Press release, dated March 4, 2010.

OAKVILLE, Ontario – March 4, 2010 - Algonquin Power & Utilities Corp. (TSX: AQN), today announced financial results for the fourth quarter and year ended December 31, 2009. On October 27, 2009, Algonquin Power Income Fund became a wholly owned subsidiary of Algonquin Power & Utilities Corp., maintaining the same operations and business activities, but under a corporate structure with Algonquin Power Income Fund’s unitholders becoming shareholders of the new Algonquin Power & Utilities Corp. (collectively “APUC”).

APUC ended the year having completed several significant accomplishments. The change in business form from an income trust structure to a corporate structure will facilitate APUC’s long term growth as it now focuses on providing total shareholder return through a combination of dividends and capital appreciation realized through the successful execution of its business strategies. Major growth initiatives accomplished in the year included the announcement of the acquisition of a regulated electricity distribution utility in California, serving over 47,000 customers, which is expected to close later in 2010. APUC also grew its renewable power portfolio with the announcement of the acquisition of 36.8 MW of hydroelectric generating assets in New Brunswick and Maine which closed on January 12, 2010.

For the fourth quarter of 2009, revenue was $43.4 million as compared to $56.5 million in the fourth quarter of 2008 and $45.1 in the third quarter of 2009. The decrease in revenue is due to reduced average energy rates and lower demand for steam at the Sanger and Windsor Locks facilities in the Thermal Energy division and lower weighted average energy rates and lower average hydrology and wind resources in the Renewable Energy division. In addition, revenue decreased as a result of a stronger Canadian dollar as compared to the same period in 2008.

Adjusted earnings before interest, taxes, depreciation, and amortization (“Adjusted EBITDA”) was $18.0 million in the fourth quarter of 2009 as compared to $23.3 million in the fourth quarter of 2008 and $20.3 in the third quarter of 2009. The decrease in Adjusted EBITDA is primarily related to lower gas prices and reduced demand for steam at APUC’s thermal energy facilities and lower average energy rates earned by the U.S. renewable energy facilities.

Adjusted net earnings in the fourth quarter of 2009 were $11.5 million or $0.14 per share as compared to adjusted net earnings of $8.8 million or $0.12 per share in the fourth quarter of 2008 and $13.1 million or $0.09 per share in the third quarter of 2009. APUC uses adjusted net earnings to assess the net earnings of APUC without the effects of gains or losses on foreign exchange, foreign exchange forward contracts, and interest rate swaps as these are primarily non-cash items that are not reflective of the performance of the underlying business of APUC.

APUC reported a net loss in the fourth quarter of 2009 of $1.4 million or $0.03 per share as compared to a net loss of $21.1 million or $0.28 per share for the fourth quarter of 2008 and net earnings of $13.1 million or $0.17 per share in the third quarter of 2009.

“APUC is pleased at the breadth and scope of the significant changes which have occurred through 2009, with the organization finishing the year looking dramatically different than when it entered the year,” commented Ian Robertson, Chief Executive Officer of APUC. “Despite the volatility in the capital markets and wavering global economic environment in 2009, APUC achieved several major goals we had set for ourselves including positioning the company for growth in 2010 by strengthening our balance sheet through our $86 million dollar financing of common shares and convertible debentures in December. APUC is optimistic that the diversification of its portfolio, coupled with the impact of its committed growth initiatives, will serve the organization well in 2010.”

APUC’s financial information and analysis are available on our web site at www.algonquinpowerandutilities.com.

APUC will hold an earnings conference call at 10:00 a.m. eastern time on Friday, March 5, 2010, hosted by Chief Executive Officer Ian Robertson and Chief Financial Officer David Bronicheski.

Phone Number: Toll free within North America: 1-877-974-0446 or local 416-644-3418.

For those unable to attend the live call, a digital recording will be available for replay two hours after the call by dialing 1-877-289-8525 or 416-640-1917 access code 4224434# from March 5, 2010 until March 12, 2010.

Through its distinct operating subsidiaries, APUC owns and operates a diversified portfolio of clean renewable electric generation and sustainable utility distribution businesses throughout North America. APUC’s electric generation subsidiary, carrying on business as Algonquin Power Co., includes 45 renewable energy facilities and 11 high efficiency thermal energy facilities representing more than 450 MW of installed capacity. Through its wholly owned subsidiary, Liberty Water Co., APUC provides regulated utility services to more than 70,000 customers across 18 water distribution and wastewater treatment utility systems. Pursuant to a previously announced agreement, APUC is committed to acquiring the California based regulated utility electric distribution and generation assets of NV Energy which serve approximately 47,000 retail electricity distribution customers. APUC and its operating subsidiaries deliver continuing growth through an expanding pipeline of greenfield and expansion renewable power and clean energy projects, organic growth within its regulated utilities and the aggressive pursuit of accretive acquisition opportunities. APUC’s common shares and convertible debentures are traded on the Toronto Stock Exchange under the symbols AQN, AQN.DB, AQN.DB.A, and AQN.DB.B. Visit Algonquin Power & Utilities Corp. on the web at www.AlgonquinPowerandUtilities.com.

This news release may contain certain information that is future-oriented, including information and statements regarding prospective results of operations, financial position or cash flows. These statements and information are forward-looking, and are based on factors or assumptions that were applied in drawing a conclusion or making a forecast or projection, including assumptions based on historical trends, current conditions and expected future developments, and other factors believed to be appropriate in the circumstances. Although the forward-looking statements and information are based upon management’s current expectations and assumptions, they are subject to numerous risks and uncertainties, including those set out in the management’s discussion and analysis section of APUC’s 2008 annual report, APUC’s Annual Information Form dated March 31, 2009, and APUC’s Management Information Circular dated March 20, 2009. Readers are cautioned that such risks and uncertainties may cause APUC’s actual results to vary materially from those expressed in, or implied by, the forward-looking statements and information. Any forward-looking statements or information contained in this news release are made as of the date hereof for the purpose of providing readers with APUC’s expectations for the coming financial period(s), and may not be appropriate for other purposes. Other than as specifically required by law, APUC undertakes no obligation to update any forward-looking statements or information to reflect new information, subsequent or otherwise.

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

Management of Algonquin Power & Utilities Corp. (“APUC”), the corporation continuing the business of the Algonquin Power Income Fund (the “Fund”), has prepared the following discussion and analysis to provide information to assist its shareholders’ understanding of the financial results for the three and twelve months ended December 31, 2009. This Management’s Discussion and Analysis (“MD&A”) should be read in conjunction with APUC’s audited consolidated financial statements for the years ended December 31, 2009 and 2008 and the notes thereto. 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 can be found on SEDAR at www.sedar.com.

This MD&A is based on information available to management as of February 27, 2010.

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 “outlook”, “believes”, “anticipates”, “continues”, “could”, “expect”, “may”, “will”, “project”, “estimates”, “intend”, “plan” 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 our actual results may differ materially from the expectations set out in the forward-looking statements. Material risk factors include the continued volatility of world financial markets; 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. Although APUC believes that the assumptions inherent in these forward-looking statements are reasonable, undue reliance should not be placed on these statements, which apply only as of these dates. APUC is not obligated to nor does it intend to update or revise any forward-looking statements, whether as a result of new information, future developments or otherwise, except as required by law.

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

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

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

APUC is a corporation incorporated under the Canada Business Corporations Act. APUC produces stable earnings through a diversified portfolio of renewable energy and utility businesses owned and operated by its subsidiary entities. APUC conducts its business primarily through two businesses:

The first, conducting business as Algonquin Power Co. (“APCo”), generates electrical energy through a diverse portfolio of clean, renewable power generation and thermal power generation facilities across North America. As at December 31, 2009, APCo owns 41 hydroelectric facilities operating in Ontario, Québec, Newfoundland, Alberta, New York State, New Hampshire, Vermont and New Jersey with a combined generating capacity of 140 MW. APCo also owns a 99 MW wind farm in Manitoba. The renewable energy facilities are generally facilities operating under long term power purchase agreements with major utilities and have an average remaining contract life of 16 years. APCo’s 11 thermal energy facilities operate under power purchase agreements (“PPAs”) and have an average remaining contract life of 7 years with a combined generating capacity of 321 MW.

The second, Liberty Water Co. (“Liberty Water”) provides water and wastewater utility services through 18 water distribution and wastewater utility systems in the United States. Liberty Water provides regulated water distribution and wastewater facilities in Arizona, Illinois, Missouri and Texas. These utility operating companies are regulated investor-owned utilities subject to regulation, including rate regulation, by the public utility commissions of the states in which they operate.

APUC’s business strategy is to maximize long term shareholder value as a dividend paying, growth oriented corporation actively competing within its clearly defined business sectors. APUC is committed to delivering a total shareholder return comprised of a dividend augmented by capital appreciation arising through growth in earnings and dividends. Through an emphasis on sustainable, long view renewable power and utility investments, over a medium term planning horizon APUC strives to deliver annualized earnings growth exceeding 5% and is committed to growing its dividend supported by such earnings.

Independent Power: APCo develops and operates a diversified portfolio of electrical energy generation facilities. Within this business there are three distinct divisions: Renewable Energy, Thermal Energy and Development. The Renewable Energy division operates APCo’s hydroelectric and wind power facilities. The

Thermal Energy division operates co-generation, energy from waste, steam production and other thermal facilities. The Development division seeks to deliver continuing growth to APCo through the development of APCo’s greenfield power generation projects, accretive acquisitions of electrical energy generation facilities as well as development of organic growth opportunities within APCo’s existing portfolio of renewable energy and thermal energy facilities. The renewable power and thermal energy generation business of APCo is managed with an emphasis on growth through the development of green-field projects and opportunities within APCo’s existing portfolio. This involves building on APCo’s expertise in the origination of greenfield renewable energy projects, building upon APCo’s existing portfolio of assets for further growth, and capitalizing on opportunities that may emerge in the current turbulence of the capital markets.

Regulated Water Utilities: In 2009, APUC branded all of its utilities under the Liberty Water brand. Liberty Water is committed to being the 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 delivers long term shareholder value by profitably owning and operating investor owned water and wastewater utilities providing safe, reliable transportation and delivery of water and wastewater treatment in its service areas. It is also focused on delivering continued growth in earnings by identifying opportunities which accretively expand its business portfolio.

Regulated Electrical Utilities: APUC has announced its plan to establish a third distinct business subsidiary focused on the provision of local regulated electrical generation and distribution utilities within a new business subsidiary to be called Liberty Electric. In this regard APUC announced plans to co-acquire an electrical generation and regulated distribution utility through a strategic partnership with Emera Inc. (“Emera”) (see “Electrical Distribution Utility Acquisition”).

During fiscal 2009, APUC made monthly cash dividends/distributions to shareholders/unitholders of $0.02 per share/trust unit per month or $0.24 per share/trust unit per annum. This level of dividends/cash distributions allows for both an immediate return on investment for shareholders/unitholders and retention of sufficient cash within APUC to fund growth opportunities, debt repayment and mitigate the impact of volatility in foreign exchange rates. APUC strives to achieve its results within a moderate risk profile consistent with top-quartile North American power, utility, and infrastructure operations. Effective January 1, 2010, APUC changed to a quarterly dividend from a monthly dividend. As a result, APUC anticipates declaring a per share dividend for the first quarter of 2010 of $0.06, which is the equivalent of the current per share dividend of $0.02 per month. The first quarterly record date is expected to be March 31, 2010, with a payment date on or about April 15, 2010.

During 2009 APUC completed its conversion from an income trust to a corporation. The conversion was completed through a series of transactions more fully described below.

On October 27, 2009 the Fund’s unitholders exchanged 100% of the outstanding trust units of the Fund for a new class of common shares (“New Common Shares”) of APUC (formerly Hydrogenics Corporation or Hydrogenics), an existing corporation. Immediately prior to this exchange (the “Unit Exchange Offer”), Hydrogenics, under a Plan of Arrangement, transferred all of its operations and substantially all of its assets and liabilities to New Hydrogenics. The pre-existing publicly traded shares of Hydrogenics were contemporaneously redeemed for shares of New Hydrogenics and thus the pre-existing publicly traded shares of Hydrogenics no longer exist.

The transaction resulted in the unitholders of the Fund holding their interest in the Fund as shareholders of APUC. Excluding shares issued under the CD Exchange Offer (as defined and described below), the number of common shares of APUC outstanding immediately after completion of the Unit Exchange Offer was exactly the same as the number of the Fund’s trust units outstanding immediately before the Unit Exchange Offer.

The Unit Exchange Offer was accounted for as a change in business form using the continuity of interests method of accounting. Under this method of accounting, the transfer of the assets, liabilities and equity of the Fund are recorded at their net book values in the financial statements of APUC as at October 27, 2009, the effective date of the transaction. As a result, APUC is required to be accounted for as though it were a continuation of the Fund but with its capital reflecting the exchange of APUC shares for trust units. For the periods reported up to the effective date of the Unit Exchange Offer all payments to unitholders were in the form of trust unit distributions and after that date all payments to shareholders were in the form of dividends.

APUC paid New Hydrogenics $10,813 and has accrued an additional amount of $494 as a final closing adjustment. As a result of the Unit Exchange Offer, together with substantively enacted changes in tax rates in December 2009, APUC recognized a future income tax asset of $60,014 and a deferred credit in relation to this asset of $49,879 as at December 31, 2009. For accounting purposes the deferred credit is recorded as a credit to tax expense when the future tax assets are realized.

Also as a result of the completion of the Unit Exchange Offer, APUC recorded an increase to its recorded future tax liability. This adjustment reflects the tax impact of recording future tax assets and liabilities for temporary differences in APUC’s flow-through entities that are reversing or settling prior to 2011 which were previously not recorded since prior to the transaction these temporary difference reversals were not expected to be taxed in APUC.

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

On December 21. 2009, the Board of Directors of APUC (the “Board”) reached agreement with the shareholders of Algonquin Power Management Inc. (the “Manager” or “APMI”) to internalize all management functions of the Fund which were provided by the Manager. APUC will acquire the interest previously held by the Manager in the management services agreement, subject to regulatory and shareholder approval, with consideration to be paid in the form of issuance of 1,158,748 APUC shares (the “Shares”). An independent advisor retained by the Board concluded that the consideration to be paid by APUC pursuant to the transaction is fair, from a financial point of view. The expense has been measured at $4,693 using a price for each share of $4.03, the adjusted closing market price on December 21 2009, the date the agreement was ratified.

Effective as of December 21, 2009, Mr. Ian Robertson assumed overall responsibility for APUC’s operations as Chief Executive Officer and will be invited to join the Board. Mr. Robertson previously held the position of Executive Director, Business Development with the Fund. Mr. Chris Jarratt has joined the Strategy Development Committee where he is co-directing the development of strategy with APUC management and will be invited to join the Board in the role of Vice Chairman. Mr. David Kerr has been retained to provide transitional services to APUC.

In accordance with the policies of the Toronto Stock Exchange, approval of the issuance of the Shares will be sought from shareholders at the next annual general meeting. The beneficial interest in the Shares of those individuals who are continuing in management roles with APUC is intended to create and maintain alignment with the interests of APUC’s shareholders.

During the second quarter of 2009, the Board of Trustees of the Fund also announced that, in conjunction with the Unit Exchange Offer, holders of the Fund’s convertible debentures would be provided the opportunity to exchange their debentures for new debentures of APUC (the “CD Exchange Offer”).

Contemporaneously with the Unit Exchange Offer on October 27, 2009, holders of the Fund’s convertible debentures exchanged their convertible debentures for convertible debentures or common shares of APUC resulting in the Fund’s debentureholders becoming debentureholders and shareholders of APUC and the maturity date of the Series 1 Debentures being extended from 2011 to 2014.

Pursuant to the CD Exchange Offer, $63,755 of the outstanding Series 1 Debentures were exchanged for Series 1A Debentures in a principal amount of $66,943, and $21,209 of the outstanding Series 1 Debentures were exchanged for 6,607,027 shares of APUC. In addition, all of the outstanding Series 2 Debentures were exchanged for Series 2A Debentures in a principal amount of $59,967. (See – Shareholder’s Equity and Convertible Debentures).

Strengthened Balance Sheet - $75 Million Offering of Common Shares and Convertible Debentures

On December 2, 2009, APUC completed, on a bought deal basis, an offering of 5,980,000 common shares at $3.35 per common share for gross proceeds of $20,033 and an offering for $55,000 principal amount of 7% convertible unsecured subordinated debentures due June 30, 2017 (the “Series 3 Debentures”). The underwriters of the offering also exercised in full an over-allotment option to purchase an additional 897,000 common shares and $8,250 principal amount of Series 3 Debentures on the same terms. As a result of the closing of the main offering and the over-allotment option, APUC raised an aggregate of $82,606 in net proceeds after underwriting expenses and before additional issuance costs ($86,288 in gross proceeds).

The Series 3 Debentures bear interest at a rate of 7% per annum payable semi-annually in arrears on the last day of June and December in each year commencing on June 30, 2010, and will mature on June 30, 2017. The Series 3 Debentures will be convertible at the holder’s option into common shares of APUC at a conversion price of $4.20 per common share (See – Shareholder’s Equity and Convertible Debentures).

Expanded Regulated Utility Business - Electrical Distribution Utility Acquisition

On April 23, 2009, APUC announced that it plans to co-acquire an electrical generation and regulated distribution utility through a strategic partnership with Emera Inc. (“Emera”). APUC and Emera will each own 50% of the newly formed California Pacific Electric Company, LLC (“Calpeco”), a California limited liability company, which intends to acquire the California-based electricity distribution and related generation assets (the “California Utility”) of NV Energy, Inc. for the purchase price of approximately US $116 million, subject to certain working capital and other closing adjustments. APUC and Emera will jointly own and operate the California Utility through Calpeco. The California Utility currently provides electric distribution service to approximately 47,000 customers in the Lake Tahoe region. In October 2009, an application was filed with the California Public Utilities Commission requesting approval of the transaction in which NV Energy has agreed to sell its California electric distribution and generation assets to Calpeco. The transaction is subject to state and federal regulatory approval which is expected to occur in the latter half of 2010.

As an element of the California Utility strategic partnership, Emera has also agreed to a conditional treasury subscription of approximately 8.5 million shares of APUC at a price of $3.25 per share. Delivery of the shares under the subscription receipts is conditional on and is planned to occur simultaneously with the closing of the acquisition of the California Utility.

As of December 31, 2009, APUC has incurred costs of $1.1 million related to the acquisition of the California Utility. These costs are recorded as deferred transaction costs in other assets on the Consolidated Balance Sheet.

Expanded Renewable Energy Portfolio – Tinker Hydro-electric Generating Asset Acquisition

Subsequent to December 31, 2009, on January 12, 2010, APUC completed the acquisition of 36.8 MW of electrical generating assets (the “Tinker Assets”) that was announced on November 10, 2009. The Tinker Assets are located in New Brunswick and Maine and were purchased after satisfying the conditions of the acquisition, including regulatory approval.

Through the purchase of shares and assets, APCo has acquired three hydroelectric generating stations, the 34.5MW Tinker Hydro, a hydroelectric generating facility with sufficient reservoir storage capability to move significant amounts of energy from off-peak to on-peak generation located on the Aroostook River near the Town of Perth-Andover, New Brunswick, Caribou Hydro, a 0.9MW run-of-river hydroelectric generating facility located in Northern Maine and Squa Pan Hydro, a 1.4MW run-of-river hydroelectric generating facility located in Northern Maine.

APCo has also acquired five thermal generating facilities with a rated capacity of 40MW in Northern Maine and New Brunswick utilized for installed reserve capacity, not continuous generation, New Brunswick Public Utilities Board regulated transmission lines and interconnections which allow direct and indirect access to multiple electricity markets (Northern Maine ISA, New Brunswick ISO, New England ISO).

In connection with the acquisition of the Tinker Assets, on February 4, 2010, APCo acquired a number of load supply and energy procurement contracts in northern Maine and the ISO New England (ISONE) market (“Energy Services Business”). It is anticipated that the majority of the energy sold by the Energy Services Business will be supplied through generation from the Tinker Assets, based on historical long term average levels of hydroelectric energy generation of these facilities. The Energy Services Business involves Standard Offer (SO) contracts for the supply of energy to commercial and industrial customers in northern Maine, as well as energy purchase obligations with the ISO NE required to supplement self-generated energy.

The Energy Services Business is based on a series of short-term energy supply agreements which generally will expire within the next 14 months. These include energy sales to a town in New Brunswick, Standard Offer Service contracts with three local electric utilities in northern Maine, and a series of direct energy contracts with commercial buyers also in northern Maine.

The hydroelectric and thermal generation assets offer capacity to support the energy services obligations in northern Maine. The acquisition improves hydrologic diversification through a new geographical area to the APCo generation portfolio and builds APCo’s Eastern Canadian generating presence.

During the 2009, the 18 individual water and waste water utilities owned by APUC were reorganized under the consolidated brand of Liberty Water with the objective of improving the quality and consistency of services provided to the organization’s approximately 70,000 regulated water/wastewater utility customers through updated web customer service, paperless electronic billing and expanded service hours. A secondary objective of aggregating APUC’s water utility operations under the Liberty Water brand is to support the transparent analysis of APUC’s water utility business as compared to other publicly traded US based water utility businesses.

