EXHIBIT 99.1

Interim 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”) has prepared the following discussion and analysis to provide information to assist its shareholders’ understanding of the financial results for the three months ended March 31, 2011. This interim Management’s Discussion and Analysis (“MD&A”) should be read in conjunction with APUC’s unaudited consolidated financial statements for the three months ended March 31, 2011 and 2010. This material is available on SEDAR at www.sedar.com and on the APUC website at www.AlgonquinPowerandUtilities.com. Additional information about APUC, including the most recent Annual Information Form (“AIF”) can be found on SEDAR at www.sedar.com.

This MD&A is based on information available to management as of May 11, 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 U.S. 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.

Overview

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

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APCo generates and sells electrical energy through a diverse portfolio of renewable power generation and clean thermal power generation facilities across North America. As at March 31, 2011, 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 exchangeable 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 regulated utility services related to electricity, natural gas and, water distribution and wastewater collection 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 distribution 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 announced an agreement with Emera to acquire the interest in the California utility held by Emera, 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 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 at least 5% and continued growth in its dividend supported by increasing cash flows, earnings and additional investment prospects.

APUC understands the importance of the dividend to its shareholders. 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.

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 APUC. APUC strives to achieve its results in the context of a moderate risk profile consistent with top-quartile North American power and utility operations.

Independent Power: APCo develops, owns and operates a diversified portfolio of electrical energy generation facilities. This business is comprised of three 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

¹  During the fourth quarter of 2011, 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

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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 regulated utilities in the electricity and natural gas distribution and transmission sectors and water distribution and wastewater treatment sectors through its two wholly-owned subsidiaries, Liberty Energy and Liberty Water. These utilities share certain common infrastructure to generate economies of scale to support best-in-class customer care for their 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 these 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 utility business portfolio.

Major Highlights

Corporate Highlights

Strengthened Balance Sheet - Conversion of Series 1A Convertible Debentures to Equity

On April 7th, 2011, APUC provided the holders of its Series 1A 7.5% convertible unsecured subordinated debentures due November 30, 2014 (“Series 1A Debentures”) notice of its intention to redeem, effective May 16, 2011 (“Redemption Date”), all of the issued and outstanding Series 1A Debentures.

The redemption will be effected in accordance with the terms and definitions of the trust indenture governing the Series 1A Debentures. APUC will satisfy its obligation to pay holders of Series 1A Debentures (“Debentureholders”) by issuing and delivering the number of freely tradeable APUC shares obtained by dividing the aggregate principal amount of Series 1A Debentures as at March 31, 2011, currently $62,397,050, by 95% of the current market price of APUC shares on the Redemption Date. Unpaid accrued interest on the Series 1A Debentures will be paid in cash at the time of redemption.

Strategic Investment Agreement with Emera

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

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

As an element of the Strategic Agreement, Emera’s allowed common equity interest in APUC will be increased from 15% to 25%. APUC will seek shareholder approval at its upcoming annual and special general meeting currently scheduled for June 21, 2011.

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Liberty Utilities Highlights

California Utility Acquisition

On January 1, 2011, APUC completed the acquisition of 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 (“Liberty Energy (California)”).

Total consideration for the entire utility was U.S. $131.8 million, subject to final adjustments. The acquisition of the utility assets by Liberty Energy (California) was funded in part with the proceeds of a U.S. $70 million senior unsecured private debt placement to Liberty Energy (California) 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.

During the quarter ended March 31, 2011, the California Assets generated revenue of $22.9 million against operating costs of $17.0 million.

Acquisition of 100% Ownership Interest of the California Utility

Emera has agreed to sell its 49.999% direct ownership in Liberty Energy (California) to APUC, with closing of such transaction subject to regulatory approval. As consideration Emera will receive 8.211 million APUC shares in two tranches. Approximately half of the shares will be issued following regulatory approval of the Liberty Energy (California) ownership transfer and the balance of the shares will be issued following completion of Liberty Energy (California)’s first rate case, expected to be completed in the latter half of 2012.

Utility Acquisitions by Liberty Water

On April 19th, 2011, APUC announced that Liberty Water had entered into asset purchase agreements to acquire three additional regulated water utility assets in the United States. These acquisitions, Louisiana Land and Water Co. (“LLW”), Noel Water Company (“Noel”), and KMB Utilities Company (“KMB”), will add approximately 7,400 customer connections to the Liberty Water family. Total consideration for the three acquisitions is U.S. $8.3 million.

LLW, the largest of the three utilities serving approximately 6,000 customers near Monroe, LA, and KMB located in Missouri, both own and operate regulated water distribution and waste-water collection and treatment utility systems; Noel participates solely in the regulated water distribution utility business in Missouri.

Closings of the acquisitions are subject to certain conditions including state regulatory approval, and are expected to occur in the fall of 2011.

Algonquin Power Co. Highlights

Acquisition of First Wind’s Northeast Projects

On April 30, 2011, APUC and Emera announced that they have entered into an agreement to jointly construct, own and operate wind energy projects in the Northeast U.S.

First Wind has a 370 MW portfolio of wind energy projects in the Northeast U.S. including five operating projects and two projects near operation. These assets will become part of an operating company of which First Wind will own 51% and, Emera and APUC through their own separate joint venture (“Northeast Wind”), will own 49% of the operating company. Emera will initially own 75% of Northeast Wind and APUC will own the balance. Northeast Wind will invest a total of $333 million to acquire the

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49% ownership of the operating company. This includes a $150 million loan to the operating company. The loan will be repaid within 5 years, or convert to equity in future projects.

APUC and Emera will work with First Wind to grow the operating company and develop other projects in the region. The transaction provides Northeast Wind access to a pipeline of Northeast US based development projects and provides Algonquin an effective way to extend its development reach into a geographic area which has historically not been included in its area of focus. Algonquin is able to leverage its development activities through access to First Wind’s development team within New England. Algonquin’s involvement includes oversight control over the process which will result in additional projects being acquired by the joint venture. Once projects in the development pipeline meet certain eligibility criteria they will transfer to the operating company.

APUC will finance its investment in Northeast Wind, in part, through an agreement with Emera for Emera to acquire $37 million of subscription receipts in Algonquin at a price of $5.37 per share.

The transaction is expected to be immediately accretive to both Emera and Algonquin. The transaction requires certain state and federal regulatory approvals, among others, and is expected to close by the end of the year.

The First Wind projects being transferred to the operating company are:

Project	Location	Commercial Operation	Size
Mars Hill Wind,	Mars Hill, Maine	2007	42 MW
Stetson Wind I,	Danforth, Maine	2009	57 MW
Stetson Wind II,	Danforth, Maine	2010	26 MW
Rollins Wind	Lincoln, Maine	expected completion - July 2011	60 MW
Sheffield Wind	Sheffield, Vermont	expected completion - Oct. 2011	40 MW
Steel Winds I	Lackawanna, New York	2007	20 MW
Cohocton Wind	Cohocton, New York	2009	125 MW

Acquisition of Saskatchewan Wind Projects

On March 21, APCo announced that it has executed an asset purchase agreement to acquire the Morse Projects (two proposed adjacent 10 MW wind energy development projects in Saskatchewan). These projects were selected by SaskPower for award of power purchase agreements in accordance with the SaskPower Green Options Partners Program in May 2010. Upon SaskPower’s approval and execution of the PPAs, Kineticor will assign the PPAs to APCo. The projects are to be constructed near Morse, Saskatchewan, approximately 180 km west of Regina and are expected to be completed in late 2013.

2011 First quarter results from operations

Over the past two years, APUC has focused its efforts on a number of value creation initiatives that, through their completion, have now created the conditions for growth in APUC revenues, EBITDA and earnings. These value initiatives include Liberty Energy’s acquisition of a California electric distribution utility, prosecution of rate cases by Liberty Water, APCo’s refurbishment of the Energy from Waste facility, acquisition by APCo of the Tinker Hydro facility and APCo’s completion of construction and commissioning of the Red Lily I Wind Farm. As a result, for the three months ended March 31, 2011, APUC reported total revenue of $71.7 million as compared to $45.9 million during the same period in 2010, an increase of $25.8 million or 56.3%. Adjusted EBITDA in the three months ended March 31, 2011 totalled $26.9 million as compared to $17.9 million during the same period in 2010, an increase of $8.9 million or 50%.

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Key Selected First Quarter Financial Information

	Three months ended March 31
	2011		2010
Revenue	$	71,708	$	45,884
Adjusted EBITDA1	$	26,915	$	17,933
Cash provided by Operating Activities		19,284		8,385
Net earnings		5,016		3,531
Adjusted net earnings2		4,525		1,439
Dividends to Shareholders		6,762		5,597
Per share
Net earnings	$	0.05	$	0.04
Adjusted net earnings2	$	0.04	$	0.02
Diluted net earnings	$	0.05	$	0.04
Cash provided by Operating Activities	$	0.19	$	0.09
Dividends/distributions to Shareholders/Unitholders	$	0.065	$	0.06
Total Assets		1,175,822		966,169
Long Term Debt3		325,237		237,088

¹ 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.

