceedings with Trafalgar, Algonquin acquired notes secured by, among other things, seven hydroelectric facilities owned by Traflagar. In 1997, Algonquin moved to foreclose on the assets, and subsequently Trafalgar went into bankruptcy. Trafalgar had previously won a $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. Trafalgar commenced an action in 1999 in U.S. District Court against Algonquin, APMI and various other entities related to them in connection with, among other things, the sale of the one of the notes by Aetna Life Insurance Company to the Fund and in connection with the foreclosure on the security for the note. In 2006, the District Court decided that Aetna had complied with the provisions concerning the sale of the note, that Algonquin was therefore the holder and owner of the note, and that all other claims by Trafalgar with respect to the transfer of the note were without merit. In 2008 Algonquin filed for summary judgement seeking dismissal of Trafalgar’s remaining claims, and the District Court granted this motion on November 6, 2008. On October 22, 2009 Trafalgar filed an appeal from the November 6, 2008 summary judgement to the United States Court of Appeals for the Second Circuit. The Second Circuit Court of Appeals on November 1, 2010 dismissed all the claims against APCo in the civil proceedings. The bankruptcy proceedings are continuing.

On December 19, 1996, the Attorney General of Québec (“Québec AG”) filed suit in Québec Superior Court against Algonquin Développement Côte Ste-Catherine Inc. (Développement Hydromega), a predecessor company to an APUC subsidiary. The Québec AG at trial claimed $5.4 million for amounts that the APUC entities have been paying to the federal authority under its water lease with the authority. The APUC entities brought the Attorney General of Canada into the proceedings. On March 27, 2009, the Superior Court dismissed the claim of the Québec AG. Québec AG appealed this decision on April 24, 2009 and the appeal was heard by the Court of Appeal January 31, 2011. The Côte Ste-Catherine Facility currently pays water lease dues to the federal government, but if the Québec AG is successful in final appeal, an adjustment and/or increase of such amounts is possible.

Obligations to serve

Liberty Water’s utility 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 Water may be required to solicit additional capital or obtain additional borrowings to finance these future construction obligations.

Tax risks associated with the Unit Exchange Offer

There is a possibility that the Canada Revenue Agency could successfully challenge the tax consequences of the Unit Exchange or prior transactions of Hydrogenics or that legislation could be enacted or amended resulting in different tax consequences from those contemplated in the Unit Exchange Offer 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.

Disclosure Controls

At the end of the fiscal year ended December 31, 2010, APUC carried out an evaluation, under the supervision of and with the participation of the APUC’s management, including the Chief Executive Officer (“CEO”) and the Chief Financial Officer (“CFO”), of the effectiveness of the design and operations of the Company’s disclosure controls and procedures (as defined in Rule 13a – 15(e) and Rule 15d – 15(e) under the Securities Exchange Act of 1934, as amended (the “Exchange Act”)). Based on that evaluation, the CEO and the CFO have concluded that as of December 31, 2010, APUC’s disclosure controls and procedures were adequately designed and effective in ensuring that: (i) information required to be disclosed by APUC in reports that it files or submits to the Securities and Exchange Commission under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in applicable rules and forms and (ii) material information required to be disclosed in its reports filed under the Exchange Act is accumulated and communicated to management, including the CEO and CFO, as appropriate, to allow for accurate and timely decisions regarding required disclosure.

Internal controls over financial reporting

APUC’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles.

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

Because of its inherent limitations, internal control over financial reporting may not prevent or detect all misstatements. Additionally, projections of any evaluation of effectiveness to future periods are subject to the

risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

Management conducted an evaluation of the design and operation of APUC’s internal control over financial reporting as of December 31, 2010 based on the criteria set forth in Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. This evaluation included review of the documentation controls, evaluation of the design effectiveness of controls, testing of the operating effectiveness of controls and a conclusion on this evaluation. Based on this evaluation, management has concluded that APUC’s internal control over financial reporting was effective as of December 31, 2010.

During the year ended December 31, 2010, there has been no change in APUC’s internal control over financial reporting that has materially affected, or is reasonably likely to materially affect, APUC’s internal control over financial reporting.

Quarterly Financial Information

The following is a summary of unaudited quarterly financial information for the two years ended December 31, 2010.


Millions of dollars (except per share amounts)	1^st Quarter 2010		2^nd Quarter 2010			3^rd Quarter 2010		4^th Quarter 2010
Revenue	$	45.9	$	42.7		$	45.4	$	48.9
Net earnings /(loss)		3.5		(2.2	)		1.5		16.9
Net earnings / (loss) per share		0.04		(0.02	)		0.02		0.18

Total Assets		966.2		983.2			969.4		980.9
Long term debt*		434.0		446.7			452.8		461.0

Dividend/distribution per share		0.06		0.06			0.06		0.06

	1^st Quarter 2009		2^nd Quarter 2009			3^rd Quarter 2009		4^th Quarter 2009
Revenue	$	52.2	$	46.5		$	45.1	$	43.4
Net earnings / (loss)		4.2		15.3			13.1		(1.4	)
Net earnings / (loss) per trust unit		0.05		0.20			0.17		(0.03	)

Total Assets		974.2		952.4			925.7		1,013.4
Long term debt*		457.6		456.2			445.4		439.9

Distribution per trust unit		0.06		0.06			0.06		0.06

*	Long term debt includes long term liabilities, the Facility, convertible debentures and other long term obligations

The quarterly results are impacted by various factors including seasonal fluctuations and acquisitions of facilities as noted in this MD&A.