At the annual general meeting of unitholders of the Fund held on July 27, 2009, in addition to the re-election of existing trustees, Mr. Huskilson was elected as a trustee of the Fund. As part of the Unit Exchange Offer, the trustee’s of the Fund also became directors of APUC. The Board and management of APUC believe that Mr. Huskilson’s utility and power experience will make a strong addition to the Board and will support APUC’s long term strategy and corporate governance activities. As part of the management internalization process, Mr. Robertson and Mr. Jarratt have been invited to join the Board.

APUC’s slate of proposed Directors in respect of the election of Directors by shareholders at the annual general meeting shall continue to be determined by the Directors in accordance with APUC’s governance policies and procedures. It is contemplated that Mr. Robertson and Mr. Jarratt will stand for election as Directors at the next annual general meeting of shareholders.

For the year ended December 31, 2009, APUC reported total revenue of $187.3 million as compared to $213.8 million during the same period in 2008, a decrease of $26.5 million or 12.4%. The decrease in APUC revenue in the twelve months ended December 31, 2009 was primarily the result of $23.3 million in lower APCo revenue due to reduced average energy rates, lower demand for steam at the Sanger and Windsor Locks facilities in the Thermal Energy division, and $6.8 million lower revenue due to lower weighted average energy rates and lower average hydrology and wind resources in the Renewable Energy division, as compared to the same period in 2008. These decreases were partially offset by an increase of $2.5 million due to the Brampton Cogeneration Inc. (“BCI”) facility being operational in the APCo Thermal Energy division as compared to the same period in 2008 as BCI commenced operations in June 2008. APUC reported increased revenue of $5.3 million from U.S. operations as a result of the weaker Canadian dollar as compared to the same period in 2008. A more detailed analysis of these factors is presented within the business unit analysis. APCo attributes the reduced average energy rates to the overall effect the economic slow down has had on energy prices primarily in New York and New England where its hydro electric plants sell merchant power. APCo attributes lower revenue at its Sanger and Windsor Locks facilities to lower gas prices and to lower demand from the steam hosts resulting from the recession in the U.S.

For the year ended December 31, 2009, APUC experienced an average U.S. exchange rate of approximately $1.142 as compared to $1.067 in the same period in 2008. As such, any year over year variance in revenue or expenses, in local currency, at any of APUC’s U.S. entities are affected by a change in the average exchange rate, upon conversion to APUC’s reporting currency. Although a weaker Canadian dollar relative to the U.S. dollar has an impact on both revenue and expenses generated by its U.S. subsidiaries, APUC’s foreign exchange forward contracts partially offset the impact on earnings (see Risk Management).

Adjusted EBITDA in the twelve months ended December 31, 2009 totalled $79.4 million as compared to $90.0 million during the same period in 2008, a decrease of $10.7 million or 12%. The decrease in Adjusted EBITDA is primarily related to $8.8 million in lower earnings from operations primarily resulting from lower gas prices and reduced demand for steam in the APCo Thermal Energy division and lower average energy rates earned by the APCo Renewable Energy division’s U.S. facilities. A more detailed analysis of these factors is presented within the reconciliation of Adjusted EBITDA to net earnings set out below (see Non-GAAP Performance Measures).

For the year ended December 31, 2009, net earnings totalled $31.3 million as compared to net loss of $19.0 million during the same period in 2008. Net earnings per share/trust unit totalled $0.39 for the year ended December 31, 2009, as compared to net loss per share/trust unit of $0.25 during the same period in 2008.

The increase in net earnings as compared to 2008 was primarily the result of a change in income of $65.5 million due to unrealized mark to market gains on derivative financial instruments partially offset by losses on derivative financial instruments contracts settled in the period, as a result of decreased interest rates and the weaker Canadian dollar.

Unrealized mark to market losses on derivative financial instruments resulting from changes in foreign exchange rates relate to contract periods which extend to fiscal 2013. Unrealized mark to market losses on derivative financial instruments resulting from changes in interest rates relate to contract periods which extend to fiscal 2015. The following chart provides a summary of the period over period changes between realized and unrealized mark to market gains and losses of derivative financial instruments:

In addition, net earnings for the year ended December 31, 2009 increased $4.9 million from reduced interest expense due to lower rates on APUC’s variable interest rate debt booked in the period, $5.3 million due to non-cash gains on foreign exchange resulting from the weaker Canadian dollar and $18.8 million related to a recovery in future income taxes primarily due to the conversion to a corporation from an income trust, changes in future income tax rates, tax losses on U.S. operations resulting from bonus depreciation and lower energy and natural gas prices as compared to the same period in 2008 and the recovery of non-deductible interest expense related to U.S. operations. These increases were partially offset by $6.5 million related to the write down of certain thermal assets, $4.7 million related to the costs associated with the internalization of management, $3.5 million related to corporatization costs, $2.0 million due to increased amortization expense, $8.8 million due to lower earnings from operating facilities, $1.3 million due to increased administrative expenses and $5.9 million resulting from increased minority interest gains at the St. Leon facility primarily due to unrealized gains on financial instruments.

During the twelve months ended December 31, 2009, cash provided by operating activities totalled $50.0 million or $0.63 per share/trust unit as compared to cash provided by operating activities of $77.2 million, or $1.03 per share/trust unit during the same period in 2008. Cash provided by operating activities exceeded dividends/distributions by 2.6 times during the twelve months ended December 31, 2009 as compared to 1.4 times during the same period in 2008. The change in cash provided by operating activities after changes in working capital in the twelve months ended December 31, 2009 is primarily due to increased realized losses from derivative instruments and decreased earnings from operating facilities, as compared to the same period in 2008.

For the three months ended December 31, 2009, APUC reported total revenue of $43.4 million as compared to $56.5 million during the same period in 2008, a decrease of $13.1 million or 23%. The decrease in APUC revenue in the three months ended December 31, 2009 was primarily the result of a decrease of $4.1 million due to reduced average energy rates and lower demand for steam at the Sanger and Windsor Locks facilities in the APCo Thermal Energy division and a $2.8 million decrease due to lower weighted average energy rates and lower average

hydrology and wind resources in the APCo Renewable Energy division, as compared to the same period in 2008. In addition, APUC reported decreased revenue of $4.4 million from U.S. operations as a result of the stronger Canadian dollar as compared to the same period in 2008. A more detailed analysis of these factors is presented within the business unit analysis.

For the three months ended December 31, 2009, APUC experienced an average U.S. exchange rate of approximately $1.057 as compared to $1.212 in the same period in 2008. As such, any year over year variance in revenue or expenses, in local currency, at any of APUC’s U.S. entities are affected by a change in the average exchange rate, upon conversion to APUC’s reporting currency. Although a stronger Canadian dollar relative to the U.S. dollar has an impact on both revenue and expenses generated by its U.S. subsidiaries, APUC’s foreign exchange forward contracts in place partially offset the impact on earnings (see Risk Management).

Adjusted EBITDA in the three months ended December 31, 2009 totalled $18.0 million as compared to $23.3 million during the same period in 2008, a decrease of $5.2 million or 22%. The decrease in Adjusted EBITDA is in part due to lower earnings from operations primarily resulting from lower gas prices and reduced demand for steam in the Thermal Energy division and lower average energy rates earned by the Renewable Energy division’s U.S. facilities. A more detailed analysis of these factors is presented within the reconciliation of Adjusted EBITDA to net earnings set out below (see Non-GAAP Performance Measures).

For the three months ended December 31, 2009, net loss totalled $1.4 million as compared to a net loss of $21.1 million during the same period in 2008. Net loss per share/trust unit totalled $0.03 for the three months ended December 31, 2009, as compared to net loss per share/trust unit of $0.28 during the same period in 2008.

The increase in net earnings as compared to 2008 was primarily the result of a change in income of $33.5 million due to unrealized mark to market gains on derivative financial instruments partially offset by losses on derivative financial instruments contracts settled in the period, as a result of increased interest rates and the stronger Canadian dollar.

In addition, net earnings for the three months ended December 31, 2009 increased by $6.7 million related to a recovery in future income taxes primarily due to the reasons outlined in the discussion of the annual results, above

and $2.6 million due to non-cash gains resulting from the stronger Canadian dollar as compared to the same period in 2008. These items were partially offset by decreases of $1.1 million due to lower earnings on portfolio investments, $4.4 million due to lower earnings from operating facilities, $6.5 million related to the write down of certain thermal assets, $4.7 million related to the internalization of management, $3.5 million related to corporatization costs, $2.1 million resulting from increased minority interest gains at the St. Leon facility primarily due to unrealized gains on financial instruments and $0.2 million due to increased amortization expense as compared to the same period in 2008.

During the three months ended December 31, 2009, cash provided by operating activities totalled $12.5 million or $0.15 per share/trust unit as compared to cash provided by operating activities of $24.8 million, or $0.32 per share/trust unit during the same period in 2008. Cash provided by operating activities exceeded dividends/distributions by 2.4 times during the quarter ended December 31, 2009 as compared to 5.3 times during the same period in 2008. The change in cash provided by operating activities after changes in working capital in the three months ended December 31, 2009, is primarily due to increased realized losses from derivative instruments and decreased cash flow from operating facilities, as compared to the same period in 2008.

APCo’s Renewable Energy division is expected to perform at or below long term average resource conditions in the first quarter of 2010 with the exception of the Quebec and New England regions where APCo anticipates at or above long term average resource conditions. APCo is expecting an improvement in weighted average energy rates at its U.S. renewable facilities as compared to the rates experienced in the first quarter of 2009. The 2010 first quarter results will include results from the acquisition of three hydroelectric generating stations with a capacity of 36.8 MW located in New Brunswick and Maine. The energy produced by these facilities will be shown as the Maritime Region.

APCo Thermal Energy division’s Energy-From-Waste (“EFW”) facility is expected to operate below APCo’s expectations during the first quarter of 2010 due to an unplanned outage in January 2010 related to problems with boiler and economizer tubes. The facility is expected to be operational in spring 2010 once the boiler and economizer tube issues are resolved. APCo is accelerating capital maintenance originally planned for the second and third quarters of 2010 during this outage which should allow the facility to make up some of the income expected to be lost in the first quarter in the remainder of 2010.

APCo Thermal Energy division’s Sanger facility is expected to operate at or above APCo’s expectations for the first quarter of 2010 in line with 2009 results. APCo’s power development team will continue to pursue new opportunities for power generation projects in both Canada and the U.S. APCo will continue to focus on cost containment and productivity improvement measures that will maximize margins and EBITDA throughout 2009.

APCo Thermal Energy division’s Windsor Locks facility is expected to operate at or above APCo’s expectations for the first quarter of 2010 and in line with 2009 results. In the second quarter APCo expects Windsor Locks to perform in line with 2009 results until the power purchase agreement with Connecticut Light & Power (“CL&P”) expires in April 2010 after which APCo expects to be able to sell between 10MW and 40MW of electrical capacity to a local utility or provide ancillary services such as “spinning reserves” to the ISO-NE. For a more detailed description of the options and expected impact see Development Division - Windsor Locks.

Liberty Water has ongoing rate cases at a number of its utilities and will continue to process these rate cases throughout 2010. These rate cases are discussed in further detail within this MD&A (see Liberty Water: Outlook). An exact determination of increased revenues from all rate case applications is not possible at this time as the timing of conclusion to the rate cases and the final decision on rate increases are determined by the regulator. As a result of delays in the progress of rate cases through the regulatory processes, Liberty Water now anticipates that approximately $7 million of additional revenue from rate cases will be achieved in 2010 but the full annualized increase in revenues determined through the rate case processes is expected to be achieved in 2011.

The regulatory reviews of the rates and tariffs for these facilities are expected to conclude in early 2010, with the new rates and tariffs implemented and/or going into effect in the first half of 2010, depending on the state in which the relevant facility operates. The business unit will also continue to consider accretive water and wastewater utility acquisition opportunities, as well as acquisitions in other regulated utilities, such as electricity distribution.

With respect to growth, Liberty Water is expecting limited organic expansion due to the slowdown in the U.S. housing market. Liberty Water expects to deliver growth through the acquisition of an additional small utility system.

As APCo’s hydroelectric generating facilities in the New York and New England regions primarily sell their output at market rates, the average revenue earned per MW-hr sold can vary significantly from the same period in the prior year. APCo’s facilities in the other regions are subject to varying rates, by facility, as set out in each facility’s individual power purchase agreement (“PPA”). As such, while most of APCo’s PPAs include annual rate increases, a change to the weighted average production levels resulting in higher average production from facilities which 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.

For the year ended December 31, 2009 the Renewable Energy division produced 1,041,150 MW-hrs of electricity, as compared to 1,090,600 MW-hrs produced in the same period in 2008, a decrease of 4.5%. The production level

in 2009, while slightly lower than the previous year still represents production levels above long term averages. The production in the twelve months ended December 31, 2009 represents sufficient renewable energy to supply the equivalent of 57,800 homes on an annualized basis with renewable power. Using new standards of thermal generation, as a result of renewable energy production, the equivalent of 575,000 tons of CO2 gas was prevented from entering the atmosphere in 2009.

For the year ended December 31, 2009, the division generated electricity equal to 102% of long term projected average resources (wind and hydrology) as compared to 107% during the same period in 2008. In 2009, a number of regions experienced resources at significantly higher levels than long term average, including the Quebec region which was 8% above long term averages, the New England region, which was 33% above long term averages and the New York region, which was 9% above long term averages. Several regions experienced resources at or below long term averages, including the Western region which was 13% below long term average resources, the Ontario region which was 7% below long term average resources and the Manitoba region which was 2% below long term average resources.

For the year ended December 31, 2009, revenue from energy sales in the Renewable Energy division totalled $68.2 million, as compared to $75.5 million during the same period in 2008. Revenue from APCo’s U.S. facilities decreased $4.0 million due to a decrease in weighted average energy rates of approximately 36% in the New England and New York regions, partially offset by an increase of $0.1 million due to higher than average hydrology, as compared to the same period in 2008. Revenue from APCo’s Canadian hydroelectric facilities decreased $2.2 million due to lower average hydrology, partially offset by an increase of $0.3 million due to an increase in weighted average energy rates of approximately 0.9% and, as compared to the same period in 2008. Revenue from the Manitoba region decreased $0.8 million due to a weaker wind resource and $0.2 million due to a decrease in weighted average energy rates of approximately 0.7%, as compared to the same period in 2008. The division reported an increase in revenue of $0.4 million from U.S. operations as a result of the weaker Canadian dollar as compared to the same period in 2008.

For the year ended December 31, 2009, operating expenses totalled $22.2 million, as compared to $22.0 million during the same period in 2008, an increase of $0.2 million. Operating expenses were impacted by $0.4 million of increased repair and maintenance costs at the St. Leon facility resulting from scheduled payments under the extended warranty and operation and maintenance agreements with Vestas-Canadian Wind Technology Inc. (“Vestas”), increased operational and administrative expenses of $0.3 million, an increase of $0.2 million resulting from increased Canadian property taxes, an increase of $0.2 million resulting from increased repair and maintenance expenses incurred on Canadian facilities, partially offset by decreased variable operating costs of $0.9 million tied to lower revenue associated with U.S. facilities as compared to the same period in 2008. Operating expenses include costs of $2.1 million associated with the pursuit of various growth and development activities, a reduction of $0.2 million as compared to the same period in 2008. The division reported increased expenses of $0.5 million from U.S. operations as a result of the weaker Canadian dollar as compared to the same period in 2008.

For the year ended December 31, 2009, Renewable Energy’s operating profit totalled $47.2 million, as compared to $55.0 million during the same period of 2008, representing a decrease of 14.2%. For the year ended December 31, 2009, Renewable Energy’s operating profit did not meet APCo’s expectations primarily due to lower than expected weighted average energy rates in the U.S.

For the quarter ended December 31, 2009 the Renewable Energy division produced 247,875 MW-hrs of electricity, as compared to 222,700 MW-hrs produced in the same period in 2008, an increase of 11.3%. The level of production in 2009 represents sufficient renewable energy to supply the equivalent of 55,100 homes on an annualized basis with renewable power. Using new standards of thermal generation, as a result of renewable energy production, the equivalent of 138,000 tons of CO2 gas was prevented from entering the atmosphere in the fourth quarter of 2009.

During the quarter ended December 31, 2009, the division generated electricity equal to 93% of long term projected average resources (wind and hydrology) as compared to 105% during the same period in 2008. A number of regions experienced resources at significantly higher levels than long term averages, including the New York region, which was 8% above long term averages and the New England region, which was 16% above long term averages. The Western region experienced results 18% below long term average resources, the Manitoba region experienced results 16% below long term averages, and the Ontario region experienced results 15% below long term averages in the quarter ended December 31, 2009.

For the quarter ended December 31, 2009, revenue from energy sales in the Renewable Energy division totalled $16.6 million, as compared to $19.2 million during the same period in 2008. Revenue from APCo’s U.S. facilities decreased $0.3 million due to a decrease in weighted average energy rates of approximately 17% in the New England region and $0.3 million due to decreased average hydrology, as compared to the same period in 2008. Revenue from the Manitoba region increased $0.1 million due to an increase in weighted average energy rates of approximately 1.3%, offset by a decrease of $1.0 million due to a weaker wind resource, as compared to the same period in 2008. Revenue from APCo’s Canadian facilities decreased $0.7 million due to lower energy production, partially offset by $0.4 million due to an increase in weighted average energy rates as compared to the same period in 2008. The division reported decreased revenue of $0.5 million from U.S. operations as a result of the stronger Canadian dollar as compared to the same period in 2008.

For the quarter ended December 31, 2009, operating expenses totalled $6.6 million, as compared to $6.2 million during the same period in 2008, a decrease of $0.4 million. Operating expenses were impacted by $0.3 million of increased expenses at the St. Leon facility, primarily resulting from scheduled payments under the extended warranty and operation and maintenance agreements with Vestas, increased operational and administrative expenses of $0.2 million, $0.1 million resulting from increased U.S. property taxes, partially offset by decreased variable operating costs of $0.1 million tied to lower revenue associated with U.S. facilities, as compared to the same period in 2008. Operating expenses include costs of $0.9 million associated with the pursuit of various growth and development activities, as compared to $0.8 million in the same period in 2008. The division reported decreased expenses of $0.3 million from U.S. operations as a result of the stronger Canadian dollar as compared to the same period in 2008.

For the quarter ended December 31, 2009, Renewable Energy’s operating profit totalled $10.4 million, as compared to $13.5 million during the same period of 2008, representing a decrease of 23.0%. For the quarter ended December 31, 2009, Renewable Energy’s operating profit did not meet APCo’s expectations primarily due to lower than expected weighted average energy rates in the U.S. and a lower wind resource.

The APCo Renewable Energy division is expected to perform at or below long term average resource conditions in the first quarter of 2010 with the exception of the Quebec and New England regions where APCo anticipates at or above long term average resource conditions.

On January 12, 2010, APCo completed the acquisition of three hydroelectric generating stations located in New Brunswick and Maine with installed capacity of 36.8MW, which include, most notably, the 34.5MW Tinker Hydroelectric station located on the Aroostook River near the Town of Perth-Andover, New Brunswick. The energy produced by these facilities will be shown as the Maritime Region in the first quarter of 2010.

In connection with the Tinker acquisition which closed January 12, 2010, on February 4, 2010, APUC acquired the Energy Services Business which provides energy to commercial and industrial customers in the northern Maine and New Brunswick markets. The Energy Services Business anticipates that, based on the expected load forecast for its existing contracts, it will provide approximately 150,000 MW-hrs of energy to its customers at an average rate of $80/MW-hr on an annualized basis. Based on historical long term average levels of hydroelectric energy generation, the Tinker Assets are anticipated to provide greater than 80% of the energy required by the Energy Services Business to service its customers which provide a natural hedge on supply costs of the Energy Services Business.

In addition to the energy generation provided by the Tinker Assets, the Energy Services Business anticipates buying additional energy on the open market in order to services its customer demand. APCo manages the risk associated with this business through internally generated energy from the Tinker Assets, as well as, through the purchase of fixed volume/prices from the ISO New England market. In addition, APCO negotiates appropriate consumption volumes and pricing indexes with large retail and wholesale consumers in northern Maine to ensure risk associated with volatility of consumption by the consumer is mitigated.

As a result of certain legislation passed in Quebec (Bill C93), APCo’s Renewable Energy division is required to undertake technical assessments of eleven of the twelve hydroelectric facility dams owned or leased within the Province of Quebec. In the first quarter of 2010 APCo expects to complete the required assessments necessary to determine the work required and estimate capital cost of compliance with the legislation. APCo is required to submit plans for undertaking any remedial measures that are identified to comply with the legislation. As a result of nine completed and two partially completed assessments, APCo has estimated capital expenditures of approximately $17.5 million related to compliance with the legislation. The timing of when the actual capital costs need to be made is determined as part of the technical assessments.