² 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.

³ 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.

The major factors resulting in the increase in APUC revenue in the three months ended March 31, 2011 as compared to the corresponding period in 2010 are set out as follows:

	Three months ended March 31, 2011
Comparative Prior Period Revenue	$	45,884
Significant Changes:
California Utility Acquisition – January 1, 2011		22,900
Energy-from-Waste facility		3,400
Liberty Water revenue increases primarily due to rate case approvals		2,000
Effect of wind resource compared to comparable quarter		900
Red Lily I – development, construction and supervision fees		500
Sanger Facility – Effect of price and volume reductions vs the comparable quarter		(600	)
Tinker Hydro/Energy Services Business		(1,100	)
Impact of the weaker U.S. dollar		(1,500	)
Other		(676	)
Current Period Revenue	$	71,708

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

For the three months ended March 31, 2011, APUC experienced an average U.S. exchange rate of approximately $0.986 as compared to $1.041 in the same period in 2010. As such, any quarter over quarter 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 March 31, 2011 totalled $26.9 million as compared to $17.9 million during the same period in 2010, an increase of $8.9 million or 50%. The increase in Adjusted EBITDA is primarily due to increased earnings from operations primarily resulting from the acquisition of the California Assets, increased revenues from Liberty Water resulting from the completion of rate cases, and improved results from the EFW facility, partially offset by lower results at Windsor Locks, the Energy Services Business average hydrology in the Renewable Energy division and the impact of the weaker U.S. dollar as compared to the same period in 2010. 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).

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For the three months ended March 31, 2011, net earnings totalled $5.0 million as compared to $3.5 million during the same period in 2010, an increase of $1.5 million or 43%. Net earnings per share totalled $0.05 for the three months ended March 31, 2011, as compared to $0.04 during the same period in 2010, an increase of 25%.

Net earnings for the three months ended March 31, 2011 increased by $9.5 million due to increased earnings from operating facilities and $0.3 million related to increased interest, dividend and other income as compared to the same period in 2010. These items were partially offset by increased expenses of $0.8 million due to increased management and administration expense, $2.0 million due to increased interest expense, $0.8 million due to increased amortization expense, $1.6 million related to decreased recoveries of income tax expense primarily due to the reasons discussed in Annual Corporate and Other Expenses – Income Taxes, $1.8 million due to increased earnings attributable to non-controlling interest, primarily related to earnings from the California Asset, $0.8 million due to increased amortization expense, $0.5 million due to decreased gains on derivative financial instruments and $0.7 million due to increased acquisition costs as compared to the same period in 2010.

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 under Treasury Risk Management - Foreign currency risk.

During the three months ended March 31, 2011, cash provided by operating activities totalled $19.4 million or $0.19 per share as compared to cash provided by operating activities of $8.4 million, or $0.09 per share during the same period in 2010, an increase of more than 100%. Cash provided by operating activities exceeded dividends declared by 2.9 times during the quarter ended March 31, 2011 as compared to 1.5 times dividends during the same period in 2010. The change in cash provided by operating activities after changes in working capital in the three months ended March 31, 2011, 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 2010.

Outlook

APCo

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

The capital upgrade completed at the EFW facility is expected to continue to result in higher throughput and lower operating costs at the facility in the second quarter of 2011 as compared to the same period in 2010 when the facility was temporarily shut down. APCo anticipates that the Sanger facility should meet expectations for the second quarter of 2011 and be in line with 2010 results.

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 the Independent System Operator New England (“ISO-NE”) day-ahead market or to retail customers through the Energy Services Business. It is anticipated that performance during the second quarter of 2011 will be in line with expectations.

Liberty Utilities

Liberty Water is forecasting modest customer growth in 2011. Revenue increases from rate cases completed in Arizona and Texas are anticipated to contribute additional revenue in Liberty Water in the second quarter of 2011 as compared to the same period in 2010. Liberty Water attributes approximately U.S. $1.7 million of the revenue increases in the first quarter of 2011 to the impact of completed rate cases and anticipates that this will continue in the second quarter. In addition, the Rio Rico and Bella Vista rate cases were completed in the quarter and are expected to contribute an additional U.S. $1.7 million in revenue on an annualized basis.

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Liberty Energy expects modest customer growth in 2011. Liberty Energy anticipates that the Liberty Energy (California) facility should exceed expectations for the second quarter of 2011 through increased load and customer count.

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

APCo: Renewable Energy

	Three months ended March 31
	Long Term Average Resource		2011			2010
Performance (MW-hrs sold)
Quebec Region		57,725		60,925			64,650
Ontario Region		37,250		33,100			29,925
Manitoba Region		105,000		92,800			79,175
Saskatchewan Region*		17,500		7,300			—
New England Region		18,625		16,450			18,800
New York Region		27,300		22,650			23,925
Western Region		10,200		9,875			9,400
Maritime Region		25,575		32,850			31,400
Total		299,175		275,950			257,275
Revenue
Energy sales			$	21,879		$	22,219
Less:
Cost of Sales – Energy**				(1,772	)		(2,089	)
Net Energy Sales			$	20,107		$	20,130
Other Revenue				501			—
Total Net Revenue			$	20,608		$	20,130
Expenses
Operating expenses				(5,814	)		(6,036	)
Interest and Other income				420			138
Division operating profit (including other income)			$	15,214		$	14,232

* Actual production in the Saskatchewan Region reflects production since Red Lily I achieved commercial operation, approximately one month. The long term average resource reflects three months of production.

** Cost of Sales – Energy consists of energy purchases by the Energy Services Business which is resold to its retail and industrial customers.

APCo’s hydroelectric generating facilities in the New York and New England regions primarily sell their output at market rates, therefore 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 APCo’s Energy Services Business which, in turn, sells this energy under fixed price contracts to local electric utilities and commercial and industrial customers in Northern Maine. APCo’s facilities in the other regions sell their energy under varying rates as established by each facility’s specific PPA. 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.

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2011 First Quarter Operating Results

For the quarter ended March 31, 2011, the Renewable Energy division produced 275,950 MW-hrs of electricity, as compared to 257,275 MW-hrs produced in the same period in 2010, an increase of 7.3%. The increased generation is primarily due to improved average hydrology in the quarter as compared to the comparable period in 2010. This level of production in 2011 represents sufficient renewable energy to supply the equivalent of 60,000 homes on an annualized basis with renewable power. Using new standards of thermal generation, as a result of renewable energy production, the equivalent of 148,000 tons of CO2 gas was prevented from entering the atmosphere in the first quarter of 2011.

During the quarter ended March 31, 2011, the division generated electricity equal to 95% of long-term projected average resources (wind and hydrology) as compared to 90% during the same period in 2010. In the first quarter of 2011, the Maritimes and Quebec regions experienced resources significantly higher than long-term averages, producing approximately 30% and 6% above long-term average resources, respectively. The Western region experienced resources approximately 5% below long-term average, while the Ontario, Manitoba and New England regions experienced resources of approximately 10% below long-term averages. The New York regions experienced results approximately 15% below long-term average resources.

For the quarter ended March 31, 2011, revenue from energy sales in the Renewable Energy division totalled $21.9 million, as compared to $22.2 million during the same period in 2010, a decrease of $0.3 million or 1.5%. 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 March 31, 2011, net revenue from energy sales in the Renewable Energy division totalled $20.1 million, consistent with the same period in 2010.

Revenue from APCo’s New England and New York region facilities decreased $0.2 million due to a decrease in weighted average energy rates (approximately 4.5%) and decreased average hydrology, as well as $1.3 million decrease in revenue at the Energy Services Business primarily due to decreased customer demand as compared to the same period in 2010. Revenue at the Energy Services Business primarily consists of wholesale deliveries to local electric utilities and retails sales to commercial and industrial customers in Northern Maine ($3.2 million) and merchant sales of production in excess of customer demand and other revenue ($0.3 million). Revenue from the Manitoba region increased $0.9 million primarily due to a stronger wind resource and $0.3 million in the Maritime region primarily due to increased customer demand as compared to the same period in 2010. 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 in the Quebec region as compared to the same period in 2010. The division reported decreased revenue of $0.4 million from U.S. operations as a result of the weaker U.S. dollar as compared to the same period in 2010.

Red Lily achieved commercial operations effective February 23, 2011. From commercial operation date to March 31, 2011 Red Lily produced 7,300 MW-hrs of electricity which was sold to SaskPower. APCo’s economic return from its investment in Red Lily currently comes in the form of interest payments, fees and other charges. Under the terms of the agreements, APCo has the right to exchange these contractual and debt interests in Red Lily for a direct 75% equity interest in 2016. On the expectation that APCo will exercise such option, APCo proportionally includes the performance of Red Lily in its generation report. For the three months ended March 31, 2011, APCo earned fees and interest payments from Red Lily in the total amount of $0.8 million.