Quarterly revenues have fluctuated between $42.7 million and $52.2 million over the prior two year period. A number of factors impact quarterly results including seasonal fluctuations, hydrology and winter and summer rates built into the PPAs. In addition, a factor impacting revenues year over year is the significant fluctuation in the strength of the Canadian dollar which has resulted in significant changes in reported revenue from U.S. operations.

Quarterly net earnings have fluctuated between net earnings of $16.9 million and a net loss of $2.2 million over the prior two year period. Earnings have been significantly impacted by non-cash factors such as future tax expense due to the enactment of Bill C-52 and mark-to-market gains and losses on financial instruments.

Critical Accounting Estimates

APUC prepared its Consolidated Financial Statements in accordance with Canadian GAAP. An understanding of APUC’s accounting policies is necessary for a complete analysis of results, financial position, liquidity and trends. Refer to Note 1 to the Consolidated Financial Statements for additional information on accounting principles. The Consolidated Financial Statements are presented in Canadian dollars rounded to the nearest thousand, except per unit amounts and except where otherwise noted.

Additional disclosure of APUC’s critical accounting estimates is also available in APUC’s MD&A for the year ended December 31, 2009 available on SEDAR atwww.sedar.com and on the APUC website atwww.AlgonquinPowerandUtilities.com.

Changes in Accounting Policies

APUC’s accounting policies are described in Note 1 to the Consolidated Financial Statements for the period ended December 31, 2010. There have been no changes to the critical accounting policies as disclosed in APUC’s audited Consolidated Financial Statements for the year ended December 31, 2009 except as disclosed below.

Change in accounting estimates

As a result of the change in its corporate structure, APUC re-evaluated its exposure to currency exchange rate changes as determined by the underlying facts and circumstances of the economy in which the U.S. divisions operate. APUC concluded that the U.S. operations of the Renewable Energy and Thermal Energy divisions no longer should be classified as integrated foreign operations but rather self-sustaining operations. Consequently, these divisions are prospectively translated into Canadian dollars using the current rate method, effective January 1, 2010. The net exchange adjustment of $37.6 million resulting from the current rate translation of non-monetary items principally property, plant and equipment and intangible assets as of the date of the change is included as a separate component of other comprehensive income with a corresponding reduction to the carrying amount of the non-monetary items.

Accounting Framework

In 2011, most publicly accountable enterprises in Canada will be required to change the accounting framework under which financial statements are prepared to International Financial Reporting Standards (“IFRS”). The adoption of IFRS is one of the alternatives available to APUC. As an entity with rate-regulated activities, APUC could also avail itself of the one-year deferral approved by the Accounting Standard Board of the Canadian Institute of Chartered Accountants in September 2010. Alternatively, as an existing SEC registrant, APUC could also choose to report its financial statements under U.S. GAAP.

APUC evaluated the three options and assessed which of the three accounting frameworks would provide its shareholders and other interested readers of its financial statements the most useful basis for financial reporting. Considering the short-term nature of the CICA solution and the uncertainty around the eventual adoption of a rate-regulated accounting standard under IFRS, U.S. GAAP financial statements represent the least disruptive accounting framework for readers of APUC’s financial statements. This option would result in minimal changes having to be made to its financial statements as there are fewer differences between U.S. GAAP and current Canadian GAAP. U.S. GAAP also includes accounting standards for rate-regulated activities within the financial statements.

As such, APUC has decided to adopt U.S. GAAP effective January 1, 2011 for purposes of Canadian and U.S. reporting requirements. U.S. GAAP reporting is permitted by Canadian securities laws and the TSX for companies subject to reporting obligations under U.S. securities laws.

Changeover to U.S. Generally Accepted Accounting Standards –January 1, 2011

Reconciliation to U.S. GAAP

Canadian GAAP differs in certain material respects from U.S. GAAP. The reconciliation to U.S. GAAP in note 24 of the consolidated financial statements provides a reconciliation to U.S. GAAP of net earnings, balance sheet and deficit for the years ended December 31, 2010 and 2009.

Significant Changes in Accounting Policies upon Conversion

Commencing in the first quarter of 2011, U.S. GAAP will be applied retrospectively to all prior periods. We expect to make changes in our accounting policies to be compliant with U.S. GAAP. Our U.S. GAAP policies are expected to be consistent with the policies we applied in preparing the reconciliation reflected below. As such, the descriptions contained within the reconciliation are anticipated to be reflective of the changes we plan to make in our adoption of U.S. GAAP.

Impact on the organization

As an SEC registrant, APUC reconciles its financial statements from Canadian GAAP to U.S. GAAP for purpose of annual reporting on Form 40-F with the SEC as a foreign private issuer. As a consequence, no significant impact of the transition to U.S. GAAP is expected on APUC’s internal controls, information technology systems and financial reporting expertise requirements. No financial covenants are expected to be impacted by APUC’s conversion to U.S. GAAP given the few differences that exist with Canadian GAAP.

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Algonquin Power & Utilities (AQN) 40-F2010 FY Annual report (Canada)

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