APCo anticipates that these expenditures will be invested over the next five years as follows:

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

In 2009, the EFW facility processed 161,102 tonnes of municipal solid waste as compared to 161,198 tonnes processed in the same period of 2008. This level of production resulted in the diversion of approximately 43,500 tonnes of waste from landfill sites in 2009.

During the twelve months ended December 31, 2009, the business unit produced 571,505 MW-hrs of energy as compared to 597,923 MW-hrs of energy in the comparable period of 2008, a decrease of 4.4%. The business unit’s performance decreased by 4,300 MW-hrs at the Sanger facility resulting from power curtailment by Pacific Gas and Electric Company (“PG&E”) due to line loading issues on the utility side and 7,500 MW-hrs at the Windsor Locks facility due to reduced demand for steam from its steam host customer, as compared to the same period in 2008. The overall decrease in energy production at the EFW facility is due to steam generated by the incineration process at the facility now being utilized by BCI for steam sales to a nearby industrial customer rather than being used to generate electricity. During the twelve months ended December 31, 2009, the business unit’s BCI steam sales facility was operating for the full period having reached commercial operation in June 2008. Although this has resulted in the decrease in electrical generation from EFW’s steam turbine of 16,300 MW-hrs, the decrease was more than offset by the new steam sales by BCI. Throughput at the EFW facility remained consistent with the same period in 2008.

For the year ended December 31, 2009, gross revenue in the Thermal Energy division totalled $80.5 million, as compared to $103.0 million during the same period in 2008, a decrease of $22.5 million. As natural gas expense is a significant revenue driver and component of operating expenses, the division compares ‘net energy sales revenue’ (energy sales revenue less natural gas expense) as a more appropriate measure of the division’s results. During the year ended December 31, 2009, net energy sales revenue at the Thermal Energy division totalled $35.7 million, as compared to $38.3 million during the same period in 2008, a decrease of $2.6 million. The decrease in revenue from net energy sales, as compared to the first twelve months of 2008, was primarily due to the Sanger facility experiencing a decrease of $5.6 million as a result of decreased energy rates, in part due to lower natural gas prices, and $0.7 million as a result of decreased production and decreased revenue at the Windsor Locks facility of $16.1 million as a result of lower energy rates, in part due to lower natural gas prices, and $0.9 million as a result of decreased demand for steam production as compared to the same period in 2008. The offsetting reduction in natural gas expense at the Sanger and Windsor Locks facilities is discussed in detail below. In addition, revenue decreased $1.1 million at the landfill-gas (“LFG”) facilities primarily as a result of lower energy rates and $1.0 million at the EFW facility as a result of a portion of the steam generated by the incineration process being used by BCI instead of being used to generate electricity. These decreases were partially offset by an increase of $2.5 million as a result of the BCI steam sales facility achieving commercial operation in June 2008, as compared to the same period in 2008. The division reported increased revenue of $2.2 million from operations as a result of the weaker Canadian dollar, as compared to the same period in 2008.

Revenue from waste disposal sales for the year ended December 31, 2009 totalled $14.5 million, as compared to $15.7 million during the same period in 2008, a decrease of $1.2 million. The facility earned lower average rates for each tonne of waste processed in the quarter, primarily the result of the arrangement to process higher priced airline waste at the facility ceasing in December 2008.

For the year ended December 31, 2009, fuel costs at Sanger and Windsor Locks totalled $26.5 million, as compared to $44.7 million during the same period in 2008, a decrease of $18.2 million. Natural gas expense at Sanger decreased $4.9 million (52%), primarily the result of a 50% decrease in the average price for natural gas as compared to the same period in 2008. In addition, production decreased 3%, primarily as a result of production curtailments by PG&E, decreasing the volume of natural gas used in ongoing operation of the facility as compared to the same period in 2008. Natural gas expense at the Windsor Locks facility decreased $14.2 million (44%), primarily the result of a 44% decrease in the average price for natural gas as compared to the same period in 2008. The division reported increased fuel costs of $0.9 million as a result of the weaker Canadian dollar as compared to the same period in 2008.

For the year ended December 31, 2009, operating expenses, excluding fuel costs at Windsor Locks and Sanger, totalled $30.8 million, as compared to $32.5 million in the same period in 2008. Operating expenses for the period were impacted by decreased operating expenses of $0.6 million at the EFW facility primarily as a result of lower

natural gas expenses and repair and maintenance expenses, $0.5 million at the hydro-mulch facility primarily resulting from reduced repair and maintenance costs and $0.5 million primarily due to decreased repair and maintenance costs at the Valley Power facility, as compared to the prior period. Expenses at the LFG facilities decreased $2.2 million due to lower operating, royalty, repair, maintenance and natural gas expenses as compared to the same period in 2008. In 2008 expenses at the LFG facilities included $0.6 million of costs associated with its investment in the landfill gas tax credit program which did not occur in 2009. These decreases were partially offset by increased expenses at the Windsor Locks facility primarily due to $0.4 million in costs associated with compliance with the greenhouse gas initiatives and $0.7 million of operating costs of the BCI steam facility as compared to the same period in 2008. The reported operating costs at the BCI facility exclude the cost of purchasing steam from the EFW facility as this is eliminated upon consolidation. The division reported increased operating expenses of $0.7 million from U.S. operations as a result of the weaker Canadian dollar as compared to the same period in 2008.

For the year ended December 31, 2009, the Thermal Energy division’s operating profit totalled $27.0 million, as compared to $31.1 million during the same period in 2008, a decrease of $4.1 million or 13.1%. Operating profit in the Thermal Energy division did not meet overall expectations for 2009, due to weaker gas prices and lower demand for steam from the division’s co-generation assets resulting from the current economic slow down in the U.S.

In the fourth quarter of 2009, the EFW facility processed 42,189 tonnes of municipal solid waste as compared to 42,348 tonnes processed in the same period of 2008, a decrease of 0.4%. This level of production resulted in the diversion of approximately 11,500 tonnes of waste from landfill sites in the fourth quarter of 2009.

During the quarter ended December 31, 2009, the business unit produced 147,482 MW-hrs of energy as compared to 145,050 MW-hrs of energy in the comparable period of 2008. During the quarter ended December 31, 2009, the business unit’s performance increased by 700 MW-hrs at the Windsor Locks facility, 2,100 MW-hrs at the Sanger facility and 1,500 MW-hrs at the Valley Power facility as compared to the same period in 2008. During the quarter ended December 31, 2009, the BCI steam facility used more EFW steam in its operations, resulting in a decrease in electrical generation from EFW’s steam turbine of 1,000 MW-hrs. Throughput at the EFW facility was consistent with the same period in 2008.

For the quarter ended December 31, 2009, revenue in the Thermal Energy division totalled $18.2 million, as compared to $27.5 million during the same period in 2008, a decrease of $9.3 million. As natural gas expense is a significant revenue driver and component of operating expenses, the division compares ‘net energy sales revenue’ (energy sales revenue less natural gas expense) as a more appropriate measure of the division’s results. For the quarter ended December 31, 2009, net energy sales revenue at the Thermal Energy division totalled $8.6 million, as compared to $10.2 million during the same period in 2008, a decrease of $1.6 million. The decrease in revenue from energy sales was primarily due to a decrease of $0.7 million at the Sanger facility as a result of decreased energy rates, in part due to lower natural gas prices, partially offset by $0.3 million as a result of increased production, and a decrease of $4.8 million at the Windsor Locks facility as a result of decreased energy rates, in part due to lower natural gas prices, partially offset by $0.1 million as a result of increased demand for steam production, as compared to the same period in 2008. The offsetting reduction in natural gas expense at the Sanger and Windsor Locks facilities is discussed in detail below. The division reported decreased revenue of $2.7 million from operations as a result of the stronger Canadian dollar, as compared to the same period of 2008.

Revenue from waste disposal sales for the quarter ended December 31, 2009 totalled $3.8 million, as compared to $3.9 million during the same period in 2008. The facility earned lower average rates for each tonne of waste processed in the quarter, primarily the result of the arrangement to process higher priced airline waste at the facility ceasing in December 2008.

For the quarter ended December 31, 2009, fuel costs at Sanger and Windsor Locks totalled $5.2 million, as compared to $11.6 million during the same period in 2008, a decrease of $6.4 million. Natural gas expense at Sanger decreased $0.3 million (18%), primarily the result of a 22% decrease in the average price for natural gas as

compared to the same period in 2008. Natural gas expense at the Windsor Locks facility decreased $4.4 million (55%), primarily the result of a 56% decrease in the average price for natural gas as compared to the same period in 2008. The division reported decreased fuel costs of $1.7 million as a result of the stronger Canadian dollar as compared to the same period in 2008.

For the quarter ended December 31, 2009, operating expenses, excluding fuel costs at Windsor Locks and Sanger, totalled $7.1 million, as compared to $8.8 million during the same period in 2008, a decrease of $1.7 million. The decrease in operating expenses for the quarter was primarily due to reduced operating costs of $0.5 million at the LFG facilities resulting from lower repair, maintenance, royalty and operating expenses, $0.2 million at BCI resulting from lower natural gas expenses and $0.3 million in lower consumables and repair and maintenance expenses at the hydro-mulch facility as compared to the same period in 2008. The division reported decreased operating expenses of $0.6 million from U.S. operations as a result of the stronger Canadian dollar as compared to the same period in 2008.

For the quarter ended December 31, 2009, the Thermal Energy division’s operating profit totalled $6.7 million, as compared to $7.7 million during the same period in 2008, representing a decrease of 13.0%. Operating profit in the Thermal Energy division did not meet overall expectations for the quarter ended December 31, 2009, due to weaker gas prices and lower demand for steam from the Division’s co-generation assets resulting from the current economic slow down in the U.S.

The EFW facility is expected to operate below expectations during the first quarter of 2010 due to an unplanned outage in late January 2010 due to a failure with boiler and economizer tubes, some of which were scheduled for replacement as part of the current year capital expenditure plan. APCo intends to accelerate this replacement and simultaneously advance capital maintenance originally planned for the second and third quarters of 2010 during the outage which should allow the facility to make up some of the income expected to be lost in the first quarter in the remainder of 2010. APCo estimates the outage will negatively impact operating profit from EFW in 2010 by approximately $1.2 million compared to its operating profit in 2009.

The Thermal Energy division’s Sanger facility is expected to operate at or above expectations for the first quarter of 2010 in line with 2009 results.

Windsor Locks is expected to operate at or above APCo’s expectations for the first quarter of 2010 and in line with 2009 results. In the second quarter APCo expects Windsor Locks to perform in line with 2009 results until the power purchase agreement with Connecticut Light & Power (“CL&P”) expires in April 2010 after which APCo expects to be able to sell between 10MW and 40MW of electrical capacity to a local utility or provide ancillary services such as “spinning reserves” to the ISO-NE. For a more detailed description of the options and expected impact see Development Division - Windsor Locks.

The Development division works to identify, develop and construct new, renewable and efficient energy generating facilities, as well as to identify, develop and construct other accretive projects that maximize the potential of APCo’s existing facilities. Development is focused on projects within North America with a commitment to working proactively with all stakeholders, including local communities. The Development division is led by five full time employees who have access to, and support from, all of APCo’s available resources to assist it in the development of projects. Typically, the division draws upon the support of the finance, engineering, technical services, and environmental and regulatory compliance groups. It also utilizes existing industry relationships to assist in the identification, evaluation, development and construction of projects, and retains expertise, as required, from the financial, legal, engineering, technical, and construction sectors.

The Development division may also create opportunities through the acquisition of operating assets with accretive characteristics and prospective projects that are at various stages of development. The Development division

believes that the prevailing economic climate has also created opportunities for APCo to acquire third party development projects on terms that require the experience and financial resources that APCo has at its disposal. The strategy is to focus on high quality renewable and high efficiency thermal energy generation projects that benefit from low operating costs using proven technology that can generate sustainable and increasing cash flows in order to achieve a high return on invested capital.

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

APCo continues to advance the Red Lily Wind Project in south-eastern Saskatchewan (the “Project” or “Red Lily”). In July 2008, a 25 MW PPA for the first phase of the Project (“Phase I”) was executed with SaskPower after Phase I was successfully bid into a SaskPower Environmentally Preferred Power Strategy Request for Proposal. In June 2009, APCo and Natural Resources Canada (“NRC”) executed a Contribution Agreement under the ecoENERGY for Renewable Power Program for Phase I, securing funding for the project in advance of the expectation of the program being fully subscribed later in 2009. APCo has submitted to NRC the Environmental Impact Assessment documentation for review in relation to obtaining funding under the federal ecoENERGY program and is following up with NRC, as the lead agency, on comments received from other agencies. Notably, on April 13, 2009 Saskatchewan Environmental Assessment Branch confirmed that APCo had satisfied the requirements under the Provincial Environmental Assessment Act for Phase I. APCo is currently awaiting confirmation of a development permit from the regional municipality of Martin.

APCo is considering a number of financing alternatives for Red Lily. Currently, the most likely alternative will see the Project financed through an equity injection from a third party together with APCo’s participation arising in the Project solely through a subordinated debt commitment of up to $19.0 million. APCo would retain responsibility and receive fees in respect of the development, construction, operation and supervision of the Project. After 5 years, APCo would have an option to subscribe for a 75% equity interest in the Project in exchange for its subordinated debt commitment.

On behalf of Red Lily, APCo is in the process of finalizing the contracts necessary to construct the project and has executed term sheets to secure all of the required financing, with the anticipation that the funding will be available in the first quarter of 2010. The earliest expected commissioning date of the project is December 31, 2011. In addition to the focused effort on Phase I, APCo has secured additional property and is assessing the viability of an expanded project. The viability of the expanded project will be conditional upon actual operating results from Phase I.

Successful development of wind projects such as Red Lily are subject to significant risks and uncertainties including the ability to obtain financing on acceptable terms within deadlines imposed by the utility, reaching agreement with any other external parties involved in the project, currency fluctuations affecting the cost of major capital components such as wind turbines, price escalation for construction labour and other construction inputs and construction risk that the project is built without mechanical defects and is completed on time and within budget estimates. Assuming the Project is developed, it is currently estimated to require 16 turbines with a capital investment of approximately $65 million. Annual energy production from the wind farm is estimated to be 88,100 MW-hrs and annual gross revenue is estimated to be $8.5 million.

The Windsor Locks facility is a 54MW natural gas power generating station located in Windsor Locks, Connecticut. The facility was acquired in 2003 and currently has an outstanding net book value to APCo of approximately US$17.2 million. The facility has two key energy agreements. The first agreement is the PPA with CL&P which expires in April 2010. The second agreement is the Energy Services Agreement (“ESA”) with Ahlstrom Windsor Locks, LLC (“Ahlstrom”), a leading paper and non woven materials manufacturer, which, if not further extended by mutual agreement, will continue until 2017. The expiration of the CL&P PPA will impact operations beyond April 2010.

Commencing in April 2010, APCo will maximize net revenue by serving the steam and power requirements of Ahlstrom pursuant to the ESA together with bidding the remaining available capacity of approximately 40 MW into the thirty minute forward operating reserve market (“TMOR”). APCo has entered into an agreement with Emera Energy Services Inc. to manage the off-take sales from this facility into the Independent System Operator New England (“ISO-NE”) market.

APCo is continuing the preliminary engineering and environmental permitting work for the installation of a new combustion gas turbine more appropriately sized to meet the electrical and steam requirements of Ahlstrom. APCo believes it is eligible to receive a one-time non-recurring grant from the State of Connecticut equivalent to US $450/KW to a maximum of US $6.6 million to offset the cost of such re-powering. In addition to installing the new gas turbine, APCo would expect to continue to operate and maintain the existing equipment. Any investment in new capital for this site will be based on an assessment of the incremental earnings against such additional investment.

The Development division currently anticipates operating cash flow at the Windsor Locks facility for 2010 to be approximately U.S. $4.5 million compared to a historical cash flow of approximately U.S. $8.0 million. This operating cash flow estimate assumes participation in the summer 2010 and the winter 2010/2011 forward reserve auctions. TMOR has cleared at US $14 per MW month for the last 7 forward reserve procurement periods (two periods annually). During 2010, it is expected that APCo will earn revenue from steam and electrical sales to Ahlstrom, steam and electrical capacity payments made by Ahlstrom, energy sales to ISO-NE, capacity payments made by ISO-NE and TMOR payments made by ISO-NE. Under this operating protocol APCo will need to acquire 750,000MMBTU to 835,000MMBTU of natural gas annually in addition to the natural gas purchases reimbursed by Ahlstrom.

APCo has completed preliminary engineering and a financial feasibility analysis on a 12 MW combined cycle high efficiency thermal energy generation project located in Ontario. APCo believes this project is an excellent fit for the Minister of Energy and Infrastructure’s Directive to procure electricity from combined heat and power 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 having a potential generation capacity of over 250 MW, hydroelectric projects at different stages of investigation, and thermal energy generation projects. The projects being examined are located both in Canada and the United States.

In addition to the second phase of the Red Lily project, APCo is currently collecting wind data on three other sites in Saskatchewan and expects to respond to the Provinces’ Request for Qualifications to procure up to 175MW of wind power from one or more independent power producers.

APCo owns the rights, including land options, meteorological towers and historical wind data related to a potential 80 MW Canadian wind project. In the event the project is developed, it is currently estimated to require an investment of up to $250 million and is expected to require 2 to 3 years to complete.

In 2008, APCo made a strategic decision to maintain land option agreements for two wind projects in Quebec in anticipation of future provincial tenders. In May 2009, Hydro Quebec released details in relation to a tender request for wind projects of a 25 MW maximum size. In addition, APCo has developed a relationship with two development co-operatives comprised of landowners and other small investors for the potential development of a third and fourth project in response to the expected call for tender. Algonquin will assess the economics of these projects individually and will bid into the RFP accordingly.

Discussions with the Ontario Power Authority indicate that energy procurement initiatives will be positively influenced by the Green Energy Act (“GEA”) which received Royal Assent on May 14, 2009. 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 Ontario Power Authority in accordance with the GEA. In addition, APCo has applied to become applicant of record for three crown land sites under the Ministry of Natural Resources wind power site release programme, and has recently submitted 42 MW of on-shore wind energy projects in eastern Ontario under the GEA’s Feed-in Tariff program (“FIT”). The on-shore wind price set by the FIT program is $0.135 per kWH.

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.

The following sets out a summary of potential development projects at existing facilities which are being examined by the Development division.

The St. Leon Wind Project achieved commercial operation status under its PPA with the Manitoba Hydro Electric Board in June 2006, and has been performing at or above expected levels of production. APCo is exploring multiple options to continue to build on the success of this project 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.

The EFW facility in the Thermal Energy division of APCo is designed to incinerate over 500 tonnes per day of municipal solid waste from the Region of Peel to produce steam that is used in the production of electricity and to supply the internal steam load for a nearby recycled paper board manufacturing mill. APCo established BCI to operate the required facilities to supply steam to the nearby paper board customer and pursue additional steam load customers.

The Development division is currently reviewing several proposals at the EFW facility to expand its power generation and waste processing throughput capacity. Throughput capacity could be expanded by between 40,000 and 100,000 tonnes annually depending on the proposal that is selected. If the expansion is pursued, depending on the alternative chosen, an investment of between $60 million to $250 million would be required. APCo is currently evaluating the feasibility of an expanded facility including associated capital and operating costs and financing terms. APCo is also engaged in discussions with the Region of Peel to establish a new long term contract for a reliable supply of municipal solid waste.

APCo believes that future opportunities for power generation projects will continue to arise given that many jurisdictions, both in Canada and the United States, continue to increase targets for renewable and other clean power generation projects. In the past year the Ontario government passed the Green Energy Act. Accordingly the Ontario Power Authority has issued standard pricing for electricity from renewable sources under a Feed-in Tariff. Included within this legislation is the requirement for Ontario Power Authority to purchase power generated from green energy projects, and an obligation for all utilities to grant priority grid access to such projects. The intention of the legislation is to make development of renewable energy projects significantly easier than the prior process of formal bids in response to requests for proposals from the responsible power authority.

In 2009, Utility Services branded all of its utilities under the Liberty Water brand. Liberty Water is committed to being the 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 reports total connections, inclusive of vacant connections rather than customers. Liberty Water had 34,441 wastewater connections as at December 31, 2009, as compared to 34,190 as at December 31, 2008, an increase of 251 year over year or 0.7%. Liberty Water had 36,919 water distribution connections as at December 31, 2009, as compared to 36,297 as at December 31, 2008, representing a year over year increase of 622 or 1.7%. Total connections include approximately 2,025 vacant wastewater connections and 1,475 vacant water distributions connections. Liberty Water’s marginal change in water distribution and wastewater treatment customer base during the period continues to primarily relate to limited organic growth at Liberty Water’s facilities resulting from the slow down in U.S. new residential home sales in areas served by the division.

Liberty Water has investments in regulatory assets of U.S. $147.8 million across four States as at December 31, 2009, as compared to U.S. $149.3 million as at December 31, 2008 and has active proceedings in Texas and Arizona to allow it to earn its full regulatory return on its investment in regulatory assets.