For the quarter ended March 31, 2011, energy purchase costs by the Energy Services Business totalled U.S. $1.8 million. During the quarter, the Energy Services Business purchased approximately 21,500 MW-hrs of energy at market and fixed rates averaging $75 per MW-hr. The Maritime region generated approximately 60% of the load required to service its customers as well as the Energy Services Business’ customers in the three months ended March 31, 2011.

For the quarter ended March 31, 2011, operating expenses excluding energy purchases totalled $5.8 million, as compared to $6.0 million during the same period in 2010, a decrease of $0.2 million or 3.7%. Operating expenses were impacted by $0.3 million related to increased operating costs associated with the Tinker Assets and the Energy Services Business, partially offset by decreased repair and maintenance expenses of $0.2 million at U.S. facilities as compared to the same period in 2010. Operating expenses include costs incurred in the period of $0.3 million associated with the pursuit of various growth and development activities, consistent with the same period in 2010. The division reported decreased expenses of $0.1 million from U.S. operations as a result of the weaker U.S. dollar as compared to the same period in 2010.

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For the quarter ended March 31, 2011, interest, dividend and other income totalled $0.4 million, as compared to $0.1 million during the same period in 2010. Interest, dividend and other income primarily consists of interest related to the senior and subordinated senior debt interest in the Red Lily I project. This amount is included as part of APCo’s earnings from its investment in Red Lily, as discussed above.

For the quarter ended March 31, 2011, Renewable Energy’s operating profit totalled $15.2 million, as compared to $14.2 million during the same period of 2010, representing an increase of $1.0 million or 6.9%. For the quarter ended March 31, 2011, Renewable Energy’s operating profit did not meet APCo’s expectations primarily due to a lower wind resource than expected in the Manitoba region.

Divisional Outlook – Renewable Energy

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

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 second quarter of 2011. The Energy Services Business anticipates that the Tinker Assets will provide the majority of the energy required to service its customers in the second quarter of 2011 and that it will need to purchase approximately 2,500 MW-hrs of energy from the ISO-NE or similar market. The Energy Services Business has in place fixed price financial energy contracts to operationally hedge the price of the customer supply obligations which are not expected to be supplied by the Tinker Assets and to minimize the volatility of the energy prices. These contracts in combination with the expected Tinker production are used to balance the monthly customer load.

APCo: Thermal Energy Division

	Three months ended March 31
	2011			2010
Performance (MW-hrs sold)		131,500			139,200
Performance (tonnes of waste processed)		41,375			6,550
Performance (steam sales – million lbs)		340,000			320,700
Revenue
Energy sales	$	12,483		$	14,299
Less:
Cost of Sales – Fuel *		(6,353	)		(6,245	)
Net Energy Sales Revenue	$	6,130		$	8,054
Waste disposal sales		4,020			917
Other revenue		191			203
Total net revenue	$	10,341		$	9,174
Expenses
Operating expenses *		(6,076	)		(6,261	)
Interest and other income		88			139
Division operating profit	$	4,353		$	3,052

* 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 at prices based on 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. Total natural gas expense will vary based on the volume of natural gas consumed and the average landed cost of natural gas for each mmbtu. As a result, a facility may record a higher aggregate expense for natural gas as a result of a lower average landed per unit cost for natural gas combined with a consumption of a higher volume of such gas.

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2011 First Quarter Operating Results

During the quarter ended March 31, 2011, the business unit produced 131,500 MW-hrs of energy as compared to 139,200 MW-hrs of energy in the comparable period of 2010. During the quarter ended March 31, 2011, the business unit’s total production decreased by 4,300 MW-hrs from the Windsor Locks facility, 2,500 MW-hrs from the now discontinued landfill gas facilities, and 1,200 MW-hrs from the Sanger facility partially offset by an increase of 1,600 MW-hrs from the EFW facility, each as compared to the same period in 2010.

The EFW facility processed 41,375 tonnes of municipal solid waste as compared to 6,550 tonnes processed in the same period of 2010. The significant increase in throughput is the result of the unplanned outage experienced from January to July 2010. The current level of production resulted in the diversion of approximately 30,000 tonnes of waste from municipal solid waste landfill sites in the first quarter of 2011.

During the quarter ended March 31, 2011, the BCI and Windsor Locks facilities sold 340,000 million lbs of steam as compared to 320,700 million lbs of steam in the comparable period of 2010. During the quarter ended March 31, 2011, BCI purchased 125,000 million lbs of steam from the EFW facility as compared to 18,000 million lbs of steam in the same period in 2010.

For the quarter ended March 31, 2011, revenue in the Thermal Energy division totalled $16.7 million, as compared to $15.4 million during the same period in 2010, an increase of $1.3 million, or 8.3%. 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 March 31, 2011, net energy sales revenue at the Thermal Energy division totalled $6.1 million, as compared to $8.1 million during the same period in 2010, a decrease of $2.0 million, primarily arising from the termination of the previous power purchase agreements in effect until April 2010 at the Windsor Locks facility.

For the quarter ended March 31, 2011, energy sales revenue in the Thermal Energy division totalled $12.5 million, as compared to $14.3 million during the same period in 2010, a decrease of $1.8 million or 12.7%. The decrease in revenue from energy sales was primarily due to a decrease of $0.4 million at the Windsor Locks facility as a result of decreased production, partially offset by an increase of $0.1 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, a decrease of $0.6 million at the Sanger facility as a result of decreased energy pricing and decreased production and a decrease of $0.2 million as a result of the closure of the LFG facilities, as compared to the same period in 2010. The decrease in revenue was partially offset by $0.2 million at the BCI facility as a result of increased price for steam and an increase of $0.1 million at the EFW facility as a result of increased production of energy, 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 $0.9 million from operations as a result of the weaker U.S. dollar, as compared to the same period in 2010.

Revenue from waste disposal sales for the quarter ended March 31, 2011 totalled $4.0 million, as compared to $0.9 million during the same period in 2009. The increase was a result of the EFW facility shutdown in the comparable period of 2010.

Other revenue for the quarter ended March 31, 2011 totalled $0.2 million, consistent with the same period in 2010.

For the quarter ended March 31, 2011, fuel costs at Sanger and Windsor Locks totalled U.S $6.4 million, as compared with U.S $6.0 million in the same period in 2010, an increase of U.S. $0.4 million. The overall natural gas expense at the Windsor Locks facility increased $0.8 million (18%), primarily the result of a 23% increase in the average landed cost of natural gas per mmbtu, partially offset by a 4% reduction in volume of natural gas consumed, as compared to the same period in 2010. The average landed cost of natural gas at the Windsor Locks facility during the quarter was $5.36 per mmbtu. This was partially offset by a decrease in the natural gas expense at Sanger of $0.4 million (27%), primarily the result of a 25% decrease in the average landed cost of natural gas per mmbtu, as well as a 2% decrease in the volume of natural gas consumed as compared to the same period in 2010. The average landed cost of natural gas at the Sanger facility during the quarter was U.S. $4.34 per mmbtu.

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For the quarter ended March 31, 2011, operating expenses, excluding fuel costs at Windsor Locks and Sanger, totalled $6.1 million, as compared to $6.3 million during the same period in 2010, a decrease of $0.2 million. The decrease in operating expenses for the quarter was primarily due to $0.7 million of reduced natural gas costs at BCI as a result of the EFW facility generating more steam, $0.3 million related to decreased costs at three facilities and $0.4 million of reduced operating costs at the LFG facilities partially offset by $1.8 million in increased operating costs at the EFW facility resulting from the outage at the facility in 2010 as compared to the same period in 2010. Operating expenses in the comparable period included costs of $0.2 million associated with the pursuit of various growth and development activities. The division reported decreased expenses of $0.4 million from U.S. operations as a result of the weaker U.S. dollar as compared to the same period in 2010.

For the quarter ended March 31, 2011, the Thermal Energy division’s operating profit totalled $4.4 million, as compared to $3.1 million during the same period in 2010, representing an increase of $1.3 million or 42.6%. Operating profit in the Thermal Energy division exceeded expectations for the quarter ended March 31, 2011, primarily due to better than expected earnings at the Windsor Locks facility as a result of improved energy pricing.

Divisional Outlook – Thermal Energy

The capital upgrade completed at the EFW facility is expected to continue to result in higher throughput and lower operating costs at the facility in the second quarter of 2011 as compared to the same period in 2010 when the facility was temporarily shut down. APCo estimates that the upgrade resulted in higher earnings from operations of approximately $1.4 million in the first quarter of 2011 as compared to the same period in 2010 and anticipates that trend should continue in the second quarter of 2011.

APCo anticipates that the Sanger facility should meet expectations for the second quarter of 2011 and be in line with 2010 results.

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 industrial customers through the Energy Services Business. The facility did not commit any portion of its remaining capacity to the FRM for the summer of 2011 due to low auction prices. It is anticipated that performance during the second quarter of 2011 will be in line with expectations.

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. See APCo Development Division – Windsor Locks for further discussion on the potential repowering project.