During the twelve months ended December 31, 2009, Liberty Water provided approximately 5.9 billion U.S. gallons of water to its customers, treated approximately 1.9 billion U.S. gallons of waste-water and sold approximately 475 million U.S. gallons of treated effluent.

For the year ended December 31, 2009, Liberty Water’s revenue totalled $38.5 million as compared to $35.2 million during the same period in 2008, an increase of $3.3 million. Revenue from wastewater treatment totalled $20.8 million, as compared to $19.1 million during the same period in 2008, an increase of $1.7 million. Revenue from water distribution totalled $17.2 million, as compared to $15.6 million during the same period in 2008, an increase of $1.6 million. Liberty Water reported increased revenue from operations of $2.7 million in the year ended December 31, 2009 as a result of the weaker Canadian dollar as compared to the same period in 2008. Excluding the impact of foreign exchange, revenue increased U.S. $0.6 million or 1.8% as compared to the same period in 2008.

The twelve month water distribution revenue was impacted by increased revenue of $0.2 million at the four Texas Silverleaf facilities primarily due to the ongoing rate cases and the related implementation of interim rate increases, in conjunction with increased customer demand and limited organic growth, $0.2 million at the Litchfield Park facility (“LPSCo”) primarily due to higher commercial water sales, and $0.2 million due to organic growth and increased customer demand at 9 water distribution facilities as compared to the same period in 2008. Liberty Water reported increased water distribution revenue of $1.2 million in the twelve months ended December 31, 2009 as a result of the weaker Canadian dollar as compared to the same period in 2008.

The twelve month wastewater treatment revenue was impacted by increased revenue of $0.4 million at the four Texas Silverleaf facilities and the Tall Timbers facility, primarily due to the ongoing rate cases and the related implementation of interim rate increases in conjunction with increased customer demand and limited organic growth, $0.4 million at LPSCo primarily due to higher treated effluent revenue as compared to the same period in 2008. These increases were partially offset by decreased wastewater treatment revenue of $0.4 million primarily resulting from a regulator imposed reduction in rates at the Gold Canyon facility and a decrease of $0.1 million due to decreased demand at the Rio Rico facility as compared to the same period in 2008. Liberty Water reported increased wastewater treatment revenue of $1.4 million in the twelve months ended December 31, 2009 as a result of the weaker Canadian dollar as compared to the same period in 2008.

For the year ended December 31, 2009, operating expenses totalled $23.2 million, as compared to $21.2 million during the same period in 2008. Liberty Water reported higher expenses from operations of $1.7 million as a result of the weaker Canadian dollar, as compared to the same period in 2008. Excluding the impact of foreign exchange, overall expenses increased U.S. $0.5 million or 2.3% as compared to the same period in 2008.

Operating expenses increased $0.6 million as a result of increased wages, salary and other operating costs, $0.3 million in reduced contracted service expenses, $0.2 million in reduced transportation costs, $0.2 million in reduced utilities and consumables and $0.2 million in decreased repair and maintenance costs as compared to the same period in 2008.

For the year ended December 31, 2009, Liberty Water earned other income of $1.4 million on the disposition of non-utility assets with a book value of $1.1 million. During the comparable period in 2008, Liberty Water did not dispose of any significant other assets.

For the year ended December 31, 2009, Liberty Water’s operating profit totalled $16.7 million as compared to $14.1 million during the same period in 2008. Excluding the gain on disposition of other assets, operating profits increased by 9.0%. Liberty Water’ operating profit exceeded expectations for the year ended December 31, 2009.

During the quarter ended December 31, 2009, Liberty Water provided approximately 1.4 billion U.S. gallons of water to its customers, treated approximately 500 million U.S. gallons of wastewater and sold approximately 100 million U.S. gallons of treated effluent.

For the quarter ended December 31, 2009, Liberty Water’s revenue totalled $8.7 million as compared to $9.8 million during the same period in 2008, a decrease of $1.1 million. Revenue from wastewater treatment totalled $4.9 million, as compared to $5.4 million during the same period in 2008, a decrease of $0.5 million. Revenue from water distribution totalled $3.7 million, as compared to $4.3 million during the same period in 2008, a decrease of $0.6 million. Liberty Water reported decreased revenue from operations of $1.2 million in the fourth quarter of 2009 as a result of the stronger Canadian dollar as compared to the same period in 2008. Excluding the impact of foreign exchange, revenue was consistent with the same period in 2008.

The fourth quarter water distribution revenue was impacted by increased revenue of $0.1 million at the four Texas Silverleaf facilities primarily due to the ongoing rate cases and the related implementation of interim rate increases, offset by a decrease of $0.1 million at the Litchfield Park facility (“LPSCo”) primarily due to lower commercial water sales and $0.1 million due to lower customer demand at 4 water distribution facilities as compared to the same period in 2008. Liberty Water reported decreased water distribution revenue of $0.5 million in the quarter ended December 31, 2009 as a result of the stronger Canadian dollar as compared to the same period in 2008.

The fourth quarter wastewater treatment revenue was impacted by increased revenue of $0.3 million at the four Texas Silverleaf facilities and the Tall Timbers facility, primarily due to the ongoing rate cases and the related implementation of interim rate increases, $0.1 million at LPSCo primarily due to higher treated effluent revenue as compared to the same period in 2008. These increases were partially offset by decreased wastewater treatment revenue $0.1 million primarily resulting from a regulator imposed reduction in rates at the Gold Canyon facility and $0.1 million due to lower customer demand at the Rio Rico facility as compared to the same period in 2008. Liberty Water reported decreased wastewater treatment revenue of $0.7 million in the twelve months ended December 31, 2009 as a result of the stronger Canadian dollar as compared to the same period in 2008.

For the quarter ended December 31, 2009, operating expenses totalled $5.0 million, as compared to $6.0 million during the same period in 2008. Liberty Water reported lower expenses from operations of $0.8 million as a result of the stronger Canadian dollar, as compared to the same period in 2008. Excluding the impact of foreign exchange, overall expenses decreased U.S. $0.3 million or 5.5% as compared to the same period in 2008.

Operating expenses decreased $0.1 million in reduced contracted services expenses, $0.1 million in reduced utilities and consumables expenses and $0.6 million as a result of the capitalization of rate case costs of multiple rate cases which were previously expensed due to the adoption of rate regulated accounting during the quarter, partially offset by an increase of $0.4 million as a result of increased wages, salary and other operating costs as compared to the same period in 2008.

For the quarter ended December 31, 2009, Liberty Water’s operating profit totalled $3.7 million, comparable to the same period in 2008. Liberty Water’s operating profit exceeded expectations for the three months ended December 31, 2009.

Notwithstanding the slowdown in the U.S. economy, Liberty Water is not expecting any material reduction in customers in fiscal 2010. Liberty Water continues to provide water distribution and wastewater collection and treatment services, primarily in the southern and southwestern U.S., in communities that have traditionally experienced long term growth and that provide continuing future opportunities for organic growth.

Liberty Water is proceeding through the regulatory process with rate cases relating to a number of its facilities. The Black Mountain facility filed a rate case in December 2008 using a June 30, 2008 test year. The LPSCo facility filed a rate case in March 2009 using a September 2008 test year. The Rio Rico facility filed a rate case in May 2009, using a test year ended December 31, 2008. The Bella Vista, Northern Sunrise and Southern Sunrise

facilities filed rate cases in August 2009 using a March 31, 2009 test year. All of these facilities are located in Arizona. Five Texas facilities filed rate cases in April 2009, and Woodmark in Texas filed in July 2009, all with test years ended December 31, 2008.

The following table sets out some particulars with respect to the status of the rate cases as at February 15, 2010:

Rate cases ensure that a particular facility has the opportunity to recover its operating costs and earn a fair and reasonable return on its capital investment as allowed by the regulatory authority under which the facility operates. Liberty Water monitors current and anticipated operating costs, capital investment and the rates of return in respect of each of its facility investments to determine the appropriate timing of a rate case filing in order to ensure it fully earns a rate of return on its investments.

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

In July 2009, Tall Timbers implemented interim rates to customers in a portion of its service area as applied for in its rate case application. The interim rates are being contested by various homeowner associations in Tall Timbers service area affected by the increase. These rates are expected to be finalized before the end of 2010 as part of the normal regulatory process administered by the TCEQ.

In October 2009, the Texas Silverleaf utility began charging interim rates based on its rate case applications. The interim rates are being contested by greater than 10% of the customers in the service area. These rates are expected to be finalized before the end of 2010 as part of the normal regulatory process administered by the TCEQ.

In Arizona, the Arizona Corporate Commission requires a full regulatory process for all rate cases using a historic test year. It is anticipated that the regulatory review of the proposed rates and tariffs for the Arizona facilities would be completed by mid-2010, with the new rates and tariffs in Arizona going into effect throughout 2010.

An exact determination of increased revenues from all rate case applications is not possible at this time as the timing of conclusion to the rate cases and the final decision on rate increases are determined by the regulator. As a result of delays in the progress of rate cases through the regulatory processes, Liberty Water now anticipates that approximately $7 million of additional revenue from rate cases will be achieved in 2010 but the full annualized increase in revenues determined through the rate case processes is expected to be achieved in 2011.

During the year ended December 31, 2009, administrative expenses totalled $10.7 million as compared to $9.4 million in the same period in 2008. The expense increase in the twelve months ended December 31, 2009 was primarily due to increased costs associated with additional staff added requirements to administer APUC’s operations as compared to the same period in 2008.

In December 2009, APCo decided to dispose of its investments in its remaining LFG facilities and its 50% ownership in the Drayton Valley facility. APCo tested its investments for recoverability using a net realizable value valuation technique. As a result, Algonquin determined that these assets were impaired as at December 31, 2009. Accordingly, for the year ended December 31, 2009, APCo recognized an impairment charge of $1.1 million against the outstanding principal balance of a note receivable related to its LFG operations. APUC also wrote down the carrying value of its remaining LFG facilities and its 50% investment in the Valley Power facility to their estimated current fair value. This resulted in a write down of property and equipment of $4,854 in the period representing the difference between the carrying value of the assets and their net realizable values. Both of these assets are currently reported under the Algonquin Power – Thermal Division reporting segment. These assets generated gross revenues of $4.3 million in 2009.

For the year ended December 31, 2009, APUC recorded an expense of $4.7 million with regards to an agreement to acquire the Manager’s interest in the management services agreement and internalize management as compared to nil in the same period in 2008. On December 21, 2009, APUC’s Board ratified an agreement in principal with the shareholders of APMI to acquire the management contract and internalize management. Senior management expenses will be recorded within the Administrative Expense category on a go forward basis (See – Major highlights in 2009 – Management Internalization).

During the year ended December 31, 2009, APUC recorded an expense of $3.5 million associated with costs of converting the Fund to a corporation as compared to nil in the same period in 2008. The expense in the twelve months ended December 31, 2009 primarily consists of $1.5 million related to professional fees associated with the unit exchange transaction completed on October 27, 2009, increased capital taxes of $0.8 million as a result of the conversion to a corporation and an expense of $1.3 million associated with the exchange of the Series 1 Debentures for Series 1A Debentures (See – Shareholders Equity and Convertible Debentures).

Foreign exchange gains and losses primarily represent unrealized gains or losses on U.S. dollar denominated debt and do not impact APUC’s current cash position. For purposes of evaluating divisional performance, APUC does not allocate the foreign exchange gains or losses to specific divisions as the change does not impact APUC’s current cash position or cash generated from operations. For the year ended December 31, 2009, APUC reported a foreign exchange gain of $1.3 million as compared to a loss of $4.0 million during the same period in 2008. The twelve months ended December 31, 2009 experienced a decrease in value of the U.S. dollar of 15% which resulted in unrealized gains on APUC’s U.S. denominated debt and working capital balances from its integrated U.S. operating facilities. The comparable period in 2008 experienced an increase in the value of the U.S. dollar of 22%, which resulted in unrealized losses on APUC’s U.S. denominated debt. As at December 31, 2009, APUC had approximately $32.5 million in U.S. dollar denominated debt.

For the year ended December 31, 2009, interest expense totalled $21.4 million as compared to $26.3 million in the same period in 2008. Decreased interest expense was primarily related to lower interest rates charged on APUC’s variable interest rate credit facilities and lower average borrowings, as compared to the prior year.

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

On October 27, 2009, as a result of the Unit Exchange Offer, the Fund converted from a publicly traded income trust to a publicly traded corporation (see “Major Highlights in 2009—Conversion to a Corporation”). APUC’s calculation of current and future income taxes for the year ended December 31, 2009 is based on the conversion to a corporate structure effective October 27, 2009, whereas APUC’s calculation of current and future income taxes for the year ended December 31, 2008 is based on APUC being a publicly traded income trust. An income tax recovery of $17.9 million was recorded in 2009, as compared to an expense of $0.3 million during the same period in 2008. The primary reasons for this recovery relates to the conversion to a corporation from an income trust, decreases in expected future income tax rates, tax losses on U.S. operations resulting from bonus depreciation and lower energy and natural gas prices as compared to the same period in 2008 and the recovery of non-deductible interest expense related to U.S. operations, partially offset by additional future income tax liabilities resulting from the temporary differences in tax expenses related to CD and unit exchange issue costs and the reversal in the current year of unrealized losses on derivative financial instruments booked in the prior fiscal year. This resulted in an increased future tax recovery recorded in the twelve months ended December 31, 2009. (see Risk Management – Changes to income tax laws).

During the quarter ended December 31, 2009, administrative expenses totalled $2.5 million, as compared to $2.8 million in the same period in 2008. The expense increase in the three months ended December 31, 2009 primarily relates to added requirements to administer APUC’s operations as compared to the same period in 2008.

In December 2009, APCo decided to exit its underperforming investments LFG facilities and Valley Power. See the discussion in the annual corporate results section, above, for details related to this expense.

For the quarter ended December 31, 2009, APUC recorded an expense of $4.7 million with regards to an agreement to acquire the Manager’s interest in the management contract and internalize management as compared to nil in the same period in 2008. See the discussion in the annual corporate results section and ‘Major highlights in 2009 – Management Internalization’, above, for details related to this expense.

During the quarter ended December 31, 2009, APUC recorded an expense of $3.5 million associated with costs of converting the Fund to a corporation as compared to nil in the same period in 2008. The expense is discussed in more detail in the annual corporate results section, above.

Foreign exchange gains and losses primarily represent unrealized gains or losses on U.S. dollar denominated debt and do not impact current cash position. For purposes of evaluating divisional performance, APUC does not allocate the foreign exchange gains or losses to specific divisions as the change does not impact APUC’s current cash position or cash generated from operations. For the three months ended December 31, 2009, APUC reported a foreign exchange gain of $0.3 million as compared to a loss of $2.3 during the same period in 2008. The three months ended December 31, 2009 experienced a decrease in value of the U.S. dollar of 2% which resulted in unrealized losses on APUC’s U.S. denominated debt and working capital balances from its integrated U.S. operating facilities. The comparable period in 2008 experienced an increase in the value of the U.S. dollar of 16%, which resulted in unrealized losses on APUC’s U.S. denominated debt.

For the quarter ended December 31, 2009, interest expense totalled $5.6 million as compared to $5.7 million in the same period in 2008. Decreased interest expense was related to lower interest rates charged on APUC’s variable interest rate credit facilities and lower average borrowings, as compared to the prior year.

Loss on derivative financial instruments consists of realized and unrealized mark to market losses on foreign exchange forward contracts and interest rate swaps 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 $10.7 million was recorded in the three months ended December 31, 2009, as compared to a recovery of $4.4 million during the same period in 2008. The primary reasons for this recovery are discussed in the annual income tax expense section above (see Risk Management – Changes to income tax laws).

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 derived from a number of non-operating factors, accounting methods and assumptions. APUC believes that presentation of this measure will enhance an investor’s understanding of APUC’s operating performance. Adjusted EBITDA is not intended to be representative of cash provided by operating activities or results of operations determined in accordance with GAAP.

The following table is derived from and should be read in conjunction with the 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.

For the quarter ended December 31, 2009, Adjusted EBITDA decreased by $5.2 million compared to the same period in 2008. The decrease in Adjusted EBITDA in the quarter ended December 31, 2009 is primarily due to $4.4 million in lower earnings from operations and $1.1 million in decreased interest, dividend and other income earned in the year as compared to the previous quarter.

For the year ended December 31, 2009, Adjusted EBITDA decreased by $10.7 million compared to the same period in 2008. The decrease in Adjusted EBITDA in the twelve months ended December 31, 2009 is due to $8.8 million in lower earnings from operations, $1.3 million in increased administration expenses and $0.6 million in decreased interest, dividend and other income earned in the year.

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/(loss) 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, 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 Consolidated Statement of Operations. This supplementary disclosure is intended to more fully explain disclosures related to adjusted net earnings and provides additional information related to the operating performance of APUC. Investors are cautioned that this measure should not be construed as an alternative to consolidated net earnings in accordance with GAAP.

The following table shows the reconciliation of net earnings/(loss) to adjusted net earnings exclusive of these items:

The increase in adjusted net earnings in the three months ended December 31, 2009 is primarily due to future income tax recoveries in the current year compared to future income tax expenses in the previous year, partially offset by lower earnings from operations. The reasons for future income tax recoveries are discussed in the APUC – Corporate section above.

The increase in adjusted net earnings in the twelve months ended December 31, 2009 is due primarily to by future income tax recoveries in the current year compared to future income tax expenses in the previous year partially offset by lower earnings from operations. The reasons for future income tax recoveries are discussed in the APUC – Corporate section above.

SUMMARY OF PROPERTY, PLANT AND EQUIPMENT EXPENDITURES BY BUSINESS SUBSIDIARY

APUC’s consolidated capital expenditures in 2009 remained lower than in 2008 due to a number of large capital projects that were completed in 2008. The larger capital projects completed in 2008 were APCo’s BCI project, the Sanger re-powering project, and the acquisition of the Campbellford hydroelectric facility. Liberty Water in 2008 incurred larger growth related capital projects particularly at the LPSCo facility.

Property, plant and equipment expenditures for the 2010 fiscal year are anticipated to be between $14.0 million and $20.0 million, including approximately $2.0 million related to ongoing requirements in Liberty Water, $6.7 million related to the APCo Thermal division, and $4.0 million related to the APCo Renewable Energy division.

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

During the twelve months ended December 31, 2009, APUC incurred growth and other property, plant and equipment expenditures of $1.3 million, as compared to $13.1 million during the comparable period in 2008. APCo invested $3.4 million in property, plant and equipment during the twelve months ended December 31, 2009, as compared to $5.0 million during the comparable period in 2008. In addition, Liberty Water invested $6.2 million in property, plant and equipment during the twelve months ended December 31, 2009, as compared to $35.7 million during the comparable period in 2008.

During the twelve months ended December 31, 2009, APCo Renewable Energy division’s expenditures primarily relate to investments in the Great Falls and Franklin hydroelectric facilities. During the comparable period in 2008, the APCo Renewable Energy division’s expenditures primarily relate to the Campbellford acquisition, a 4MW hydroelectric generating facility located on the Trent-Severn Waterway approximately four kilometres north of Campbellford, Ontario, and projects at Great Falls and Dickson Dam.

During the twelve months ended December 31, 2009, APCo Thermal Energy division’s expenditures primarily related to investments at the Dynafibres, EFW and BCI facility. In the comparable period, the expenditures primarily related to the completion of the Sanger re-powering project, investment in the Windsor Locks facility, the BCI steam sales facility and the EFW facility.

During the twelve months ended December 31, 2009, Liberty Water’s investment in property, plant and equipment primarily relate to completion and commissioning of projects initiated in 2008, additional well capacity and engineering work, including approximately $4.1 million of advances from developers and a $3.6 million investment in certain non-utility assets, a portion of which was sold during the year. During December 2009, Liberty Water refunded an advance from a developer which resulted in a $3.4 million reduction of in the book value of property plant and equipment and a corresponding reduction in net property plant and equipment expenditures recorded in the period

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

During the quarter ended December 31, 2009, APUC incurred growth and other property, plant and equipment expenditures of nil, as compared to $2.3 million during the comparable period in 2008. APCo incurred net investment in property, plant and equipment $1.1 million during the quarter ended December 31, 2009, as compared to $1.7 million during the comparable period in 2008. In addition, Liberty Water incurred negative net investment in property, plant and equipment of $0.5 million during the quarter ended December 31, 2009, as compared to net investment of $4.8 million during the comparable period in 2008.

During the three months ended December 31, 2009, the Renewable Energy division’s expenditures were not significant. During the comparable period in 2008, the Renewable Energy division’s expenditures primarily related to various projects at Great Falls and Dickson Dam.

During the three months ended December 31, 2009, the Thermal Energy division’s expenditures were not significant. During the comparable period in 2008, the Thermal Energy division’s expenditures primarily related to investments in the Sanger, BCI and Windsor Locks facilities.