APCo: Development Division

Current Development Projects

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

Project Name (Location)	Size (MW)		Estimated Capital Cost		Expected Year of Commissioning		Ownership Interest			PPA Term		Production MW-hrs
Amherst Island (Ontario)1		75	$	230m		2014		100	%		25		247,000
St. Damase (Quebec)2		24	$	70m		2013		50	%		20		86,000
Val Eo (Quebec)3		24	$	70m		2015		25	%		20		66,000
Morse (Saskatchewan)4, 5		20	$	60m		2013		100	%		20		75,000
Total		143	$	430m									474,000

Notes:

1 FIT contract awarded

2 Successful submission to Hydro Quebec’s 2009 RFP for wind.

3 PPA signed

4 Two 10 MW PPAs

5 Comprised of two projects that are connected geographically and will be built simultaneously. Both projects were awarded PPAs under the province’s Green Options Partner Program (GOPP).

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Amherst Island

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

The project is currently contemplated to use more efficient Class III wind turbine generator technology and will be developed by APCo. APCo forecasts that the available wind resource could produce approximately 247 GW hrs of power annually, depending upon the final turbine selection for the project. Funding for the total capital costs currently estimated to be $230 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 to 18 months.

Quebec Community Wind Projects

In 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 power purchase contracts that stipulate the use of ENERCON turbines.

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 APCo. The first 24 MW phase of the project is expected to be comprised of twelve 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.

The interest of APUC in the project is subject to final negotiations with the municipality but, in any event, will not be less than 50%. Final funding of the project will be arranged and announced when all required permitting has been met, and all other pre-construction conditions have been satisfied. Preliminary permitting began in early 2011, with all major authorizations targeted for completion by the end of 2012.

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 APCo. The first 24 MW phase of the project is expected to be comprised of eight 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 interest of APUC in the project is subject to final negotiations with the municipality but, in any event, will not be less 25%. Final funding of the project will be arranged and announced when all required permitting has been met, and all other pre-construction conditions have been satisfied. Preliminary permitting began in early 2011, with all major authorizations targeted for completion by the end of 2012.

Morse Wind Projects

APCo has executed an asset purchase agreement with Kineticor to acquire the Morse Projects, assets related to two proposed adjacent 10 MW wind energy development projects in Saskatchewan.

The Morse Projects were selected by SaskPower for award of PPAs in accordance with the SaskPower Green Options Partners Program in May 2010. Upon SaskPower’s approval and execution of the PPAs, Kineticor will assign the PPAs to APCo. The Morse Projects are expected to be completed in late 2013.

The Morse Projects are to be constructed near Morse, Saskatchewan, approximately 180 km west of Regina. It is contemplated that the Morse Projects will have additional land under lease or option in order to facilitate future expansion of the Morse Projects.

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The total annual energy production for the Morse Projects is estimated to be 75,000 MW-hrs. The capital cost to construct the Morse Projects is currently estimated to be $55-$60 million, inclusive of acquisition costs. The first year PPA rate is set at $101.98 per
MW-hr for the first full year of operations, which APCo expects to occur in 2014, with an annual escalation provision of 2% over the expected 20 year term.

Red Lily II Wind Proejct

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.

Windsor Locks Repower

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 pursuant to the ESA.

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 the Windsor Locks Facility 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 ITC sponsored by the U.S. Federal Government. The benefit of the ITC grant is approximately U.S. $1 million in addition to the Connecticut DPUC grant. 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.

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.

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 Green Energy Act (“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 has applications for approximately 42 MW of on-shore wind energy projects in eastern Ontario under the GEA’s FIT program which are now being reviewed under the Economic Connection Test. The on-shore wind price set by the FIT program is $0.135 per KWh.

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.

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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

St. Leon II

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.

LIBERTY WATER

	Three months ended March 31						Three months ended March 31
	2011			2010			2011			2010
Number of
Wastewater connections								36,095			35,380
Wastewater treated (millions of gallons)								550			525
Water distribution connections								37,890			37,026
Water sold (millions of gallons)								1,000			900
Assets for regulatory purposes (U.S. $)	U.S. $	158,588		U.S. $	152,658		Can $			Can $
Revenue
Wastewater treatment	$	5,781		$	4,693		$	5,699		$	4,917
Water distribution		3,975			3,075			3,918			3,221
Other Revenue		165			105			167			108
	$	9,921		$	7,873		$	9,784		$	8,246
Expenses
Operating expenses		(5,502	)		(5,204	)		(5,421	)		(5,428	)
Other income		111			11			109			11
Business Unit operating profit	$	4,530		$	2,680		$	4,472		$	2,829

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 36,095 wastewater connections as at March 31, 2011, as compared to 35,380 as at March 31, 2010, an

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increase of 715 connections in the period or 2.0%. Liberty Water had 37,890 water distribution connections as at March 31, 2011, as compared to 37,026 as at March 31, 2010, representing an increase of 864 in the period or 2.3%. Total connections include approximately 1,800 vacant wastewater connections and 1,500 vacant water distributions connections as at March 31, 2011. Liberty Water’s change in water distribution and wastewater treatment customer base during the period is primarily due to modest customer growth at Liberty Water’s facilities.

Liberty Water has investments in regulatory assets of U.S. $158.6 million across four states as at March 31, 2011, as compared to U.S. $152.7 million as at March 31, 2010.

2011 First Quarter Operating Results

During the quarter ended March 31, 2011, Liberty Water provided approximately 1.0 billion U.S. gallons of water to its customers, treated approximately 550 million U.S. gallons of wastewater and sold approximately 35 million U.S. gallons of treated effluent.

For the quarter ended March 31, 2011, Liberty Water’s revenue totalled U.S. $9.9 million as compared to U.S. $7.9 million during the same period in 2010, an increase of U.S. $2.0 million or 26.0%. The increased revenues were primarily due to the implementation of rate increases from rate cases filed with state legislators over the past two years. The rate cases were required 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.

Revenue from wastewater treatment totalled U.S. $5.8 million, as compared to U.S. $4.7 million during the same period in 2010, an increase of U.S. $1.1 million or 23.2%. The first quarter wastewater treatment revenue was impacted by increased revenue, primarily from the implementation of rate increases, of U.S. $0.7 million at the LPSCo facility and U.S. $0.2 million at the Black Mountain facility, U.S. $0.1 million related to the acquisition of Galveston as compared to the same period in 2010. In addition, revenue increased U.S. $0.2 million at eight wastewater treatment facilities primarily due to increased customer demand as compared to the same period in 2010.

Revenue from water distribution totalled U.S. $4.0 million, as compared to U.S. $3.1 million during the same period in 2010, an increase of U.S. $0.9 million or 29.3%. The first quarter water distribution revenue was impacted by U.S. $0.7 million at the LPSCo facility primarily due to the implementation of rate increases, U.S. $0.2 million at the Rio Rico facility and U.S. $0.1 million related to the acquisition of Galveston as compared to the same period in 2010.

For the quarter ended March 31, 2011, operating expenses totalled U.S. $5.5 million, as compared to U.S. $5.2 million during the same period in 2010. Overall expenses increased U.S. $0.3 million or 5.7% as compared to the same period in 2010. Operating expenses increased due to increased utilities, consumable and insurance expenses of U.S. $0.2 million and U.S. $0.1 million related to wages, salary and other operating costs as compared to the same period in 2010.

For the quarter ended March 31, 2011, Liberty Water’s operating profit totalled U.S. $4.5 million as compared to U.S. $2.7 million in the same period in 2010, an increase of U.S. $1.9 million or 69.0%. Liberty Water’s operating profit met expectations for the three months ended March 31, 2011.

Measured in Canadian dollars, for the quarter ended March 31, 2011, Liberty Water’s revenue totalled $9.8 million, as compared to $8.2 million during the same period in 2010. Revenue from wastewater treatment totalled $5.7 million, as compared to $4.9 million during the same period in 2010, an increase of $0.8 million. Revenue from water distribution totalled $3.9 million, as compared to $3.2 million in the same period in 2010, an increase of $0.7 million. Liberty Water reported decreased revenue from operations of $0.5 million in the first quarter of 2011 as a result of the weaker U.S. dollar as compared to the same period in 2010.

Measured in Canadian dollars, for the quarter ended March 31, 2011, operating expenses totalled $5.4 million, consistent with same period in 2010. Liberty Water reported lower expenses from operations of $0.3 million as a result of the weaker U.S. dollar, as compared to the same period in 2010.

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For the quarter ended March 31, 2011, Liberty Water’s operating profit totalled $4.5 million as compared to $2.8 million in the same period in 2010, an increase of $1.6 million. Liberty Water’s operating profit met expectations for the three months ended March 31, 2011.

Outlook – Liberty Water

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. Liberty Water expects continuing modest customer growth in 2011.

Revenue increases from rate cases completed in Arizona and Texas are anticipated to contribute additional revenue in Liberty Water in the second quarter of 2011 as compared to the same period in 2010. Liberty Water attributes approximately U.S. $1.7 million of the revenue increases in the first quarter of 2011 to the impact of completed rate cases and anticipates that this will continue in the second quarter. In addition, the Rio Rico and Bella Vista rate cases were completed the quarter and are expected to contribute an additional U.S. $1.7 million in revenue on an annualized basis.

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
Bella Vista, Northern and Southern Sunrise		April 2011	$	1.1. million	$	0.8 million

On March 29, 2011, Liberty Water received a recommended order (“ROO”) for the consolidated Bella Vista, Northern Sunrise, and Southern Sunrise utilities authorizing an annual rate increase of $0.8 million, effective April 1, 2011, representing approximately 70% of the requested revenue increase.

At an ACC open meeting held on December 10, 2010 to consider the LPCSo ROO, it was determined that 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. On May 2, 2011, at a procedural conference it was determined that the phase 2 hearing would commence on June 27, 2011.

On April 19th, 2011 Liberty Water announced that it had entered into agreements to acquire three additional regulated water utility assets in the United States. These acquisitions, LLW, Noel, and KMB are expected to add approximately 7,400 customer connections, an increase of approximately 10%. Total consideration for the three acquisitions is U.S. $8.3 million.

LLW, the largest of the three utilities serving approximately 6,000 customers near Monroe, LA, and KMB located in Missouri, both own and operate regulated water distribution and waste-water collection and treatment utility systems. Noel participates solely in the regulated water distribution utility business in Missouri.

LLW, Noel, and KMB are anticipated to have net regulatory assets for rate making purposes at closing of approximately US$6.5 million, US$0.7 million, and US$0.3 million respectively, representing a consolidated purchase price multiple of net regulatory assets of approximately 1.09x. With the consent of the Louisiana regulator, LLW will file a rate case promptly after closing of the acquisition with recent rate cases in Louisiana providing return on equity of approximately 9.5-11%. At the Missouri facilities, recent rate cases have provided return on equity of 9.5% and 11.3% for Noel and KMB respectively.

The acquisitions are expected to close later in 2011.

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LIBERTY ENERGY

	Three months ended March 31					Three months ended March 31
	2011			2010		2011			2010
Number of Customer Accounts
Residential							41,260			—
Commercial – Small							5,440			—
Commercial – Large							60			—
Total Customer Accounts							46,760
Customer Usage (MW-hrs)
Residential							90,500			—
Commercial – Small							46,100			—
Commercial – Large							38,800			—
Total Customer Usage (MW-hrs)							175,400
Assets for regulatory purposes (U.S. $)	U.S. $	133,594		U.S. $	—	Can $			Can $
Revenue
Utility energy sales and distribution	$	23,179		$	—	$	22,850		$	—
Less:
Cost of Sales – Fuel *		(13,432	)		—		(13,242	)
	$	9,747		$	—	$	9,608		$	—
Expenses
Operating expenses		(3,799	)		—		(3,740	)		—
Other income		—			—		—			—
Business Unit operating profit**	$	5,948		$	—	$	5,868		$	—

* Cost of Sales – Energy consists of energy purchases from NV Energy.

** Represents 100% of investment in California Assets.

Liberty Energy’s business strategy is to build its nationwide 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 and building constructive positive regulatory relationships.

Liberty Energy’s initial asset as at March 31, 2011 is a 50.001% controlling interest in Liberty Energy (California). On April 29, 2011, it was announced that Emera has agreed to sell its 49.999% ownership interest to Liberty Energy, with closing of such transaction subject to regulatory approval. As a result, upon completion of the transaction, Liberty Energy will own 100% of Liberty Energy (California). Liberty Energy believes that consolidating 100% of the California utility under the Liberty Energy brand will provide the flexibility and control necessary to fully implement its approach to meeting the needs of customers, employees and regulators.

Liberty Energy has presented the division’s results in both the reporting currency and its functional currency. Liberty Energy believes that since the division’s operations are entirely in the U.S., it is useful to show the results in Liberty Energy’s functional currency without the impact of foreign exchange.

Liberty Energy reports active connections, exclusive of vacant connections rather than total connections. Liberty Energy had approximately 41,260 residential customer accounts and 5,500 commercial customer accounts, as at March 31, 2011 as compared to nil during the same period in 2010.

During the quarter ended March 31, 2011, Liberty Energy’s customer usage totalled approximately 175,400 MW-hrs of energy as compared to nil in the comparable period of 2010.

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2011 First Quarter Operating Results

For the quarter ended March 31, 2011, Liberty Energy’s revenue from utility energy sales totalled U.S. $23.2 million as compared to nil during the same period in 2010. The purchase of energy by Liberty Energy (California) is a significant revenue driver and component of operating expenses but these costs are effectively passed through to its customers. As a result, the division compares ‘net energy sales revenue’ (energy sales revenue less energy purchases) as a more appropriate measure of the division’s results. For the quarter ended March 31, 2011, net utility energy sales revenue for Liberty Energy totalled U.S. $9.7 million, as compared to nil during the same period in 2010.

For the quarter ended March 31, 2011, energy purchases for Liberty Energy totalled U.S $13.4 million, as compared with nil in the same period in 2010. During the quarter, Liberty Energy (California) purchased approximately 175,500 MW-hrs of energy at rates averaging U.S. $76.5 per MW-hr.

For the quarter ended March 31, 2011, operating expenses, excluding energy purchases, totalled U.S. $3.8 million, as compared to nil during the same period in 2010.

For the quarter ended March 31, 2011, Liberty Energy’s operating profit totalled U.S. $5.9 million as compared to nil in the same period in 2010. Liberty Energy’s operating profit exceeded expectations for the three months ended March 31, 2011.

Measured in Canadian dollars, for the quarter ended March 31, 2011, Liberty Energy’s revenue from energy sales totalled $22.9 million, as compared to nil during the same period in 2010. As the purchase of energy by Liberty Energy (California) is a significant revenue driver and component of operating expenses, the division compares ‘net energy sales revenue’ (energy sales revenue less energy purchases) as a more appropriate measure of the division’s results. For the quarter ended March 31, 2011, net energy sales revenue for Liberty Energy totalled $9.6 million, as compared to nil during the same period in 2010.

Measured in Canadian dollars, for the quarter ended March 31, 2011, energy purchases for Liberty Energy totalled $13.2 million, as compared with nil in the same period in 2010.

Measured in Canadian dollars, for the quarter ended March 31, 2011, operating expenses excluding energy purchases totalled $3.7 million, as compared to nil in the same period in 2010.

For the quarter ended March 31, 2011, Liberty Energy’s operating profit totalled $5.9 million as compared to nil in the same period in 2010. Liberty Energy’s operating profit exceeded expectations for the three months ended March 31, 2011 due to higher customer count and customer energy usage.

Outlook – Liberty Energy

Liberty Energy expects modest customer growth in 2011. Liberty Energy anticipates that Liberty Energy (California) should exceed expectations for the second quarter of 2011.

During the regulatory transfer approval process, Liberty Energy (California) committed to maintaining the historic three year rate case cycle implemented by NV Energy. Accordingly, a general rate case (“GRC”) will be filed with the regulator, California Public Utility Commission (“CPUC”) in August 2011 with new rates not expected to take effect until mid 2012. Liberty Energy continues to work with key stakeholders, including the CPUC, to help manage issues related to the issuance of a decision in its GRC in a timely manner.

On December 9, 2010, Liberty Energy’s wholly owned subsidiary Liberty Energy (New Hampshire) Inc entered into agreements to acquire all issued and outstanding shares of Granite State Electric Company (“Granite State”), a regulated New Hampshire electric utility, and EnergyNorth Natural Gas Inc. (“EnergyNorth”), a regulated New Hampshire natural gas utility for a total purchase price of U.S. $285 million. Granite State and EnergyNorth are anticipated to have regulatory assets at closing of approximately U.S. $72.0 million and U.S. $178.8 million, respectively.

Closings of the transactions are subject to certain conditions including state and federal regulatory approval, and are expected to occur in the fall of 2011. Liberty Energy (New Hampshire) is actively pursuing such approvals

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with the New Hampshire Public Utilities Commission (NHPUC). Following the preliminary hearing held the NHPUC on April 20, 2011, the parties reached agreement on a procedural schedule establishing final hearings (if necessary) for January 2012, Financing of the acquisitions is expected to occur simultaneously with the closing of the transactions. Liberty Energy is targeting a capital structure of not more than 50% debt to total capitalization consistent with investment grade utilities.

APUC: Corporate

	Three months ended March 31
	2011			2010
Corporate and other expenses:
Administrative expenses	$	3,722		$	2,915
Loss / (Gain) on foreign exchange		35			(39	)
Interest expense		8,018			6,067
Interest, dividend and other Income		(730	)		(735	)
Gain on derivative financial instruments		(429	)		(913	)
Income tax recovery		(554	)		(2,151	)

2011 First Quarter Corporate and Other Expenses

During the quarter ended March 31, 2011, management and administrative expenses totalled $3.7 million, as compared to $2.9 million in the same period in 2010. The expense increase in the three months ended March 31, 2011 primarily results from increased salaries and bonuses related to the management and administering APUC’s operations as compared to the same period in 2010.