During the three months ended December 31, 2009, Liberty Water investment in property, plant and equipment primarily related to a number of general projects including approximately $2.5 million of advances from developers, less the refund of an advance from a developer noted in the discussion of annual expenditures above. In the comparable period, the expenditures primarily related to investment in additional wells, engineering work regarding wastewater treatment operations and arsenic treatment at the LPSCo facility. As previously noted, these investments have been included in the rate case applications which are currently in process.

The following table sets out the amounts drawn, letters of credit issued and outstanding amounts available to APUC and its subsidiaries under the senior banking credit facilities previously arranged by the Fund (the “Facilities”):

As at and for the period ended December 31, 2009, APUC and the Fund are in compliance with the covenants under its Facilities.

As at December 31, 2009, $94.0 million had been drawn on the Facilities as compared to $137.0 million as at December 31, 2008. In addition to amounts actually drawn, there was $33.1 million in letters of credit currently outstanding as at December 31, 2009. As at December 31, 2009, APUC and its subsidiaries had $52.5 million of committed and available bank facilities remaining and $2.8 million of cash resulting in $55.3 million of total liquidity and capital reserves.

The term of the Facilities matures on January 14, 2011. Subsequent to December 31, 2009, APUC initiated discussions with its senior lenders with regards to entering into a new multi-year term senior debt facility.

As at December 31, 2009, in addition to the liquidity and capital reserves noted above, APUC also had $40.0 million in short term investments available to complete the acquisition of three hydroelectric generating assets located in New Brunswick and Maine having a capacity of 36.8 MW, most notably the 34.5MW Tinker Hydroelectric station located on the Aroostook River near the Town of Perth-Andover, New Brunswick.

Information concerning contractual obligations as of December 31, 2009 is shown below:

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

On October 27, 2009, pursuant to the Unit Exchange Offer, all the Fund’s trust units were exchanged for shares of APUC that began to be publicly traded on the Toronto Stock Exchange while the Fund’s trust units concurrently ceased trading on the Toronto Stock Exchange.

As at December 31, 2009, APUC had 93,064,120 issued and outstanding shares on a fully diluted basis.

APUC may issue an unlimited number of common shares. The holders of common shares are entitled to: dividends, if and when declared; 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.

On December 2, 2009, APUC issued 6,877,000 common shares at $3.35 each for net proceeds of $21.9 million after underwriting expenses and before additional issuance costs (gross proceeds of $23.0 million).

Pursuant to the takeover bid of AirSource Power Fund I LP (“Airsource”), on September 29, 2006 the Fund issued trust units and a subsidiary issued limited partnership units which were exchangeable into trust units of the Fund at the holder’s option (the “Exchangeable Units”). The Fund issued 1,021,449 trust units during the fourth quarter on and prior to October 27, 2009, and 1,473,647 trust units during the period ended October 27, 2009 pursuant to the conversion of Exchangeable Units. These trust units were converted to shares of APUC as a result of the Unit Exchange Offer.

At a special meeting of Exchangeable Unitholders of Airsource in December 2009, amendments were approved to amend the agreements related to the Exchangeable Units to allow the exchange of Exchangeable Units for common shares of APUC, as opposed to units of the Fund, and to change the definition of “Redemption Date” as set out in the Airsource partnership agreement. As a result of these changes, APUC exercised the compulsory acquisition provisions contained in the documentation relating to the Exchangeable Units on December 31, 2009 and all of the remaining outstanding Exchangeable Units were exchanged for 532,074 common shares of APUC, as per the formula set out in the original agreements. As a result, there are no outstanding Exchangeable Units as of December 31, 2009.

On August 1, 2008, the Fund issued 3,507,143 trust units in exchange for cash and securities of approximately $27.0 million or $7.69 per unit. The unit issue was pursuant to an agreement entered into on September 27, 2008 between the Fund, Highground Capital Corporation (“Highground”) (previously Algonquin Power Venture Fund) and CJIG Management Inc. (“CJIG”). Under the agreement CJIG acquired all of the issued and outstanding common shares of Highground, and the Fund issued 3,507,143 trust units, of which 3,065,183 trust units were received by Highground shareholders as part of the agreement with the remaining trust units being retained by CJIG.

During 2009, the Fund received $983 from CJIG as additional proceeds of the share issuance from assets obtained in the transaction and from the Fund’s share of the additional proceeds from the further liquidation of the assets held by Highground in excess of $26,970. This has been recorded as an increased amount assigned to the trust units originally issued. The remaining investments, formerly held by Highground, currently consist of two non-liquid debt assets having a book value of $2.4 million. The payments on these assets are current and the debt matures in 2010 and in 2012. The Fund’s 50% share of any additional proceeds from liquidation of the remaining Highground assets will be recorded when received as additional proceeds from the issuance of units in future periods.

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

Pursuant to the CD Exchange Offer, on October 27, 2009, $63,755 of the outstanding Series 1 Debentures were exchanged for convertible debentures bearing interest at 7.5%, maturing on November 30, 2014 (“Series 1A Debentures”) convertible unsecured subordinated debentures in a principal amount of $66,943. The Series 1A Debentures pay interest semi-annually in arrears on January 1 and July 1 each year and are convertible into shares of APUC at the option of the holder at a conversion price of $4.08 per share, being a ratio of approximately 245.1 shares for each $1,000 principal. The Series 1A Debentures may not be redeemed by APUC prior to January 1, 2011. During the period of January 2, 2011 until January 1, 2012, the debentures may be redeemed by APUC if the underlying trust unit price is equal to or exceeds a price of $5.10 (125% of the conversion price of $4.08). During the period of January 2, 2012 until the debenture’s maturity, APUC can redeem the debentures for 100% of the face value of debenture with cash, or for 105% of the face value of debenture with additional shares. On December 31, 2009, there were 66,943 Series 1A Debentures outstanding with a face value of $66,943.

The remaining Series 1 Debentures having a face value of $21,209, not converted to Series 1A Debentures pursuant to the CD Exchange Offer, were exchanged for 6,607,027 shares of APUC.

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

Pursuant to the CD Exchange Offer, on October 27, 2009, all of the outstanding Series 2 Debentures were exchanged for convertible unsecured subordinated debentures bearing interest at 6.35%, maturing on November 30, 2016 (“Series 2A Debentures”) in a principal amount of $59,967. The Series 2A Debentures pay interest semi-annually in arrears on April 1 and October 1 each year and are convertible into shares of APUC at the option of the holder at a conversion price of $6.00 per share, being a ratio of approximately 166.7 shares for each $1,000 principal. The Series 2A Debentures may not be redeemed by APUC prior to January 1, 2011. During the period of January 2, 2011 until January 1, 2012, the debentures may be redeemed by APUC if the underlying trust unit price is equal to or exceeds a price of $7.50 (125% of the conversion price of $6.00). During the period of January 2, 2012 until the debenture’s maturity, APUC can redeem the debentures for 100% of the face value of debenture with cash, or for 105% of the face value of debenture with additional shares. On December 31, 2009, there were 59,967 Series 2A Debentures outstanding with a face value of $59,967.

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

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

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

The following related party transactions occurred during the year ended December 31, 2009:

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

There are a number of 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 2009 Annual Information Form.

Currency fluctuations may affect the cash flows APUC would realize from its consolidated operations, as certain APUC subsidiary businesses sell electricity or provide utility services in the United States and receive proceeds from such sales in U.S. dollars. Such APUC businesses also incur costs in U.S. dollars. At the current exchange rate, approximately 45% of EBITDA and 60% of cash flow from operations is generated in U.S. dollars. APUC estimates that, on an unhedged basis, a $0.10 increase in the strength of the U.S. dollar relative to the Canadian dollar would result in increased reported revenue from U.S. operations of approximately $9.6 million and increased reported expenses from U.S. operations of approximately $6.4 million or a net impact of $3.2 million ($0.035 per share) on an annual basis.

The Fund previously managed this risk primarily through the use of forward contracts as it required U.S. dollar cash inflows to meet Canadian dollar cash outflows. As a result of the current business strategy and lower payout ratio, APUC has determined that the prior practice of hedging 100% of its U.S. currency exposure is no longer appropriate and is taking steps to eliminate its existing forward currency contract program and during the quarter ended December 31, 2009, APUC terminated forward contracts of $37.2 million for net proceeds of $0.1 million. APUC’s policy is not to utilize derivative financial instruments for trading or speculative purposes. For the year ended December 31, 2009 APUC realized a $0.3 million loss on forward contracts settled during the period.

The following chart sets out the amount of foreign exchange forward contracts outstanding as at December 31, 2009, hedge proceeds and average hedged rates over the term of the contracts:

Based on the fair value of the forward contract using the exchange rates as at December 31, 2009, the exercise of these forward contracts will result in the use of cash of $1.1 million in fiscal 2011 and result in the use of cash of $0.4 million for the remainder of the hedged period beyond 2011. Assuming a decrease in the strength of the US dollar relative to the Canadian dollar of $0.10 at December 31, 2009, with a corresponding increase in the forward yield curve, the fair value of the outstanding forward exchange contracts would increase by $4.0 million, resulting in the generation of additional cash of $1.6 million in fiscal 2011, and the generation of $0.9 million in cash for the remainder of the hedged period beyond 2011.

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

Subsequent to December 31, 2009, as a result of the acquisition of the Energy Services Business on February 4, 2010, APCo provides the short-term energy requirements to various customers at fixed rates. These customers include energy sales to a town in New Brunswick, Standard Offer Service contract with three local municipal electric utilities in northern Maine, and a series of direct energy contracts with commercial buyers also in northern Maine. The energy requirements of these customers are estimated at approximately 150,000 MW-hrs on an annualized basis. While the Tinker Assets are expected to provide the majority of the energy required to service these customers, the Energy Services Business anticipates having to purchase a portion of its energy requirements at the ISO NE spot rates to supplement self-generated energy. In the event that the Energy Services Business was required to purchase all of its energy requirements at ISO NE spot rates, each $10.00 change per MW-hr in the market prices in ISO NE would result in a change in expense of $1.5 million on an annualized basis.

This risk is mitigated though the use of short term energy hedges contracts. APCo has committed to acquire 12,500 MW-hrs of energy over the next 13 months at an average rate of approximately $75 per MW-hr.

APUC and its subsidiaries are subject to credit risk through its trade receivables. APUC does not believe this risk to be significant as approximately 90% of APCo Renewable Energy division’s revenue, approximately 80% of APCo Thermal Energy division’s revenue, and over 65% of total revenue is earned from large utility customers having a credit rating of BBB or better, and revenue is generally invoiced and collected within 45 days.

The following chart sets out APCo’s significant counterparties, their credit ratings and percentage of total revenue associated with the counterparty:

The remaining revenue is primarily earned by Liberty Water. In this regard, the credit risk related to Liberty Water accounts receivable balances of US $2.9 million is spread over approximately 68,000 customers, resulting in an average outstanding balance of less than $50.00 per customer. Liberty Water has processes in place to monitor and evaluate this risk on an ongoing basis including background credit checks and security deposits from new customers.

APUC and its subsidiaries have 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:

Liquidity risk is the risk that APUC and its subsidiaries will not be able to meet their financial obligations as they become due. APUC’s approach to managing liquidity risk is to ensure, to the extent possible, that it will always have sufficient liquidity to meet liabilities when due.

APUC currently pays a dividend of $0.24 per share per year. 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 their judgment, ensure APUC’s long-term success. Based on the current level dividends paid during the year ended December 31, 2009, cash provided by operating activities exceeded dividends declared by 2.6 times.

As at December 31, 2009, APUC had cash on hand of $2.8 million and $51.3 million available to be drawn on committed credit facilities from its bank syndicate. The term of the Facilities matures on January 14, 2011. Subsequent to December 31, 2009, APUC initiated discussions with its senior lenders with regards to entering into a new multi-year term senior debt facility. See the Liquidity and Capital Reserves section for a more detailed discussion and chart of the funds available to APUC and its subsidiaries under its credit facilities.

The Facilities and project specific debt total approximately $244.8 million with maturities set out in the Contractual Obligation table above. In the event that APUC was required to replace these Facilities 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 regards 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.

APCo’s exposure to commodity prices is primarily limited to exposure to natural gas price risk. In this regard, a discussion of this risk is set out as follows:

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 further assessment of APUC’s business risks is also set out in the 2008 Annual Information Form.

APUC is entirely dependant upon the operations and assets of APUC’s businesses. Accordingly, dividends to shareholders are dependent upon the profitability of each of APUC’s businesses. This profitability could be impacted by equipment failure, the failure of a major customer to fulfill its contractual obligations under

its PPA, reductions in average energy prices, a strike or lock-out at a facility and expenses related to claims or clean-up to adhere to environmental and safety standards. The water distribution networks of the Liberty Water operate under pressurized conditions within pressure ranges approved by regulators. Should a water distribution network become compromised or damaged, the resulting release of pressure could result in serious injury or death to individuals or damage to other property.

These risks are mitigated through the diversification of APUC’s operations, both operationally (APCo and Liberty Water) and geographically (Canada and U.S.), the use of regular maintenance programs, maintaining adequate insurance and the establishment of reserves for expenses. In addition, APCo’s existing long term PPAs minimize the risk of reductions in average energy pricing.

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.

The utility facilities are highly regulated and are subject to rate settings by State regulators. The operating companies are regulated utilities subject to the full regulation of the public utility commissions for the states in which they operate. The respective public utility commissions have jurisdiction with respect to rate, service, accounting procedures, issuance of securities, acquisitions and other matters. These utilities operate under cost-of-service regulation as administered by these State authorities. The utilities use a historic test year subject to certain adjustments for known and measureable changes in the establishment of rates for the utility and pursuant to this method the determination of the rate of return on approved rate base and deemed capital structure, together with the reasonable and prudent costs, establishes the revenue requirement upon which each utility’s customer rates are determined. These regulatory bodies have the authority to establish the allowed rate of return on approved rate base and also determine which investments are approved for inclusion in the rate base which in both cases can affect the profitability of the division. If the utilities are unable to obtain government approval of requested rate increases, or if rate increases are untimely or inadequate to cover capital investments and to recover expenses, profitability could be affected.

Federal, State and local environmental laws and regulations impose substantial compliance requirements on water and wastewater utility operations. Operating costs could be significantly affected in order to comply with new or stricter regulatory requirements.

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

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

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

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

The Renewable Energy division’s St. Leon facility does not own the property on which its turbines are located. In 2004, St. Leon entered into long term right of way agreements with land owners which allowed it to construct and maintain the wind turbines used by the facility on their property. These agreements are for minimum terms of 40 years and, upon expiry or termination, provide the land owners with title to the equipment if it is not decommissioned by APCo at its option. While APCo anticipates being in a position to renew or extend the existing PPA in 2025, in the event that APCo is unable to renew or extend the agreement, or identify another purchaser of the energy, APCo may choose to decommission the facility. APCo has assessed there to be a remote likelihood of incurring any cost to decommission the wind farm.

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

Liberty Water’s facilities operate under agreements with a state or municipal regulator to provide the sole water distribution and/or wastewater treatment services in its area of operations, as set out in the agreements. In general, these facilities are operated with the assumption that their services will be required in perpetuity and there are no contractual decommissioning requirements. In order to remain in compliance with the applicable regulatory bodies, Liberty Water has regular maintenance programs at each facility to ensure its equipment is properly maintained and replaced on a cyclical basis. These maintenance expenses, expenses associated with replacing aging wastewater treatment facilities and expenses associated with providing new sources of water can generally be included in the facility’s rate base and thus Liberty Water is allowed to earn a return on its investment.

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

To manage these risks responsibly, APUC has ensured the Environmental and Compliance departments have been established within the different subsidiaries which are responsible for monitoring all of each

subsidiary’s operations, ensuring all operating facilities are in compliance with environmental regulations and preparing regulatory submissions as required. In the aggregate, the departments comprise 7 full time equivalent positions based out of head office and have an annual budget of approximately $1.0 million, which includes wages, travel and other costs. Facility specific permitting and compliance expenses are direct operating expenses of each facility and are excluded from these expenses.

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

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

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

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

Liberty Water faces a number of environmental risks that are normal aspects of operating within its business segment. The primary environmental risks associated with the operation of a wastewater treatment facility include potential air quality and odour management issues, wastewater spills and surface and ground water contamination. In order to monitor and mitigate these risks, and to remain within the regulatory requirements appropriate for the specific facility, Liberty Water maintains ongoing sampling and testing programs as required in its operational jurisdiction, including annual field investigations by management. It also has a preventative maintenance program to reduce the risk of leaks and other mechanical failures within the wastewater collection system and at the wastewater treatment plants that it operates.

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

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

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

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

The Windsor Locks facility is the only APCo site that is currently affected by the RGGI regulations. As such APCo will be required to purchase approximately 250,000 tons of CO2 allowances per year, equivalent to the total annual CO2 emissions from the Windsor Locks facility for the 2009 to 2012 fiscal years. APCo is entitled to apply for allowances and/or purchase allowances at a base price of $2.00 per tonne from the state of Connecticut. APCo submitted an application on October 31, 2008 for allowances under the available programs. For 2010, APCo has currently estimated the cost of compliance with the RGGI requirements for the Windsor Locks facility to be between $0.2 and $0.4 million.

Seven U.S. States (including Arizona and California) and four Canadian provinces (including Manitoba, Ontario and Quebec) have formed a group called the Western Climate Initiative (“WCI”). This group recently released details of its Regional Cap-and-Trade Program, which is scheduled to start on January 1, 2012. Each member state/province is now responsible for developing the draft design of the Regional Cap-and-Trade Program and taking the necessary steps to implement the Program within its jurisdiction. APCo owns and operates the Sanger facility in California and the EFW facility in Ontario and holds investments in two others in Ontario which could be impacted by this program. As this process has just begun, it is too early to determine the potential financial impact on APCo and means available to mitigate this financial impact, if any.

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

APCo submitted a baseline greenhouse gas emissions inventory to the CDP at the end of June 2008. The emissions data includes both direct emissions from our processes as well as indirect emissions from purchased power. The emissions inventory has been developed based on guidance from the Greenhouse Gas Protocol. This submission will allow comparisons with other firms to be made, and will also be useful as a baseline for addressing climate change regulations.

As a result of certain legislation passed in Quebec (Bill C93), APCo is undertaking technical assessments of its hydroelectric facility dams owned or leased within the Province of Quebec. This is discussed in greater detail within the analysis of results in the Renewable Energy Division.

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

Liberty Water owns and operates the LPSCo facility, a water distribution and waste-water treatment utility servicing the City of Litchfield Park, and parts of the City of Goodyear, the City of Avondale and the County of Maricopa, Arizona, where groundwater pollutants, namely trichloroethylene (“TCE”) originally employed by a former aerospace manufacturing plant in the nearby City of Goodyear are progressing toward three of the twelve wells that provide water to the LPSCo service area. The EPA began monitoring TCE in 1981 and has been tracking the gradual underground movement since. In addition to actively participating in EPA regular technical meetings in regards to this monitoring program, LPSCo closely monitors its wells for this groundwater pollutant through the sampling and testing of water from wells that are potentially at risk of contamination. To date there have not been any detectable levels of TCE in the water from wells used by LPSCo. EPA’s monitoring and control efforts have not indicated that the concentrations are being reduced or fully captured. Additional remedial efforts by the EPA to stop advancement and reduce TCE concentrations are underway. In the event that any wells exceed EPA permitted TCE level, LPSCo would undertake the appropriate actions which may include installing appropriate treatment facilities or removing the well from the water distribution system of the utility. In the event of removal of a well, there would remain sufficient production and reservoir capacity within the balance of the water distribution system to adequately service the needs of all of LPCSo’s customers. In addition, LPSCo has identified alternate sites where replacement wells can be established to replace this lost capacity. The cost of establishing a new well is estimated to be between $2.0 million and $3.5 million depending on the location, depth and other factors. The cost of commissioning a well forms part of the rate base for the utility. Other factors that can impact the cost of a well include, but are not limited to, any requirement to construct wellhead treatment for pollutants, volume of water available at the new site, and acquisition of land and groundwater rights. Liberty Water does not believe it is exposed to a material liability and has not recorded a contingent environmental liability on its financial statements.

APUC’s policy is to record estimates of environmental liabilities when they are known or considered probable and the related liability is estimable. There are no known material environmental liabilities as at December 31, 2009.

The hydroelectric operations of APCo are impacted by seasonal fluctuations. These assets are primarily “run-of-river” and as such fluctuate with the natural water flows. During the winter and summer periods, flows are generally lower while during the spring and fall periods flows are generally higher. The ability of these assets to generate income may be impacted by changes in water availability or other material

hydrologic events within a watercourse. It is, however, anticipated that due to the geographic diversity of the facilities, variability of total revenues will be minimized. For Liberty Water’s water utilities, demand for water is affected by weather conditions and temperature. Demand for water during warmer months is generally greater than cooler months due to requirements for irrigation, swimming pools, cooling systems and other outside water use. If there is above normal rainfall or rainfall is more frequent than normal the demand for water may decrease adversely affecting revenues.

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

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

As reported in previous public filings of the Fund, Trafalgar Power, Inc. and Christine Falls Power Corporation (collectively, “Trafalgar”) commenced an action in 1999 in U.S. District Court against the Fund, APMI and various other entities related to them in connection with, among other things, the sale of the Trafalgar Class B Note by Aetna Life Insurance Company to the Fund and in connection with the foreclosure on the security for the Note which includes interests in Trafalgar entities that own hydroelectric generating facilities in New York. In 2006, the District Court decided that Aetna had complied with the provisions concerning the sale of the B Note, that the Fund was therefore the holder and owner of the B Note, and that all other claims by Trafalgar with respect to the transfer of the Note were without merit. On October 22, 2009 Trafalgar filed an appeal from the November 6, 2008 summary judgement to the United States Court of Appeals for the Second Circuit. Financial loss to the Fund is not expected to result from the appeal.

Although APMI paid one half of the external legal fees incurred up to July 1, 2002 with respect to the Trafalgar dispute, APUC is funding the litigation. In the event of a recovery by APUC of all or part of the funds, APUC and APMI will divide such amounts in proportion to the amount of legal fees funded, after reimbursement of expenses.

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

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

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

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

Financial statements prepared in accordance with Canadian GAAP require management to make estimates and assumptions relating to reported amounts of revenue and expenses, reported amounts of assets and liabilities and disclosure of contingent assets and liabilities. APUC regularly evaluates the assumptions and estimates that are used in the preparation of APUC’s Consolidated Financial Statements. Estimates and assumptions used by management are based on past experience and other factors deemed reasonable in the circumstances. Since these estimates and assumptions involve varying degrees of judgment and uncertainty, the amounts reported in the financial statements could in the future prove to be inaccurate.

APCo recognizes revenue derived from energy sales at the time energy is delivered. Revenue from waste disposal is recognized on an actual tonnage of waste delivered to the plant at prices specified in the contract. Certain contracts include price reductions if specified thresholds are exceeded. Revenue for these contracts are recognized based on actual tonnage at the expected price for the contract year and any amount billed in excess of the expected is deferred. Liberty Water revenue is recognized when processed and delivered to customers.

APUC records as other liabilities amounts received by Liberty Water which relate to advances from developers for water distribution and water reclamation main extensions received. These advances usually carry repayment terms based on the revenue generated by the development in question ranging over a specified period of time. At the end of the payment term, the unpaid portion of the advance converts to contribution in aid of construction and is not required to be repaid to the developer. The amount recorded as other liabilities is based on Liberty Water’s expected repayments as determined by historical experience and industry practice.

Estimates are also made related to the useful life of long-lived assets. These estimates are used to determine amortization expense. Estimates of an asset’s useful life are based on past experience with similar assets taking into account technological or other changes. If these estimates prove to be inaccurate, management may have to shorten the anticipated useful life of the assets recorded in the financial statements resulting in higher amortization expense in future periods or possibly an impairment charge to reflect the write-down in the value of the asset.

APUC and its subsidiaries also regularly assess whether there has been an impairment to long term investments, notes receivable, capital and intangible assets, and recoverability of future tax assets based on circumstances that may indicate APUC will not be able to recover the assets entire carrying value. Should impairment be deemed to have occurred, APUC would reduce the carrying value of that asset in the financial statements and deduct this amount from earnings. APUC cannot predict future events that could create impairment, or how future events might affect the carrying value of the assets’ values reported in the financial statements.

The following is a summary of unaudited quarterly financial information for the two years ended December 31, 2009.

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

Quarterly revenues have fluctuated between $43.4 million and $56.5 million over the prior two year period. A number of factors impact quarterly results including seasonal fluctuations, hydrology and winter and summer rates built into the PPAs. In addition, a factor impacting revenues year over year is the significant fluctuation in the strength of the Canadian dollar which has resulted in significant changes in reported revenue from U.S. operations.

Quarterly net earnings have fluctuated between net earnings of $15.3 million and a net loss of $21.1 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 gains and losses on financial instruments due to APUC’s adoption of Section 3855 and the discontinuation of hedge accounting under Section 3865.

APUC’s accounting policies are described in Note 1 to the Consolidated Financial Statements for the period ended December 31, 2009. There have been no changes to the critical accounting policies as disclosed in APUC’s audited Consolidated Financial Statements for the period ended December 31, 2008 except as disclosed below.

Effective January 1, 2009, APUC has adopted the CICA Handbook Section 3064, Goodwill and intangible assets. Section 3064 states that upon their initial identification, intangible assets are to be recognized as assets only if they meet the definition of an intangible asset and the recognition criteria. This section also provides further information on the recognition of internally generated intangible assets. As for subsequent measurement of intangible assets, goodwill, and disclosure, Section 3064 carries forward the requirements of the old Section 3062, Goodwill and Other Intangible Assets.

Effective October 1, 2009, APUC retrospectively adopted rate regulated accounting for its Liberty Water utilities following the principle of U.S. Financial Accounting Standards Board ASC Topic 980 Regulated Operations (“ASC 980”). Under ASC 980, regulatory assets and liabilities that would not be recorded under Canadian GAAP for non-regulated entities are recorded. Regulatory assets and liabilities represent probable future revenues or expenses associated with certain charges or credits that will be recovered from or refunded to customers through the rate making process. Items to which regulatory accounting requirements apply include deferred rate case costs, and equity return component on regulated capital projects.

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

Under ASC 980, allowance for funds used during construction projects included in rate base is capitalized. This allowance is designed to enable a utility to capitalize financing costs during periods of construction of property subject to rate regulation. It represents the cost of borrowed funds (allowance for borrowed funds used during construction) and a return on other funds (allowance for equity funds used during construction). Prior to the adoption of ASC 980, APUC capitalized interest costs directly attributable to the construction of these assets but did not capitalize the allowance for equity funds used during constructions.

The effect of adopting rate regulated accounting on previously reported amounts is as follows:

Effective January 1, 2009, APUC adopted EIC 173, Credit Risk and Fair Value of Financial Assets and Financial Liabilities, which clarifies that the credit risk of counterparties should be taken into account in determining the fair value of derivative instruments. EIC 173 has been applied retrospectively without restatement of prior periods to all financial assets and liabilities measured at fair value. The impact of adopting EIC 173 was a decline of $2,542 to the recorded amount of the financial derivative liability and an increase of $494 in future income tax liability at December 31, 2008 and a $2,048 decrease in deficit.

In January 2009, the CICA issued Handbook Section 1582, Business combinations, which replaces the existing standards. This section establishes the standards for the accounting of business combinations, and states that all assets and liabilities of an acquired business will be recorded at fair value. Estimated obligations for contingent considerations and contingencies will also be recorded at fair value at the acquisition date. The standard also states that acquisition-related costs will be expensed as incurred and that restructuring charges will be expensed in the periods after the acquisition date. This standard is equivalent to the International Financial Reporting Standards on business combinations. This standard is applied prospectively to business combinations with acquisition dates on or after January 1, 2011. Earlier adoption is permitted. APUC is currently evaluating the impact of adopting this standard on its consolidated financial statements.

In January 2009, the CICA issued Handbook Section 1602, Non-controlling interests, which establishes standards for the accounting of non-controlling interests of a subsidiary in the preparation of consolidated financial statements subsequent to a business combination. This standard is equivalent to the International Financial Reporting Standards on consolidated and separate financial statements. This standard is effective for 2011. Earlier adoption is permitted. APUC is currently evaluating the impact of adopting this standard on its consolidated financial statements.

In January 2009, the CICA issued Handbook Section 1601, consolidated financial statements, which replaces the existing standards. This section establishes the standards for preparing consolidated financial statements and is effective for 2011. Earlier adoption is permitted. APUC is currently evaluating the impact of adopting this standard on its consolidated financial statements.

In 2011, APUC is required to change the accounting framework under which financial statements are prepared in Canada to International Financial Reporting Standards (“IFRS”). For the quarter ended March 31, 2011, APUC will report quarterly comparative financial information using IFRS. While the exact impact on APUC’s financial statements of moving to IFRS is not completely known at this time; APUC conducted a high level diagnostic and qualitative assessment of its operations in order to identify the main areas where IFRS conversion will have the largest impact. Based on the analysis to date, areas of potential change may involve the valuation of property, plant and equipment, business combinations, translation of financial statements of foreign operations, income taxes, financial statement disclosure and initial adoption of IFRS under the provisions of IFRS 1, First-Time Adoption of IFRS. Experience in other jurisdictions has shown that earnings may tend to become more volatile and there will be an increase in the volume and complexity of financial disclosures.

APUC has developed a conversion plan in order to be prepared for the conversion and to minimize any disruption the conversion may cause. APUC’s conversion plan, detailed below, addresses matters including detailed assessment of the effect of IFRS on its financial statements preparation, information systems requirements, internal control over financial reporting (“ICOFR”) as well as disclosure controls and procedures (“DC&P”), in addition to training and other related business matters. This conversion plan is subject to change as a result of ongoing and subsequent changes to IFRS standards and interpretations. APUC’s Audit Committee is involved with this process and will be provided formal updates on a quarterly basis and as required.

APUC has begun to prepare IFRS format Financial Statements to highlight note disclosure differences between IFRS and Canadian GAAP. Following the company wide high-level analysis, detailed analyses are being performed for each of the main areas of differences. At that point, detailed accounting differences will be identified and quantified, the impact on information systems and the need for training will be assessed and the resulting changes to ICOFR and DC&P will be evaluated, designed and implemented area by area. The company-wide impact will then be summarized and finalized. The adjustments that arise on retrospective conversion from Canadian GAAP to IFRS will be recognized directly in opening retained earnings. Four key areas of differences are described below.

The plan focuses initially on its greatest area of required effort being PP&E. IFRS and Canadian GAAP contain the same basic principles for PP&E; however, there are some differences. Specifically, there may be changes in accounting for PP&E relating to:

IFRS requires PP&E to be measured at cost in accordance with IFRS, breaking down material items into components and amortizing each one separately. This method of componentizing PP&E may result in an increase number of component parts for the power generation facilities that are separately recorded and depreciated and, as a result, may impact the calculation of depreciation expense. Libery Water already follows component accounting under Canadian GAAP. Significant progress has been made in this area, although the work is not yet completed.

In addition, IFRS permits PP&E to be measured at fair value or amortized cost. In this regard, APUCexpects to continue to reflect PP&E at amortized costs.

In July 2009, the International Accounting Standards Board (“IASB”) issued an exposure draft providing guidance on accounting for rate-regulated activities. In light of the responses received on the exposure draft, the IASB decided to further analyze the technical merits as to whether regulatory assets and regulatory liabilities can be recognized in accordance with the Conceptual Framework and to provide a revised project timeline when their analysis is completed. This revised approach, will likely result in Canadian utilities such as APUC having to convert to IFRS before an IFRS standard for rate-regulated activities is finalized, if any. In this context, the IASB tentatively decided to approve an IFRS 1 exemption which would allow Liberty Water to use the carrying amount of PP&E as its deemed cost at the date of transition to IFRSs.

Canadian GAAP impairment testing for long-lived assets involves two steps, the first of which compares the asset carrying values with undiscounted future cash flows to determine whether impairment exists. If the carrying value exceeds the amount recoverable on an undiscounted basis, then the carrying values are written down to estimated fair value. IFRS uses a one-step approach for both testing for and measurement of impairment, with an asset carrying value compared directly with the higher of fair value less costs to sell and value in use (which uses discounted future cash flows). This may result in more frequent write-downs where carrying values of assets were previously considered recoverable under Canadian GAAP on an undiscounted cash flow basis, but could not be supported on a discounted cash flow basis. The work in this area will be performed once the carrying value of assets, namely PP&E, under IFRS as been assessed and finalized.

IFRS does not have the same concept of self-sustaining or integrated operations, as under Canadian GAAP. IFRS requires each entity to determine its functional currency using a hierarchy of criteria. Under Canadian GAAP, the power generation facilities operating in the U.S. are considered integrated operations and translated into Canadian dollars using the temporal method whereby current rates of exchange are used for monetary assets and liabilities, historical rates of exchange for non-monetary assets and liabilities and average rates of exchange for revenues and expenses, except amortization which is translated at the rates of exchange applicable to the related assets. Gains and losses resulting from these translation adjustments are included in income. Under IFRS, APUC expects that its U.S. operations will all be considered to have a U.S. dollar functional currency. The assets and liabilities of these operations will be translated into Canadian dollars at the rate prevailing at the balance sheet date while revenues and expenses to be converted using average rates for the period. Unrealized gains or losses arising as a result of the translation of the operations of self-sustaining operations will be reported as a component of Other Comprehensive Income in the Consolidated Statement of Comprehensive Income.

APUC also intends to avail itself of the IFRS 1 exemption to reset its foreign currency translation account to nil by transferring the amount to retained earnings on transition.

No significant immediate impact on the financial statements is anticipated on adoption of IFRS as APUC expects to take advantage of the IFRS 1 exemption which avoids the requirement to retrospectively restate all business combinations prior to the date of transition to IFRS, subject to certain balance sheet adjustments. Going forward, a number of differences between IFRS and Canadian GAAP will affect APUC’s business acquisitions. Under IFRS, all assets and liabilities of an acquired business are recorded at fair value. Estimated obligations for contingent considerations and contingencies are also recorded at fair value at the acquisition date. In addition, acquisition-related costs are expensed as incurred. Under Canadian GAAP, acquisition-related costs form part of the consideration paid for the acquisition and contingent considerations are recorded as part of the cost of the acquisition when the contingency is resolved and the consideration is issued or becomes issuable.

APUC hired subject matter experts to co-ordinate, manage and execute the changeover process. APUC’s key personnel and Audit Committee members have received and will continue to invest in various training courses with regards to IFRS rules and the impact it will have on APUC’s reporting requirements. Internal training will be developed for accounting employees involved with the implementation as well as employees in the operating facilities whose processes and procedures will be affected by IFRS.

APUC is reviewing the needs for systems upgrades and modifications. However, APUC does not expect combining the IFRS conversion with major IT system conversion.

The Internal Control group is involved every step of the way in the assessment of changes. Investor relations will be updated once the impacts of the transition to IFRS are better understood which will most likely be sometime in 2010 or 2011.

APUC’s senior secured revolving operating and acquisition credit facilities mature on January, 14, 2011. Accordingly, APUC will be in a position to review and amend any financial covenants impacted by IFRS during the renewal process.

Algonquin Power & Utilities Corp. (“APUC” or the “Company”) is an incorporated entity under the Canada Business Corporations Act. APUC’s principal activity is the ownership, of power generation and infrastructure facilities, through investments in securities of subsidiaries including limited partnerships and other trusts which carry on these businesses. The activities of the subsidiaries may be financed through equity contributions, interest bearing notes and third party project debt as described in the notes to the consolidated financial statements.

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

Up to December 21, 2009, the Fund was managed by Algonquin Power Management Inc. (“APMI”) (see note 16).

APUC’s power generation business unit conducts business under the name Algonquin Power. Algonquin Power owns 42 renewable energy facilities and 11 high efficiency thermal energy facilities representing more than 400 MW of installed electrical generation capacity. APUC’s Water Utility Services business unit conducts business under the name of Liberty Water. Liberty Water owns 17 regulated utilities in the United States of America providing water or wastewater services in the states of Arizona, Texas, Missouri and Illinois. These utility operating companies are regulated investor-owned utilities subject to regulation by the public utility commissions of the states in which they operate. The respective public utility commissions have jurisdiction with respect to rate, service, accounting procedures, issuance of securities, acquisitions and other matters. These utilities operate under cost-of-service regulation as administered by these state authorities. The utilities use a historic test year in the establishment of rates for the utility and pursuant to this method the determination of the rate of return on approved rate base and deemed capital structure, together with all reasonable and prudent costs, establishes the revenue requirement upon which each utility’s customer rates are determined.

The accompanying audited consolidated financial statements of APUC have been prepared according to Canadian generally accepted accounting principles (“GAAP”), applied on a consistent basis, and includes the accounts of APUC and its wholly owned subsidiaries and variable interest entities where the Company is the primary beneficiary.

Short term investments, consist of money market instruments with maturities in January 2010 and are recorded at cost, which approximates current market value. Included in short term investments is an investment of $10,000 which is denominated in US $.

Cash reserves segregated from APUC’s cash balances are maintained in accounts administered by a separate agent and disclosed separately as restricted cash in these consolidated financial statements. APUC cannot access restricted cash without the prior authorization of parties not related to APUC.

Property, plant and equipment, consisting of land, facilities and equipment, are recorded at cost. The costs of acquiring or constructing facilities together with the related interest costs during the period of construction are capitalized. Interest costs capitalized for Liberty Water’s utilities also include the allowance for equity funds used during construction (note 2(b)).

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

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

Power purchase contracts acquired are amortized on a straight-line basis over the remaining term of the contract. These periods range from 6 to 25 years from date of acquisition.

APUC reviews property, plant and equipment and intangible assets for impairment whenever events or changes in circumstances indicate the carrying amount may not be recoverable. Recoverability is measured by comparing the carrying amount of an asset to expected future cash flows. If the carrying amount exceeds the expected future cash flows, the asset is written down to its fair market value.

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

The estimated amount of contributions that are expected to be ultimately refunded is recorded as Advances in Aid of Construction in other long-term liabilities.

Other long-term liabilities also include deferred water rights. Deferred water rights result from a hydroelectric generating facility which has a fifty year water lease with the first ten years of the water lease requiring no payment which is a form of lease inducement. An annual average rate for water rights was estimated for the entire life of the lease and that average rate is being expensed over the lease term. The result of this policy is that the deferred water rights inducement amount recorded in the first ten years is being drawn down in the last forty years.

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

Investments in which APUC has significant influence but not control or joint control are accounted using the equity method. APUC records its share in the income or loss of its investees in interest, dividend and other income in the consolidated statement of operations and deficit. All other equity investments and notes receivable where APUC does not have significant influence or control are accounted for under the cost method. Under the cost method of accounting, investments are carried at cost and are adjusted only for other-than-temporary declines in value and additional investments.

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

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

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

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

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

dollars. These self-sustaining operations are translated into Canadian dollars using the current rate method, whereby assets and liabilities are translated at the rate prevailing at the balance sheet date while revenues and expenses are converted using average rates for the period. Unrealized gains or losses arising as a result of the translation of the financial statements are reported as a component of Other Comprehensive Income in the Consolidated Statement of Comprehensive Income.

The fair value of estimated asset retirement obligations is recognized in the consolidated balance sheet when identified and a reasonable estimate of fair value can be made. The asset retirement cost, equal to the estimated fair value of the asset retirement obligation, is capitalized as part of the cost of the related long-lived asset. The asset retirement costs are depreciated over the asset’s estimated useful life and are included in amortization expense on the Consolidated Statements of Operations. Increases in the asset retirement obligation resulting from the passage of time are recorded as accretion of asset retirement obligation in the Consolidated Statements of Operations. Actual expenditures incurred are charged against the accumulated obligation. Based on the APUC’s assessments the Company does not have any significant asset retirement obligations and therefore no provision for retirement obligations has been recorded in 2009 and 2008.

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

The operations of the APUC are complex and the related tax interpretations, regulations and legislation in the tax jurisdictions in which it operates are continually changing. As a result, there are usually some tax matters in question that result in uncertain tax positions. The Company recognizes income tax benefits of uncertain tax filing positions when it is more likely than not that the ultimate determination of the tax treatment of the position will result in that benefit being realized.

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

APUC has classified its cash, short term investments, accounts receivable, restricted cash, accounts payable and accrued liabilities and distribution / dividend payable as held-for-trading, which are measured at fair value. Notes receivable are classified as loans and receivables, which are measured at amortized cost as there is no liquid market for these investments. Long-term liabilities, convertible debentures, and other long-term liabilities are classified as other financial liabilities, which are measured at amortized cost, using the effective interest method. APUC reviews the fair market value of financial instruments on a regular basis and whenever events or changes in circumstances indicate that the carrying value may not be recoverable an impairment loss is recognized.

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

APUC has entered into forward foreign exchange contracts as one method of managing its exposure to the US dollar as significant cash flows are generated in the US. Under these forward exchange contracts, APUC sells specific amounts of currencies at predetermined dates and exchange rates. Cash flows from these instruments are matched to the related anticipated operational cash flows. These contracts are measured at fair value and the change in fair value is included in the Consolidated Statements of Operations.

At December 31, 2006, APUC ceased designating its foreign exchange contracts as hedges and recorded the fair value of those contracts of $11,167 as derivative assets and deferred credits. Upon the adoption of the new standards on financial instruments on January 1, 2007, the deferred credits balance of $11,167 was transferred into Accumulated Other Comprehensive Income. The balances from Accumulated Other Comprehensive Income are released as the contracts are settled. At December 31, 2009 there are no longer any amounts remaining in accumulated other comprehensive income related to these foreign exchange contracts (2008 – a gain of $1,789).

In 2006, a wholly owned subsidiary of APUC, Algonquin (AirSource) Power LP (“Airsource”), entered into a fixed for floating interest rate swap until September 2015 in a notional amount which corresponds to the outstanding balance of the Airsource credit facility in order to reduce the interest rate variability on its senior debt facility. APUC has elected not to use hedge accounting for the swap transaction and records the fair value of the swap on the Consolidated Balance Sheets. Any gain or loss in fair value is recognized in the Consolidated Statements of Operations.