For the quarter ended March 31, 2011, interest expense totalled $8.0 million as compared to $6.1 million in the same period in 2010. Interest expense increased primarily as a result of higher levels of borrowings at Liberty Water and Liberty Energy as compared to the same period in 2010.

For the quarter ended March 31, 2011, interest, dividend and other income totalled $0.7 million, consistent with the same period in 2010. Interest, dividend and other income primarily consists of dividends from APUC’s share investment in the Kirkland and Cochrane facilities.

Gain 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 $0.5 million was recorded in the three months ended March 31, 2011, as compared to a recovery of $2.2 million during the same period in 2010. The primary reason for the recovery reduction relate to the utilization of carry forward losses by certain U.S and Canadian entities. The income tax recovery for the three months ended March 31, 2011 primarily results from the reversal of deferred tax liability set up in prior years on temporary differences such as fixed assets. It also includes $1.0 million related to the recognition of deferred credits from the utilization of deferred 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.

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The following table is derived from and should be read in conjunction with the unaudited Interim 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 March 31
	2011			2010
Net earnings	$	6,920		$	3,596
Add:
Income tax recovery		(554	)		(2,151	)
Interest expense		8,018			6,067
Acquisition costs		753			44
Gain on derivative financial instruments		(429	)		(913	)
Loss (gain) on foreign exchange		35			(39	)
Amortization		12,172			11,329
Adjusted EBITDA	$	26,915		$	17,933

For the quarter ended March 31, 2011, Adjusted EBITDA totalled $26.9 million as compared to $17.9 million, a net increase of $9.0 million or 50.0% as compared to the same period in 2010.

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 March  31 2011
Comparative Prior Period Adjusted EBITDA	$	17,933
Significant Changes:
Acquisition of the California Utility		5,900
EFW facility		2,400
Liberty Water revenue increases primarily due to rate case approvals		1,800
Red Lily – development and other fees		800
St. Leon – primarily due to an increased wind resource		1,000
Hydro Renewable		300
Administration and management costs		(800	)
Lower results from the weaker U.S. dollar		(500	)
Tinker Hydro / Energy Services Business primarily due to lower energy demand		(1,000	)
Windsor Locks – change in operating model		(1,200	)
Other		282
Current Period Adjusted EBITDA	$	26,915

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

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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 March 31
	2011			2010
Net earnings	$	5,016		$	3,531
Add:
Gain on derivative financial instruments, net of tax		(985	)		(2,080	)
Acquisition costs, net of tax		459			27
Loss (gain) on foreign exchange, net of tax		35			(39	)
Adjusted net earnings	$	4,525		$	1,439
Adjusted net earnings per share unit	$	0.04		$	0.02

For the three months ended March 31, 2011, adjusted net earnings totalled $4.5 million as compared to adjusted net earnings of $1.4 million, an increase of $3.1 million as compared to the same period in 2010. The increase in adjusted net earnings in the three months ended March 31, 2011 is primarily due to increased earnings from operations, partially offset by increased interest expense as compared to the same period in 2010.

SUMMARY OF PROPERTY, PLANT AND EQUIPMENT EXPENDITURES

	Three months ended March 31
	2011			2010
APCo
Renewable Energy Division
Capital expenditures	$	959		$	264
Acquisition of operating entities		—			40,281
Total	$	959		$	40,545
Thermal Energy Division
Capital expenditures, net	$	(192	)	$	3,835
Total	$	(192	)	$	3,835
LIBERTY WATER
Capital Investment in regulatory assets	$	1,416		$	45
Acquisition of operating entities		—			2,038
	$	1,416		$	2,083
LIBERTY ENERGY
Capital Investment in regulatory assets	$	1,358		$	—
Acquisition of operating entities		98,094			—
	$	99,452		$	—
Consolidated (includes Corporate)
Capital expenditures	$	807		$	4,114
Capital investment in regulatory assets		2,774			45
Acquisition of operating entities		98,094			42,319
Total	$	101,675		$	46,478

APUC’s consolidated capital expenditures in the three months ended March 31, 2011 increased as compared to the same period in 2010 primarily due to the acquisition of the California Assets.

Property, plant and equipment expenditures for the remainder of the 2011 fiscal year are anticipated to be between $23 million and $30 million, including approximately $6.5 million related to ongoing investments by Liberty Water, $2.25 million related to Liberty Energy’s share of ongoing investments at Liberty Energy (California), $6.5 million related to the APCo Thermal division, and $6.5 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.

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2011 First Quarter Property Plant and Equipment Expenditures

During the quarter ended March 31, 2011, APCo incurred capital expenditures of $0.8 million, as compared to $4.1 million during the comparable period in 2010. APCo also invested $40.3 million to acquire operating assets/entities during the comparable period in 2010.

During the quarter ended March 31, 2011, APCo Renewable Energy division’s capital expenditures were $1.0 million, as compared to $0.3 million in the comparable period in 2010. With the exception of a previously anticipated turbine overhaul project at the Tinker facility, 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 in 2010 relate to the Tinker Assets located in New Brunswick and Maine.

During the quarter ended March 31, 2011, APCo Thermal Energy division’s net capital expenditures were ($0.2) million, as compared to $3.8 million in the comparable period in 2010. The recovery in the quarter primarily relates to proceeds from the sale of the turbine at the Crossroads facility. In the comparable period, the capital expenditures primarily relate to the EFW facility where major capital maintenance was underway.

During the quarter ended March 31, 2011, Liberty Water invested maintenance capital of $1.4 million into regulatory assets, as compared to an investment of nil in the comparable period. In the comparable period in 2010, Liberty Water acquired a water and wastewater utility near Galveston Texas for approximately $2.0 million.

During the quarter ended March 31, 2011, Liberty Energy recorded capital expenditures of $1.4 million associated with the acquisition by Liberty Energy (California) of the California Utility.

Quebec Dam Safety Act

As a result of the dam safety legislation passed in Quebec (Bill C93), APCo’s Renewable Energy division completed safety evaluations and technical assessments on eleven of the twelve hydroelectric facility dams owned or leased within the Province of Quebec. Out of these, nine remedial plans have been submitted to the Quebec government and two are undergoing options analysis by APCo. Seven remedial plans have been accepted by the Quebec government and two are still being reviewed. The approval process for remedial plans can sometimes take several years.

In the past five years, APCo has spent approximately $1.1 million on dam safety evaluations, engineering, permitting and civil works related to the Bill C93 requirements. APCo currently estimates further capital expenditures of approximately $17.1 million related to compliance with the legislation. It is anticipated that these expenditures will be invested over a period of several years approximately as follows:

	Total		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.

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

• The dam safety evaluation for the Donnacona facility was completed in 2007 and APCo has been investigating alternative engineering designs to optimize the cost of the remediation work. APCo is now pursuing a design that may result in a cost savings of 20% of the original estimates. APCo anticipates completing the engineering in 2011 and performing the remedial work in 2012 and 2013.

• The dam safety study for the St. Alban facility was completed in 2010. APCo has decided to perform a more detailed condition assessment before finalizing the remediation plan for this dam. APCo anticipates condition assessment, engineering, and regulatory review to be performed between 2011 and 2013, with remedial work in 2014 to 2015.

• APCo is presently reviewing options with respect to the Bellterre facility including the removal of several small dams that are not required for power generation. APCo has been corresponding with the Quebec

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government and other stakeholders about these options since 2007. APCo anticipates completion of any required work on these dams to be completed by 2015.

Dam remediation work related to the other seven Quebec facilities is anticipated to be completed by 2013.

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 March 31, 2011 under the senior banking facility (the “Facility”):

	2011 Q1			2010 Q4			2010 Q3			2010 Q2			2010 Q1
Committed and available Facility	$	142,000		$	142,000	*	$	163,400		$	162,800		$	177,950
Funds Drawn on Facility		(65,000	)		(64,500	)		(108,900	)		(102,800	)		(91,650	)
Letters of Credit issued		(32,900	)		(33,100	)		(33,800	)		(34,600	)		(32,400	)
Remaining available Facility	$	44,100		$	44,400	*	$	20,700		$	25,400		$	53,900
Cash on Hand		2,500			5,100			3,100			2,400			750
Total liquidity and capital reserves	$	46,600		$	49,500		$	23,800		$	27,800		$	54,650

As at and for the period ended March 31, 2011, Algonquin was in compliance with the covenants under the Facility. As at March 31, 2011, $65.0 million had been drawn on the Facility as compared to $64.5 million as at December 31, 2010. In addition to amounts actually drawn, there were $32.9 million in letters of credit outstanding as at March 31, 2011.