The preparation of financial statements requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of these financial statements and the reported amounts of revenue and expenses during the year. Actual results could differ from those estimates. During the years presented, management has made a number of estimates and valuation assumptions, including the useful lives and recoverability of property, plant and equipment and intangible assets, the recoverability of notes receivable and long-term

investments, the recoverability of future tax assets, the portion of advances in aid of construction payments that will not be repaid, assessments of asset retirement obligations, and the fair value of financial instruments and derivatives. These estimates and valuation assumptions are based on present conditions and management’s planned course of action, as well as assumptions about future business and economic conditions. Should the underlying valuation assumptions and estimates change, the recorded amounts could change by a material amount.

Effective October 1, 2009, APUC retrospectively adopted rate regulated accounting for Canadian GAAP reporting in its Liberty Water utilities following the principles of U.S. Financial Accounting Standards Board ASC Topic 980 Regulated Operations (“ASC 980”). Under ASC 980, regulatory assets and liabilities that would not be recorded under Canadian GAAP for non-regulated entities are recorded to the extent that they represent probable future revenues or expenses associated with certain charges or credits that will be recovered from or refunded to customers through the rate making process. Items to which regulatory accounting requirements apply include deferred rate case costs, and capitalization of allowance for equity funds used during construction of regulated capital projects.

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

The effect of adopting rate regulated accounting on previously reported amounts is as follows:



	Year-ended December 31, 2008

	Balance as previously reported	Adjustment	Balance as restated
Other assets	971	1,053	2,024
Property plant and equipment	804,965	385	805,350
Future tax asset	3,304	(410)	2,894
Future income tax liability	85,654	150	85,804
Deficit	(359,547)	878	(358,669)

Effective for the 2009 annual reporting period, the Company adopted amendments to the CICA Handbook Section 3862, Financial Instruments Disclosure. This amended section improves financial instrument fair value measurement and liquidity risk management disclosures. The amendments require an entity to classify fair value measurements using a fair value hierarchy in levels ranging from 1 to 3 that reflect the significance of the inputs used in making these measurements. Level 1 represents fair value measurements for which the inputs are quoted prices in active markets for identical assets or liabilities. Level 2 represents inputs other than quoted prices that are observable either directly or indirectly. Level 3 represents inputs that are not based on observable market data. The use of observable and unobservable inputs is reflected in the fair value hierarchy assessment. The availability of observable inputs can vary based upon the financial instrument and a variety of factors, such as the instrument type, market liquidity, and other specific characteristics particular to the financial instrument. To the extent that the valuation is based on models or inputs that are less observable or unobservable in the market, the determination of fair value requires more judgment by management. The amendments also provide clarification about the required liquidity risk disclosures. Upon application by the Company, the fair value hierarchy level used in the determination of the fair market value of its derivative liabilities has been disclosed in Notes 19 and 26.

In order to effect a change in business structure from an income trust to a corporation, on October 27, 2009 the Fund’s unitholders exchanged 100% of the outstanding trust units of the Fund for a new class of common shares (“New Common Shares”) APUC, (formerly Hydrogenics Corporation or Hydrogenics), on a one for one basis. Immediately prior to this exchange, under a Plan of Arrangement, Hydrogenics transferred all of its operations and substantially all its assets and liabilities to a newly created company (“New Hydrogenics”). The pre-existing publicly traded shares of Hydrogenics were contemporaneously redeemed for shares of New Hydrogenics and thus the pre-existing publicly traded shares of Hydrogenics no longer exist. As a result of the Unit Exchange Offer, APUC paid New Hydrogenics $10,813 and has accrued an additional amount of $494 as a final closing adjustment. The transaction resulted in the Unitholders of the Fund indirectly holding their interest in the Fund as shareholders of APUC. Excluding shares issued under the CD Exchange Offer (as defined and described below), the number of common shares of APUC outstanding immediately after completion of the Unit Exchange Offer is exactly the same as the number of the Fund’s trust units outstanding immediately before the Unit Exchange Offer.

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

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

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

Contemporaneously with the Unit Exchange Offer a convertible debenture exchange offer (“the CD Exchange Offer) was made by APUC to debentureholders of the Fund. The CD Exchange Offer is more fully described in note 11.

In 2009, APUC entered into an agreement to co-acquire an electrical generation and regulated distribution utility through a strategic partnership with Emera Inc. (“Emera”). APUC and Emera each own 50% of the newly formed California Pacific Electric Company (“Calpeco”), which has agreed to acquire the California-based electricity distribution and related generation assets (the “California Utility”) of NV Energy, Inc. for a purchase price of approximately US $116 million, subject to certain working capital and other closing adjustments. APUC and Emera will jointly own and operate the California Utility through Calpeco. The California Utility currently provides electric distribution service to approximately 47,000 customers in the Lake Tahoe region. The transaction is subject to state and federal regulatory approval which is expected to occur in the later part of 2010.

As an element of the strategic partnership, Emera has also agreed to a conditional treasury subscription of approximately 8.5 million shares of APUC at a price of $3.25 per share. Delivery of the shares under the subscription receipts is conditional on and is planned to occur simultaneously with the closing of the acquisition of the California Utility. The proceeds of the subscription receipts are to be utilized to fund a portion of the cost of acquisition of the California Utility.

As of December 31, 2009, APUC has incurred costs of $1,084 related to the strategic partnership with Emera. These costs are recorded as deferred transaction costs and are included in other assets on the Consolidated Balance Sheet.

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

In accordance with the purchase and sale agreement, APUC is required to make additional payments to the previous owners for each additional customer connected to the utility. These payments continue until 2018. As of December 31, 2009, APUC has paid $87 (U.S. $78) (2008 - $nil) as a growth premium, and increased long term investments and notes receivable by a similar amount.

On August 1, 2008, the Fund issued 3,507,143 trust units pursuant to an agreement entered into on June 27, 2008 between the Company, Highground Capital Corporation (“Highground”) and CJIG Management Inc. (“CJIG”), which is the manager of Highground and a related party of the Company controlled by the shareholders of APMI. Under the agreement, CJIG acquired all of the issued and outstanding common shares of Highground and APUC issued 3,507,143 trust units of the Fund of which 3,065,183 trust units were received by Highground shareholders as part of the transaction with the remaining trust units being retained by CJIG.

The Company’s final consideration to be received for the trust units issued is dependent on the proceeds realized from liquidation of certain Highground investments. The Company’s final consideration will be equal to the lesser of (a) $26,970 plus 50% of the amount, if any, of the value of the assets formerly owned by Highground after payment of the transaction costs is in excess of $26,970 and (b) the value of all of the assets formerly owned by Highground after payment of the transaction costs, with the value of any non-cash securities received by the Company being determined through negotiation between the Directors of the Company and CJIG.

The Fund initially recorded the units issued at their fair value of $7.69 per unit which, net of transaction costs of $767, resulted in proceeds of the units being initially recorded at a value of $26,203. By December 31, 2009, the Company has received consideration and issued trust units as follows:



Consideration received:
Cash received in 2008	$	20,617
Cash received in 2009		983
Twin Falls Note Receivable		793
Retirement of certain long term liabilities of the Fund:
AirSource Development Note Receivable		1,600
AirSource Participation Agreement		1,400
Brampton Co-generation Inc. capital lease receivable		1,793

	$	27,186


Trust units issued:
Trust units issued	$	27,953
Transaction costs		(767	)

	$	27,186

During 2009, APUC received $983 from CJIG as APUC’s share of the 50% of additional proceeds from the further liquidation of the assets held by Highground in excess of $26,970. This has been recorded as an increased amount assigned to the trust units originally issued.

The remaining investments, formerly held by Highground, currently consist of two non-liquid debt assets having a book value of $2,400. APUC’s 50% share of any additional proceeds from liquidation of the remaining Highground assets will be recorded as additional proceeds when received from CJIG in future periods.

Included in transaction costs is a fee of $240 paid to APMI in respect of its role in completing the transaction (see note 17).

On April 2, 2008, the Company acquired the remaining 50% interest in the Campbellford Partnership not already owned by the Company for net cash consideration of $7,149. The Campbellford Partnership owns a 4 megawatt hydroelectric generating station on the Trent River near Campbellford, Ontario. The acquisition has been accounted for as a step acquisition using the purchase method of accounting. Under the purchase method total assets, liabilities and earnings from operations of the Campbellford partnership are included in the Company’s consolidated financial statements since the date of acquisition.

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



Working capital (net of cash received of $233)	$	128
Reserve funds		112
Plant and equipment		8,114
Intangible asset		969
Future income tax liability		(2,174	)


Total cash consideration	$	7,149

The intangible asset represents the value of the power purchase agreement with Ontario Electricity Financial Corporation. This asset will be amortized over its expected useful life of 11 years.

In 2009, APUC entered into definitive agreements to purchase certain electrical generating facility assets including 36.8MW of hydroelectric generating capacity located in New Brunswick and Maine. The acquisition consists of three hydroelectric generating stations, most notably the 34.5MW Tinker Hydroelectric station located on the Aroostook River near the Town of Perth-Andover, New Brunswick. The acquisition also includes five thermal generating stations and certain regulated NB ISO transmission lines located in

proximity to the generating facilities. On January 12, 2010, APUC completed the acquisition after satisfying the conditions of the acquisition including regulatory approval for a total cost of approximately $40,000, subject to closing adjustments. The acquisition will be financed out of the Short Term Investments. As of December 31, 2009, APUC incurred costs of $390 related to this acquisition. These costs are recorded as deferred transaction costs and are included in other assets on the consolidated balance sheet.

In connection with the Tinker Acquisition, on February 4, 2010, APUC acquired a related energy services business for a total cost of approximately $1,000. The energy services business retails the electrical generation of the Tinker Acquisition to commercial and industrial customers in northern Maine.

In accordance with the purchase and sale agreements of Rio Rico Utilities (“Rio Rico”), the Company has been required to make additional payments to the previous owners for each additional customer connected to the facilities.

As of December 31, 2009 APUC accrued $nil (2008 - $418) as a growth premium, these payments ended in 2008.

Regulatory assets are comprised of deferred rate case costs relate to costs incurred by APUC’s utilities to file, prosecute and defend rate case applications and which the utility expects to receive prospective recovery through its rates approved by the regulators. These costs are amortized over the period of rate recovery granted by the regulator.

The above notes are secured by the underlying assets of the respective facilities.

In 2009, APUC wrote off the remaining $1,103 (US - $999) principle balance of the note receivable related to its land fill gas facility which was previously recorded in other long term investments. The balance at December 31, 2009 was $nil.

In 2008, APUC sold its interest in the Brooklyn power generating facility for cash proceeds of $2,954 and recorded $918 as a gain on sale.

Facilities include cost of $94,606 (2008 - $94,606) and accumulated amortization of $25,426 (2008 - $22,889) related to facilities under capital lease or owned by consolidated variable interest entities, and $11,551 (2008 - $13,200) of construction in process. Amortization expense of facilities under capital lease was $2,537 (2008 - $2,489). In addition $5,926 (2008—$10,458) of contributions received in aid of construction have been credited to facilities cost. Equipment includes cost of $4,096 (2008 - $3,798) and accumulated amortization of $1,857 (2008 - $1,555) related to equipment under capital lease. Amortization expense of equipment under capital lease was $302 (2008 - $241). In 2009, interest of $nil (2008 - $785) was capitalized to facilities within property, plant and equipment.

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

The Peel Energy-from-Waste facility experienced an unplanned outage in late January 2010 related due to a failure with second stage boiler tubes and economizer tubes some of which were

scheduled for replacement as part of the 2010 capital expenditure plan. APUC intends to accelerate this replacement and simultaneously advance other planned capital maintenance which should allow the facility to make up some of the income expected to be lost during the outage.

The Company uses derivative financial instruments as one method to manage exposures to fluctuations in exchange rates and interest rates (see note 26 – Financial instruments).

In 2008, the Fund entered into a fixed for floating interest rate swap in the notional amount of $100,000 related to a portion of its revolving senior credit facility. APUC has effectively fixed its interest expense on this portion of the facility at a rate of 3.24% in 2009 and 4.18% in 2010. APUC has not designated the swap as a hedge for accounting purposes. The fair value of the interest swap at December 31, 2009 was a liability of $3,260 (2008 - $5,531).

In 2005, AirSource entered into a fixed for floating interest rate swap until September 2015 in order to reduce the interest rate variability on its senior debt facility. The notional amount of the swap is equivalent to the net outstanding amount of the underlying AirSource senior debt. AirSource has effectively fixed its interest expense on its senior debt facility at 5.47%. APUC has not designated the swap as a hedge for accounting purposes. The fair value of the interest swap at December 31, 2009 was a liability of $4,966 (2008 - $11,288).

APUC has entered into foreign exchange contracts as one method to manage its exposure to the U.S. dollar as significant cash flows are generated in the U.S. APUC sells specific amounts of currencies at predetermined dates and exchange rates. Cash flows from these instruments are matched to the related anticipated operational cash flows. Contracts in place at December 31, 2009 amounted to U.S. $39,760 until 2013 at a weighted average exchange rate of $1.02. The fair value of the outstanding forward exchange contracts is a liability of $1,469 at December 31, 2009 (2008 –$16,735).

On January 16, 2008 the Fund renewed its combined senior secured revolving operating and acquisition credit facilities (the “Facilities”) for a three year term with its Canadian bank syndicate. The Facilities have a maturity date of January 14, 2011.

The Facilities are subject to certain covenants which can limit amounts available for borrowing including senior debt to EBITDA (as defined in the agreement). At December 31, 2009, $94,000 (2008 - $137,000) has been drawn on the facility. In addition, the availability of the revolving credit facility has been reduced for certain outstanding letters of credit in amounts totaling $33,108 (2008 - $37,508). Therefore, based on current covenant limitations, the Fund had $52,467 of undrawn committed and available bank facilities resulting in total available and committed bank facilities of $179,575 as at December 31, 2009.

The terms of the credit agreement require the Fund to pay a standby charge of 0.25% on the unused portion of the revolving credit facility and maintain certain financial covenants including debt service ratios and various leverage ratios. The facility is secured by a fixed and floating charge over all Fund entities.

Total long term debt is reported net of deferred financing costs. Each of the facility level debt is secured by the respective facility with no other recourse to APUC or the Fund. The loans have certain financial covenants, which must be maintained on a quarterly basis. Non compliance with the covenants could restrict cash distributions/dividends to the Fund and APUC from specific facilities. As at December 31, 2009 APUC and its subsidiaries were in compliance with all debt covenants.

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

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

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

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

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

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

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

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

Total interest paid on the convertible debentures in 2009 was $9,696 (2008 - $9,370).

APUC is authorized to issue an unlimited number of common shares. The holders of the common shares are entitled to dividends if, as and when declared by the Board of Directors (the Board); to one vote per share at meetings of the holders of common shares; and upon liquidation, dissolution or winding up of APUC to receive pro rata the remaining property and assets of APUC; subject to the rights of any shares having priority over the common shares, of which none are outstanding.

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

The Fund’s Declaration of Trust provides that an unlimited number of units may be issued. Each unit represents an undivided beneficial interest in any distribution from the Fund and in the net assets in the event of termination or wind-up. All units are the same class with equal rights and privileges. Trust units are redeemable at the holder’s option at amounts related to market prices at the time subject to a maximum of $250 in cash redemptions in any particular calendar month, subject to the ability of the Fund to waive the maximum and pay further amounts by way of cash. Redemptions in excess of this amount shall be paid by way of a distribution in kind of a pro rata amount of certain of the Fund’s assets, including the securities purchased by the Fund, but not to include the generating facilities.

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

At a special meeting of Exchangeable Unitholders of Algonquin (AirSource) Power LP in December 2009, amendments were approved to amend the agreements related to the Exchangeable Units to allow the exchange of Exchangeable Units for common shares of APUC, as opposed to units of the Fund, and to change the definition of “Redemption Date” as set out in the Partnership Agreement. As a result of these changes, APUC exercised the compulsory acquisition provisions of the Exchangeable Units on December 31, 2009 and all of the remaining outstanding Exchangeable Units were exchanged for 532,074 common shares of APUC, as per the formula set out in the original agreements. As a result, there are no outstanding Exchangeable Units as at December 31, 2009 and consequently the non-controlling interest balance at December 31, 2009 is reduced to $nil (2008-$12,548). The non-controlling interest of $2,737 (2008 – ($3,142)) in the statement of operations represents the allocation of earnings to the exchangeable unitholders (AirSource Power LP) for the year ended December 31, 2009 prior to the conversion of Exchangeable Units for common shares of APUC.

The Unit Exchange Offer (Note 3), together with changes in tax rates enacted in December 2009, resulted in APUC recognizing a future income tax asset of $60,014 and a deferred credit in relation to this asset of $49,879 as at December 31, 2009. The accounting for the deferred credit is in accordance with EIC 110 – “Accounting For Acquired Future Tax Benefits In Certain Purchase Transactions That Are Not Business Combinations”. The credit is being amortized to income tax expense in proportion to the net reduction in the future income tax asset that gave rise to the deferred credit. Current and future income taxes have been provided in respect of taxable income and temporary differences related to the Company and its subsidiaries.

The provision for income taxes in the consolidated statements of operations represents an effective tax rate different than the Canadian enacted statutory rate of 33% (2008 - 33.05%). The differences are as follows:

The tax effect of temporary differences between the financial statement carrying amounts of assets and liabilities and their respective tax bases that give rise to significant portions of the future tax assets and future tax liabilities at December 31, 2009 and 2008 are presented below:

As at December 31, 2009, the Company had non capital loss carryforwards available to reduce future years taxable income, which expire as follows:

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

In accordance with the policies of the Toronto Stock Exchange, approval of the issuance of the Shares will be sought from shareholders at the next annual general meeting.

In addition to the transactions described in note 4 (c) with APMI, the following related party transactions occurred:

Up to December 21, 2009, APMI provided management services including advice and consultation concerning business planning, support, guidance and policy making and general management services. In 2009 and 2008, APMI was paid on a cost recovery basis for all costs incurred and charged $850 (2008 - $893). APMI was also entitled to an incentive fee of 25% on all distributable cash (as defined in the management agreement) generated in excess of $0.92 per trust unit. During 2009 $nil (2008 - $nil) was earned by APMI as an incentive fee.

As part of the project to re-power the Sanger facility, the Fund entered into an agreement with APMI to undertake certain construction management services on the project. APMI is entitled to a development supervision fee plus a performance based contingency fee for its construction management role on the project. During 2009, APMI was paid $nil (2008 - $23) for development supervision. During 2008, the Fund accrued $674 as the final fee owed to APMI with respect to this project. This fee has been accrued and is included in accounts payable on the consolidated balance sheet.

APUC has leased its head office facilities since 2001 from an entity owned by the shareholders of APMI on a net basis. Base lease costs for 2009 were $331 (2008 - $296).

On March 10, 2008, the Company advanced $225 to the Trustees for purposes of enabling the Trustees to purchase additional Units of the Company. The loans were subject to promissory notes issued in favour of the Company which were repayable upon demand and were recorded as a reduction in Trust Units on the consolidated balance sheet. On October 22, 2009 the loans were fully repaid. During 2008 a principal repayment of $8 was made.

APUC utilizes chartered aircraft, including the use of an aircraft owned by an affiliate of APMI, Airlink. In 2004, APUC entered into an agreement and remitted $1.3 million to the affiliate as an advance against expense reimbursements (including engine utilization reserves) for APUC’s business use of the aircraft. Under the terms of this arrangement, APUC will have priority access to make use of the aircraft for a specified number of hours at a cost equal solely to the third party direct operating costs incurred when flying the aircraft. During the year, APUC incurred costs in connection with the use of the aircraft of $367 (2008 - $332) and amortization expense related to the advance against expense reimbursements of $153 (2008 - $90). At December 31, 2009, the remaining amount of the advance was $666 (2008 - $818).

Up to August 1, 2008, the Company had project debt from Highground (previously Algonquin Power Venture Fund) in the amount of $3,000 related to the St. Leon facility. Highground advanced $1,600 at a rate of 11.25% as part of the initial financing of the St. Leon facility and advanced $1,400 at a rate of 9.25% during the first quarter of 2007. These amounts have now been eliminated on the Consolidated Balance Sheet of the Company due to the acquisition of Highground (Note 4 (c)).

Up to July 31, 2008, Highground was paid $150 (2007 - $150) in interest related to debt associated with the St. Leon facility. Some of the directors and shareholders of APMI were also directors, officers and shareholders of the manager of Highground.

In accordance with the construction services agreement related to the St. Leon facility, a company controlled by APMI was paid a final payment of $134 in 2008 for construction services.