During the quarter, 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 banking agreement, Algonquin had $44.1 million of committed and available bank facilities remaining and $2.5 million of cash resulting in $46.6 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 March 31, 2011 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	$	325,180	$	69,773	$	3,221	$	68,876	$	183,310
Convertible Debentures2	$	185,164		62,397		—		59,967		62,800
Interest on long-term debt obligations	$	184,567		24,662		45,521		39,142		75,242
Purchase obligations	$	38,732		38,732		—		—		—
Derivative financial instruments:
Interest rate swap	$	4,458		1,530		2,260		668		—
Capital lease obligations	$	542		215		302		25		—
Other obligations	$	9,928		1,170		2,339		2,339		4,080
Total obligations	$	748,571	$	198,479	$	53,643	$	171,017	$	325,432

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

2. Convertible debentures due in less than one year relates to the Series 1A Debentures which will be redeemed for equity effective May 16, 2011.

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SHAREHOLDER’S EQUITY AND CONVERTIBLE DEBENTURES

APUC’s shares are publicly traded on the Toronto Stock Exchange (“TSX”). As at March 31, 2011, APUC had 103,988,567 issued and outstanding shares on a fully diluted basis.

As at March 31, 2011, APUC had issued to Emera 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. 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 to acquire of Granite State and EnergyNorth.

Subsequent to March 31, 2011, APUC had agreed to issued to Emera 8.2 million shares with regards to the acquisition by Liberty Energy of Emera’s 49.999% direct ownership in Liberty Energy (California). The approval on the ownership transfer is expected in late 2011. The payment of shares is to be made in two tranches with approximately half of the shares being issued following regulatory approval of the ownership transfer and the balance of the shares being issued following completion of Liberty Energy (California)’s first rate case which is expected to be completed in mid 2012.

On April 30, 2011, APUC committed to issuance to Emera of a treasury subscription of subscription receipts convertible into approximately 6.9 million APUC common shares upon closing of the transaction related to the acquisition of an interest in a portfolio of 370MW wind projects (see Major Highlights - Acquisition of First Wind’s Northeast Projects for more details on the acquisition) at a purchase price of $5.37 per subscription receipt. Total gross proceeds to APUC of $37 million will be utilized to fund a portion of the cost to acquire the interest in Northeast Wind.

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.

The Series 1A Debentures are due November 30, 2014 and pay 7.5% interest semi-annually in arrears on January 1 and July 1 each year. The Series 1A Debentures are convertible into shares of APUC at the option of the holder at a conversion price of $4.08 per share. On April 7th, 2011, APUC announced that it had provided the holders of its Series 1A Debentures notice of its intention to redeem, effective May 16, 2011 (“Redemption Date”), all of the issued and outstanding Debentures.

The redemption will be effected in accordance with the terms and definitions of the trust indenture governing the Debentures. APUC will satisfy its obligation to pay holders of Debentures (“Debentureholders”) by issuing and delivering the number of freely tradeable APUC shares obtained by dividing the aggregate principal amount of Debentures, by 95% of the current market price of APUC shares on the Redemption Date. Unpaid accrued interest on the Debentures will be paid in cash at the time of redemption.

During the three months ended March 31, 2011, a principal amount of $73 of Series 1A Debentures were converted into 17,791 shares of APUC. On March 31, 2011, there were 62,397 Series 1A Debentures outstanding with a face value of $62,397. Subsequent to the end of the quarter, $22,620 Series 1A Debentures were converted into 5,543,835 shares of APUC.

The convertible unsecured subordinated debentures bearing interest at 6.35%, maturing on November 30, 2016 (“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. On March 31, 2011, there were 59,967 Series 2A Debentures outstanding with a face value of $59,967.

The convertible unsecured debentures maturing on June 30, 2017 (“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.

During the three months ended March 31, 2011, a principal amount of $105 of Series 3 Debentures was converted into 24,999 shares APUC. On March 31, 2011, there were 62,800 Series 3 Debentures outstanding

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with a face value of $62,800. Subsequent to the end of the quarter, $40 Series 3 Debentures were converted to 9,523 shares.

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.

On August 12, 2010, the Board approved the grant of 1,160,204 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.

On March 22, 2011, the Board approved the grant of 892,107 options to select senior executives of APUC. The options allow for the purchase of common shares at a price of $5.23, the market price of the underlying common share at the date of grant. One-third of the options vest on each of January 1, 2012, 2013 and 2014. Options may be exercised up to eight years following the date of grant.

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. As at March 31, 2011, APUC had recorded $121 (2010 - $nil) in compensation expense. As at March 31, 2011, there was $1,136 (2010 - $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 2.4 years.

As at March 31, 2011, 367,348 options with an intrinsic value of $408 are exercisable. No share options were exercised as at March 31, 2011. The intrinsic value of the 1,626,800 non-vested options as at March 31, 2011 was $816 (2010 – nil).

RELATED PARTY TRANSACTIONS

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

• 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 months ended March 31, 2011 were $82 (2010—$82). 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, Algonquin Airlink Inc. In 2004, APUC entered into an agreement and remitted $1,300 to the affiliate as an advance against expense reimbursements (including engine utilization reserves) for APUC’s business use of the aircraft. Under the terms of this arrangement, APUC will have priority access to make use of the aircraft for a specified number of hours at a cost equal solely to the third party direct operating costs incurred when flying the aircraft. During the three months ended March 31, 2011, APUC incurred costs in connection with the use of the aircraft of $71 (2010 - $148) and amortization expense related to the advance against expense reimbursements of $41 (2010 - $57). At March 31, 2011, the remaining amount of the advance was $513 (2010 - $609) 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 2021. 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 $44 (2010 - $23) for the three months ended March 31, 2011.

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• APMI is one of the two original developers of Red Lily I and both developers are entitled to a royalty fee based on a percentage of operating revenue and a development fee from the equity owner of Red Lily I. The royalty fee is initially equal to 0.75% of gross energy revenue, increasing every five years up to 2% after twenty-five years. During the three months ended March 31, 2011, APUC acquired APMI’s interest in this royalty for an amount of $600. This amount has been recorded as a purchase of intangible assets and the amount is included in accrued liabilities at March 31, 2011. APMI is also entitled to a development fee of up to $400 following commercial operation of the project and has agreed to permit the Board to determine the portion of such fee which will be paid following commercial operation of the facility.

• APUC 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.

• The above related party transactions have been recorded at the exchange amounts agreed to by the parties to the transactions. As at March 31, 2011 the amount due from the above related party transactions was $551 (2010 - $718) and amounts due to related parties was $1,534 (2010 - $901).

• 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.

• 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 nil (2010 - $1,368) 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 Maine Public Service (“MPS”). Subsequent to the date of this acquisition, the Energy Services Business sold electricity of U.S. $2,040 (2010 – 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 months ended March 31, 2011 APUC paid U.S. $61 (2010 - $0) in relation to this contract. In the same period, APUC provided a corporate guarantee to a subsidiary of Emera in an amount of U.S. $500 in conjunction with this contract.

• As of March 31, 2011, included in amounts due from related parties is $1,554 (2010 - $0) owed from Emera related to their share of system integration and regulatory approval costs related to Liberty Energy (California).

• 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.

• 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

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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 March 31, 2011, $513 of the advance remained. The Board has undertaken an independent review of the relationship and believes that continuing the arrangement is beneficial to the company. The current arrangement is expected to end in approximately 2016 when the capital advance will be repaid.

vi) Office lease

APUC has leased its head office facilities on a triple net basis from an entity partially owned by Senior Executives. The original lease was due to expire in December 31, 2012. In addition, effective April 1, 2011, Liberty Utilities (Canada) Corp. has leased its head office facilities from a third party in a new stand alone building immediately adjacent to APUC’s head office for a term of 5 years ending December 31, 2015 with an additional 5 year renewal option. APUC has amended its lease at its existing premises to be co-terminus with the Liberty Water Canada lease. The majority of terms in the amended lease are identical and the based on a review of the real estate leasing market in the fall of 2010, APUC believes the amended lease is on terms equivalent to fair market value for prime office space of similar size and quality.

vii) Operations services

Staff managed by APUC operate an additional three hydroelectric generating facilities where Senior Executives hold an interest. Effective January 1, 2011, management of these facilities is now being undertaken by Algonquin Power Systems Inc. (“APS”) which is a non-APUC related entity. APUC and APS have agreed to provide some transition services to each other until December 31, 2011. Costs for providing such transition services are intended to be on a cost recovery basis with no mark-up for profit.

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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 fees, third party costs and other liabilities with the proceeds from the lawsuits being shared after reimbursement of legal fees, third party costs and other liabilities. The Board has determined that any proceeds from the lawsuit will be between APMI and APUC proportionally to the quantum of such costs funded by each party. 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 Utilities 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

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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 ($0.04 per share) on an annual basis.

The change in mark-to-market losses/(gains) on derivative financial instruments results from changes in foreign exchange rates, changes in interest rates or forward energy prices and relate to long term contract periods which extend to fiscal 2015. 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 March 31
	2011			2010			Change
Foreign Exchange Contracts:
Change in unrealized mark-to-market gain on derivative financial instruments	$	(45	)	$	(1,083	)	$	1,038
Realized loss (gain) on derivative financial instruments		694			(132	)	$	826
	$	649		$	(1,215	)	$	1,864
Energy Forward Purchase Contracts:
Change in unrealized mark-to-market loss/(gain) on derivative financial instruments	$	(950	)	$	(1,834	)	$	884
Realized loss on derivative financial instruments		319			1,828		$	(1,509	)
	$	(631	)	$	(6	)	$	(625	)
Interest Rate Swap Contracts:
Change in unrealized mark-to-market gain on derivative financial instruments	$	(980	)	$	(1,288	)	$	308
Realized loss on derivative financial instruments		533			1,596		$	(1,063	)
	$	(447	)	$	308		$	(755	)
Derivative Financial Instruments Total:
Change in unrealized mark-to-market gain on derivative financial instruments	$	(1,975	)	$	(4,205	)	$	2,230
Realized loss on derivative financial instruments		1,546			3,292			(1,746	)
Total loss/(gain) on derivative financial instruments	$	(429	)	$	(913	)	$	484

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 banking credit facility provided to APCo by a consortium of Canadian chartered banks has an outstanding balance drawn of $65.0 million as at March 31, 2011. Assuming the current level of borrowings over an annual basis, a 100 basis point change in the variable rate charged would impact interest expense by $0.6 million annually.

• APCo’s project debt at the St. Leon facility has a balance of $68.3 million as at March 31, 2011. Assuming the current level of borrowings over an annual basis, a 100 basis point change in the variable rate charged would impact interest expense by $0.7 million annually. 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. APCo has effectively fixed its interest expense on the St. Leon senior debt facility at 5.47%. At March 31, 2011, the mark-to-market value of the interest rate swap was a net liability of $4.5 million (2010 – net liability of $4.5 million).

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

Liberty Water’s project debt at the Litchfield and Bella Vista Facilities are subject to a fixed rate of interest and thus are not subject to interest rate risk. Liberty Water’s U.S. $50 million senior unsecured notes with a 10 year

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term bearing a fixed rate of interest at 5.6% are subject to a fixed rate of interest and are not subject to interest rate risk.

Liberty Energy’s U.S. $70 million senior unsecured private debt placement at the California utility is 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. As such these notes are not subject to interest rate risk.

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 $0.26 per share per year. 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 months ended March 31, 2011, cash provided by operating activities exceeded dividends declared by 2.9 times.

As at March 31, 2011, APUC had cash on hand of $2.5 million and $44.1 million available to be drawn on the Facility. 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 $325.2 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. See APUC’s audited consolidated financial statements for the years ended December 31, 2010 and 2009 for discussion of this risk.

Liberty Water is not subject to any material commodity price risk.

Liberty Energy is exposed to energy price risk which is mitigated through the certain regulatory constructs. Liberty Energy (California) provides electric service to the Lake Tahoe basin and surrounding areas at rates approved by the CPUC. The utility purchases the energy requirements for its customers from NV Energy at rates reflecting NV Energy’s system average costs. In the event that these rates change, each $10.00 change per MW-hr would result in a change in expense of approximately U.S. $5.4 million on an annualized basis.

The rate structure in California allows for a pass-through of energy costs to rate payers on a dollar for dollar basis, through the energy cost adjustment clause (“ECAC”) mechanism, which is designed to recoup power supply costs that are caused by the fluctuations in the price of fuel and purchased power. Actual power supply costs incurred by the facility are tracked and compared to the base rate power supply costs to ensure the cumulative variance does not exceed 5%. In the event that the cumulative variance exceeds 5%, the ECAC

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allows for an adjustment to Liberty Energy (California)’s approved rates (including carrying charges associated therewith), substantially eliminating the commodity risk associated with the purchase of power.

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. 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. The electricity distribution systems owned by Liberty Energy are subject to storm events, usually winter storm events, whereby power lines can be brought down with the attendant risk to individuals and property. In addition, in forested areas, power lines brought down by wind can ignite forest fires which also bring attendant risk to individuals and property.

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

Electricity and natural gas distribution utilities could be subject to condemnation or other methods of taking by government entities under certain conditions. While any taking by government entities would require compensation be paid to Liberty Energy, and while Liberty Energy 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 Energy regularly works with its governing authorities to manage the affairs of the business.

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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.

Liberty Utilities’ 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 Utilities 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 distribution facilities and expenses associated with providing new sources of commodity supply can generally be included in the facility’s rate base and thus Liberty Utilities expects to be allowed to earn a return on such investment.

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.

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.

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

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

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 March 31, 2011.

Cycles and Seasonality

For Liberty Electric, demand for energy is primarily affected by weather conditions and conservation initiatives. Above normal snowfall in the Lake Tahoe area brings more tourists with an increased demand for electricity by small commercial customers. Liberty Electric provides information and programs to its customers to encourage the conservation of energy. In turn, demand may be reduced which could have short term adverse impacts to revenues.

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

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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

Management, including the Chief Executive Officer and the Chief Financial Officer, is responsible for establishing and maintaining internal control over financial reporting as defined in National Instrument 52-109 Certification of Disclosure in Issuers’ Annual and Interim Filings. Management, as at the end of the period covered by this interim filing, designed internal control over financial reporting to provide reasonable, but not absolute, assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with U.S. GAAP. The control framework management used to design the issuer’s internal control over financial reporting is that established in Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.

Changes in internal controls over financial reporting

During the quarter ended March 31, 2011, 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. APUC’s transition to U.S. GAAP in the period did not result in any significant changes to the APUC’s internal controls.

Quarterly Financial Information

The following is a summary of unaudited quarterly financial information for the two years ended March 31, 2011.

Millions of dollars (except per share amounts)	2nd Quarter  2010*			3rd Quarter  2010*		4th Quarter  2010*			1st Quarter  2011
Revenue	$	42.7		$	45.4	$	48.9		$	71.7
Net earnings /(loss)		(2.2	)		1.5		16.9			5.0
Net earnings / (loss) per share		(0.02	)		0.02		0.18			0.05
Total Assets		983.2			969.4		980.9			1,175.8
Long term debt**		446.7			452.8		461.0			461.0
Dividend/distribution per share		0.06			0.06		0.06			0.065
	2nd Quarter 2009*			3rd Quarter 2009*		4th Quarter 2009*			1st Quarter  2010*
Revenue	$	46.5		$	45.1	$	43.4		$	45.9
Net earnings / (loss)		15.3			13.1		(1.4	)		3.5
Net earnings / (loss) per trust unit		0.20			0.17		(0.03	)		0.04
Total Assets		952.4			925.7		1,013.4			966.2
Long term debt**		456.2			445.4		439.9			434.0
Distribution per trust unit		0.06			0.06		0.06			0.06

* Based on Canadian Generally Accepted Accounting Principals

** 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.

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Quarterly revenues have fluctuated between $42.7 million and $71.7 million over the prior two year period. A number of factors impact quarterly results including acquisitions, 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 Interim Consolidated Financial Statements in accordance with U.S 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 Interim Consolidated Financial Statements for additional information on accounting principles. The Interim 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, 2010 available on SEDAR at www.sedar.com and on the APUC website at www.AlgonquinPowerandUtilities.com.

Changes in Accounting Policies

APUC’s accounting policies are described in Note 1 to the Interim Unaudited Consolidated Financial Statements for the period ended March 31, 2011.

Accounting framework

The unaudited consolidated interim financial statements and accompanying notes have been prepared in accordance with generally accepted accounting principles in the United States (U.S. GAAP) and follow disclosures required per Regulation S-X Rule 10-10, Interim Financial Statements provided by the Securities and Exchange Commission (SEC) Guidance. These are the Company’s first U.S. GAAP consolidated interim financial statements for part of the period covered by the first U.S. GAAP annual financial statements.

The Company’s consolidated financial statements were prepared in accordance with Canadian Generally Accepted Accounting Principles (“Canadian GAAP”) until December 31, 2010. Canadian GAAP differs in some areas from US GAAP as was disclosed in the reconciliation to U.S. GAAP included in the audited annual financial statements for the year ended December 31, 2010. Descriptions of the effect of the transition from Canadian GAAP to U.S. GAAP on the Company’s financial position, financial performance and cash flows as at and for the two years ended December 31, 2010 are provided in note 24 of the audited consolidated financial statements for the year ended December 31, 2010. The accounting policies set out in the Interim Consolidated Financial Statements for the period ended March 31, 2011 have been consistently applied to all the periods presented. The comparative figures in respect of 2010 were restated to reflect the adoption of U.S. GAAP.

There was no significant impact of the transition to U.S. GAAP on APUC’s internal controls, information technology systems and financial reporting expertise requirements. No financial covenants were impacted by APUC’s conversion to U.S. GAAP given the few differences that exist with Canadian GAAP.

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