Affiliates of APMI hold 60% of the outstanding Class B limited partnership units issued by the St. Leon Wind Energy LP (“St. Leon LP”), an indirect subsidiary of APUC and the legal owner of the St. Leon facility. The holders of the Class B Units are entitled to 2.5% of the income allocations and cash distributions from St. Leon LP for a 5 year period commencing June 17, 2008 growing to a maximum of 10% by year 15. In any particular period, cash distributions to the holders of the Class B Units are only to be made after distributions have been made to the other partners, in an aggregate amount, equal to the debt service on the outstanding debt in respect of such period. The related holders of the Class B units are entitled to cash distributions of $292 for the year ended December 31, 2009 (2008 - $173).

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

APMI is entitled to 50% of the cash flow above 15% return on investment for the BCI project pursuant to its project management contract. During 2009 and 2008, no amounts were paid under this agreement. However, APMI earned a construction supervision fee in 2008 of $100 in relation to the development of this project.

Certain of the Company’s operating entities have entered into agreements to lease either land, water rights or both that are used in the generation of electricity or to pay, in lieu of property tax, an amount based on electricity production. The terms of these leases have varying maturity dates that continue up to 2048. These payments typically have a fixed and variable component. The variable fee is generally linked to actual power production or gross revenue. APUC incurred costs of $2,823 during 2009 (2008 - $3,181) in respect of these agreements for all of its operating entities.

APUC and its subsidiaries are involved in various claims and litigation arising out of the ordinary course and conduct of its business. Although such matters cannot be predicted with certainty, management does not consider APUC’s exposure to such litigation to be material to these financial statements. Accruals for any contingencies related to these items are recorded in the financial statements at the time it is concluded that its occurrence is probable and the related liability is estimable.

Legislation in the Province of Quebec requires technical assessments be made of all dams within the province and remediation of any technical deficiencies identified in accordance with the assessment. APUC is in the process of conducting the assessments as required. Based on assessments to date, some of which are preliminary, APUC has estimated potential remedial measures involving capital expenditures of approximately $17,500 which may be required to comply with the legislation and which would be invested over a five year period or longer. APUC continues to explore alternatives to reduce or mitigate these potential capital expenditures, including technical alternatives and cost sharing with other stakeholders.

An AirSource affiliate, St. Leon Wind Energy LP (“St. Leon LP”) has entered into right-of-way agreements (collectively, the “Land Rights”), with approximately 50 local landowners, providing for a minimum term of 40 years. The Land Rights agreements provide for an annual rent payable per MW-hr generated from turbines installed on the land rented, subject to a minimum payment per wind turbine. Land without wind turbines is leased at a cost on a per acre basis. The total commitment over the term of the St. Leon power purchase agreement is estimated at $3,863.

The carrying amount of APUC’s cash, short term investments, accounts receivable, restricted cash, accounts payable and accrued liabilities, and distributions / dividends payable approximate fair market value.

The carrying amount of APUC’s long-term investments is dependant on the underlying operations and accordingly a fair value is based on management’s best estimate using inputs that are not based on directly observable markets.

APUC has long-term liabilities and convertible debentures at fixed interest rates and variable rates. The estimated fair value of the convertible debentures at current rates would be $198,892 (2008 - $112,494). The book value of the convertible debentures is $173,257 (2008 - $140,427). The estimated fair value of the long-term liabilities would be $247,119 (2008 - $261,328). The book value of the long-term liabilities is $244,772 (2008 - $296,825). The fair value of other long-term liabilities approximates their carrying value.

Advances in aid of construction included in other long-term liabilities (note – 1 (h)) do not bear interest and the amount to be repaid is uncertain and not determinable. The carrying value is estimated based on historical payment patterns.

Fair value estimates are made at a specific point in time, using available information about the financial instrument. These estimates are subjective in nature and often cannot be determined with precision. The Company has determined that the carrying value of its short-term financial assets and liabilities approximates fair value at December 31, 2009 and 2008 due to the short-term maturity of these instruments.

All cash distributions and dividends of the Company are made on a discretionary basis as determined by the Board of Directors of the Company. In 2009, the Company paid monthly cash distributions and dividends of $0.02 per unit / per share. For the year ended December 31, 2009, the Company paid cash distributions / dividends to unitholders and shareholders totaling $18,999 (2008 - $56,046) or $0.24 per unit / per share (2008 - $0.75).

Total distributions to the unitholders of the AirSource exchangeable units for 2009 were $323 (2008 - $1,709) which have been recorded as a reduction in non controlling interest on the consolidated Balance Sheet.

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

Shares or Trust units issuable on conversion of exchangeable units are calculated at the year end based on the weighted average exchangeable units outstanding during the year and applying the rate of exchange. The shares to be issued as a result of the management internalization and all the convertible debentures are excluded from this calculation as they are anti-dilutive.

APUC has two broad operating segments: Algonquin Power which owns and operates 42 renewable energy facilities and 11 high efficiency thermal energy facilities representing more than 400 MW of installed electrical generation capacity and Liberty Water which owns and operates 17 regulated utilities in the United States of America providing water or wastewater services in the states of Arizona, Texas, Missouri and Illinois.

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

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

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

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

APUC’s reportable segments are Algonquin Power - Renewable Energy, Algonquin Power - Thermal Energy and Liberty Water. The development activities are reported under Renewable Energy or Thermal Energy as appropriate. For purposes of evaluating divisional performance, the Company allocates the realized portion of the gain on financial instruments to specific divisions. This allocation is determined when the initial foreign exchange forward contract is entered into. The unrealized portion of any gains or losses on derivatives instruments is not considered in management’s evaluation of divisional performance and is therefore allocated and reported in the corporate segment. Interest expense is allocated to the divisions based on the project level debt related to the facilities in each division. Interest expense on the revolving credit facility and convertible debentures is reported in the corporate segment. The interest rate swaps relate to specific debt facilities and gains and losses are allocated to operating segments in the same manner as interest expense. The operations and assets for these segments are as follows:

All energy sales are earned from contracts with large public utilities. The following utilities contributed more than 10% of these total revenues in either 2009 or 2008: Hydro Québec 17% (2008 - 14%), Pacific Gas and Electric 12% (2008 - 14%), Manitoba Hydro 15% (2008 – 15%), and Connecticut Light and Power 18% (2008 - 22%). The Company has mitigated its credit risk to the extent possible by selling energy to these large utilities in various North American locations.

In the normal course of business, the Company is exposed to financial risks that potentially impact its operating results. The Company employs risk management strategies with a view to mitigating these risks to the extent possible on a cost effective basis. Derivative financial agreements are used to manage exposure to fluctuations in exchange rates and interest rates. The Company does not enter into derivative financial agreements for speculative purposes.

This note provides disclosures relating to the nature and extent of the Company’s exposure to risks arising from financial instruments, including credit risk, liquidity risk, foreign currency risk and interest rate risk, and how the Company manages those risks.

Credit risk is the risk of an unexpected loss if a customer or counterparty to a financial instrument fails to meet its contractual obligations. The Company’s financial instruments that are exposed to concentrations of credit risk are primarily cash and cash equivalents and accounts receivable. The Company limits its exposure to credit risk with respect to cash equivalents by maintaining minimal cash balances and ensuring available cash is deposited with its senior lenders in Canada all of which have a credit rating of A or better. The Company does not consider the risk associated with accounts receivable to be significant as over 80% of revenue from Power Generation is earned from large utility customers having a credit rating of BBB or better, and revenue is generally invoiced and collected within 45 days.

The remaining revenue is primarily earned by the Utility Services business unit which consists of regulated water and wastewater utilities in the United States. In this regard, the credit risk related to Utility Services accounts receivable balances of US$2,934 is spread over thousands of customers. The Company has processes in place to monitor and evaluate this risk on an ongoing basis including background credit checks and security deposits from new customers.

As at December 31, 2009 the Company’s exposure to credit risk for these financial instruments was as follows:

Liquidity risk is the risk that the Company will not be able to meet its financial obligations as they fall due. The Company’s approach to managing liquidity risk is to ensure, to the extent possible, that it will always have sufficient liquidity to meet liabilities when due. As at December 31, 2009, in addition to cash on hand of $2,796 the Company had $51,252 available to be drawn on its senior debt facility and $40.0 million in short term investments available to complete the acquisition of three hydroelectric generating assets located in New Brunswick and Maine. The senior credit facility contains covenants which may limit amounts available to be drawn.

The Company uses a combination of foreign exchange forward contracts and spot purchases to manage its foreign exchange exposure on cash flows generated from these operations. APUC only enters into foreign exchange forward contracts with major Canadian financial institutions having a credit rating of A or better, thus reducing credit risk on these forward contracts. Based on the fair value of the forward contracts using the

exchange rates as at December 31, 2009, the exercise of these forward contracts will result in the use of $1,084 in fiscal 2011 and result in the use of $385 in cash for the remainder of the hedged period beyond 2011. Assuming a decrease in the strength of the US dollar relative to the Canadian dollar of $0.05 at December 31, 2009 with a corresponding change in the forward yield curve, the fair value of the outstanding forward exchange contracts would increase by $3,976, increasing the expected cash generated during fiscal 2011 by $2,645, and $1,331 for the remainder of the hedged period beyond 2011.

As at December 31, 2009, APUC had US$39,760 in outstanding foreign exchange forward contracts with an average rate of $1.02 and having a fair value liability of $1,469.

The Company has performed sensitivity analysis on its U.S. dollar denominated financial instruments which consist principally of cash US$236, short term investments of US$10,000, net negative U.S. dollar working capital of $2,663 and long-term debt in integrated foreign operations of US$19,645 at December 31, 2009, to determine how a change in the U.S. dollar exchange rate would impact net earnings. As at December 31, 2009, the Company determined that a 5% change in the Canadian dollar against the U.S. dollar, assuming that all other variables, including interest rates, had remained the same, would have resulted in a $604 change in the Company’s net earnings as at December 31, 2009.

The Company is exposed to interest rate fluctuations related to certain of its debt obligations, including certain project specific debt and its revolving credit facility as well as interest earned on its cash on hand. The Company has performed sensitivity analysis on interest rate risk at December 31, 2009 to determine how a change in interest rates would impact equity and net earnings:

The following table shows derivative liabilities measured at fair value as of December 31, 2009 on the Company’s balance sheet, and the input categories associated with these liabilities:



	Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Total Fair Value at December 31

Interest rate SWAP – St Leon	$	-	$	4,966	$	-	$	4,966
Interest rate SWAP – revolving credit facility		-		3,260		-		3,260
Foreign exchange hedges		-		1,469		-		1,469

	$	-	$	9,695	$	-	$	9,695

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

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

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


	Year ended December 31
	2009		2008			2007

Revenue	$	187,265	$	213,796		$	186,175

Adjusted EBITDA ²	$	79,368	$	90,028			86,169

Cash provided by Operating Activities		50,022		77,223			40,427

Net earnings (loss)		31,257		(19,038	)		24,763

Adjusted net earnings ²		30,503		18,788

Dividends/Distributions to Shareholders/Unitholders¹		19,322		57,755			69,923

Per share/trust unit:
Net earnings	$	0.39	$	(0.25	)		0.34
Adjusted net earnings ²	$	0.38	$	0.25
Diluted net earnings (loss)	$	0.39	$	(0.25	)		0.31
Cash provided by Operating Activities	$	0.63	$	1.03			0.55
Dividends/Distributions to Shareholders/Unitholders	$	0.24	$	0.75			0.92

Total Assets		1,013,413		978,515			954,067
Long Term Debt		241,412		293,590			281,725


	Year ended December 31
	2009			2008			Change

Foreign Exchange Contracts:
Unrealized mark to market loss/(gain) on derivative financial instruments	$	(15,682	)	$	25,473		$	(41,155	)
Realized loss/(gain) on derivative financial instruments		284			(5,077	)	$	5,361

	$	(15,398	)	$	20,396		$	(35,794	)

Interest Rate Swap Contracts:
Unrealized mark to market loss/(gain) on derivative financial instruments	$	(7,424	)	$	16,953		$	(24,377	)
Realized loss/(gain) on derivative financial instruments		5,504			399		$	5,105

	$	(1,920	)	$	17,352		$	(19,272	)


Derivative Financial Instruments Total:
Unrealized mark to market loss/(gain) on derivative financial instruments	$	(23,106	)	$	42,426		$	(65,532	)
Realized loss/(gain) on derivative financial instruments		5,788			(4,678	)	$	10,466

Total loss/(gain) on derivative financial instruments	$	(17,318	)	$	37,748		$	(55,066	)


	Three months ended December 31
	2009			2008

Revenue	$	43,441		$	56,505

Adjusted EBITDA ²	$	18,027		$	23,256

Cash provided by Operating Activities		12,549			24,752

Net earnings		(1,366	)		(21,095	)

Adjusted net earnings ²		11,504			8,839

Dividend/distributions to Shareholders/Unitholders ¹		4,998			5,312

Per share/trust unit
Net earnings	$	(0.03	)	$	(0.28	)
Adjusted net earnings ²	$	0.14		$	0.12
Diluted net earnings	$	(0.03	)	$	(0.28	)
Cash provided by Operating Activities	$	0.15		$	0.32
Dividends/distributions to Shareholders/Unitholders	$	0.06		$	0.06

Total Assets		1,013,413			978,515
Long Term Debt		241,412			293,590


	Three months ended December 31
	2009			2008		Change

Foreign Exchange Contracts:
Unrealized mark to market loss/(gain) on derivative financial instruments	$	(1,261	)	$	17,583	$	(18,844	)
Realized loss/(gain) on derivative financial instruments		(148	)		345	$	(493	)

	$	(1,409	)	$	17,928	$	(19,337	)

Interest Rate Swap Contracts:
Unrealized mark to market loss/(gain) on derivative financial instruments	$	(1,627	)	$	13,058	$	(14,685	)
Realized loss/(gain) on derivative financial instruments		1,520			139	$	1,381

	$	(107	)	$	13,197	$	(13,304	)


Derivative Financial Instruments Total:

Unrealized mark to market loss/(gain) on derivative financial instruments	$	(2,888	)	$	30,641	$	(33,529	)
Realized loss/(gain) on derivative financial instruments		1,372			484	$	888

Total loss/(gain) on derivative financial instruments	$	(1,516	)	$	31,125	$	(32,641	)


	Three months ended December 31						Twelve months ended December 31
	2009			2008			2009			2008
Performance (MW-hrs sold)
Quebec Region		73,650			78,720			299,900			320,025
Ontario Region		32,775			33,072			141,825			147,125
Manitoba Region		89,625			105,643			364,500			377,450
New England Region		16,200			21,066			81,725			84,950
New York Region		24,750			25,461			95,000			92,000
Western Region		10,875			12,790			58,200			69,050


Total		247,875			276,752			1,041,150			1,090,600

Revenue
Energy sales	$	16,604		$	19,175		$	68,227		$	75,549

Expenses
Operating expenses		(6,619	)		(6,160	)		(22,279	)		(22,015	)
Other income		433			507			1,226			1,477


Division operating profit (including other income)	$	10,418		$	13,522		$	47,174		$	55,011


	Test Year Ending	Status of Rate Case Application	Estimated Annual U.S. $ Revenue Increase as Filed		Estimated Timing of Rate Increase
Facility
Arizona
Black Mountain	Q2 2008	Hearing has concluded. Awaiting Recommended Order & Opinion	$	0.9 million	Q2 2010
LPSCo	Q3 2008	Hearing has concluded. Awaiting Recommended Order & Opinion	$	12.5 million	Q2/Q3 2010
Rio Rico	Q4 2008	Direct Testimony filed on February 1, 2010 hearing scheduled for March 10-12, 2010	$	2.0 million	Q3 2010
Bella Vista, Northern and Southern Sunrise	Q1 2009	Responding to interrogatories, hearing scheduled for June 28 – July 1, 2010	$	1.5 million	Q4 2010
Texas
Texas Utilities (Silverleaf – 4 utilities)	Q4 2008	Awaiting administrative hearing date	$	1.2 million	Interim rates implemented October 2009
Tall Timbers	Q4 2008	Discovery period	$	0.2 million	Interim rates implemented July 2009
Woodmark	Q4 2008	Public consultation period	$	0.1 million	Interim rates implemented January 2010


	2009 Q4			2009 Q3			2009 Q2			2009 Q1			2008 Q4


Committed and available bank credit facilities	$	179,600		$	176,700		$	189,050		$	192,750		$	192,750


Funds Drawn on credit facilities		(94,000	)		(129,000	)		(134,000	)		(129,500	)		(137,000	)
Letters of Credit issued		(33,100	)		(33,400	)		(35,250	)		(37,600	)		(37,500	)


Remaining available bank facilities	$	52,400		$	14,300		$	19,800		$	25,650		$	18,250


Cash on Hand		2,800			7,700			6,900			900			5,900

Total liquidity and capital reserves	$	55,300		$	22,000		$	26,700		$	26,550		$	24,150


	Total		Due less than 1 year		Due 1 to 3 years		Due 4 to 5 years			Due after 5 years
Long term debt obligations	$	244,772	$	3,360	$	166,051	$	3,594		$	71,767
Convertible Debentures	$	190,160		-		-		66,943			123,217
Interest on long term debt obligations	$	157,705		21,685		38,555		39,723			57,742
Purchase obligations	$	33,219		33,219		-		-			-
Derivative financial instruments:
Currency forward	$	1,469		-		1,475		(6	)		-
Interest rate swap	$	8,226		5,775		2,025		417			9
Capital lease obligations	$	456		145		302		5			4
Other obligations	$	10,143		515		1,025		1,025			7,578


Total obligations	$	646,150	$	64,699	$	209,433	$	111,701		$	260,317


	Total			2010		2011			2012			2013

Total U.S. $ Hedged	$	39,760		$	-	$	26,450		$	12,560		$	750
Total Can. $ Proceeds	$	40,460			-		26,793			12,864			803


Average Hedged Rate	$	1.020			n/a	$	1.013		$	1.024		$	1.070

Unrealized Gain (loss)	$	(1,469	)		n/a		(1,084	)		(391	)		6

Impact of a $0.10 move in exchange rates	$	3,976			n/a	$	2,645		$	1,256		$	75


Counterparty	Credit Rating *	Approximate Annual Revenues		Percent of Divisional Revenue
Renewable Energy Division
Manitoba Hydro	AA		19,800	29%
Hydro – Quebec	A+		21,700	32%
Ontario Electricity Financial Corporation	A+		10,800	16%
Public Service Company of New Hampshire	BBB		4,400	7%
National Grid	A-		3,500	5%

Total		$	60,200	88	%

Thermal Energy Division
Connecticut Light and Power Company	BBB		23,200	29%
Pacific Gas and Electric Company	BBB+		16,300	20%
Ahlstrom	1R3 **		11,700	15%
Regional Municipality of Peel	AAA		14,500	18%

Total		$	65,700	82	%

* Ratings by Standard & Poor’s as of January 2010 ** Ratings by Dunn & Bradstreet as of February 2010


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

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

Dividend/distribution per share/trust unit		0.06			0.06		0.06			0.06

	1^st Quarter 2008			2^nd Quarter 2008		3^rd Quarter 2008			4^th Quarter 2008
Revenue	$	48.0		$	54.2	$	55.1		$	56.5
Net earnings / (loss)		(1.6	)		8.0		(4.4	)		(21.1	)
Net earnings / (loss) per trust unit		(0.02	)		0.10		(0.06	)		(0.27	)

Total Assets		948.5			950.0		962.7			978.5
Long term debt*		460.6			469.6		460.9			462.9

Distribution per trust unit		0.23			0.23		0.23			0.06


Activity	Milestone/Deadlines	Progress to date
Identify and address changes required to business matters such as bank covenants, compensation, internal reporting, budgeting and rate case filings.	Changes to significant systems and dual reporting completed for the fourth quarter of 2010.	Bank discussions have been initiated.



	2009			2008
				Restated see note 2(b))

ASSETS
Current assets:
Cash	$	2,796		$	5,902
Short term investments (note 1(c))		40,010			-
Accounts receivable		20,484			26,600
Prepaid expenses		4,674			2,832
Income tax receivable		1,143			1,538
Current portion of future tax asset		14,566			-
Current portion of notes receivable		521			485

		84,194			37,357

Long-term investments and notes receivable (note 6)		24,029			27,954
Future non-current income tax asset (note 14)		61,219			2,894
Property, plant and equipment (notes 2(b) and 7)		749,350			805,350
Intangible assets (note 8)		85,929			97,398
Restricted cash		4,316			5,295
Deferred financing costs		200			243
Other assets (notes 2(b), 4(a) and 5)		4,176			2,024


	$	1,013,413		$	978,515


LIABILITIES AND UNITHOLDERS’ EQUITY

Current liabilities:
Accounts payable and accrued liabilities	$	33,219		$	34,074
Distributions / dividends payable		1,857			1,587
Current portion of long-term liabilities (note 10)		3,360			3,235
Current portion of other long-term liabilities (note 12)		1,025			1,001
Current portion of derivative liabilities (note 9)		5,775			8,438
Current income tax liability		5			541
Current portion of deferred credits		10,500			-
Future income tax liability (note 14)		913			1,191

		56,654			50,067
Long-term liabilities (notes 10)		241,412			293,590
Convertible debentures (note 11)		173,257			140,427
Other long-term liabilities (note 12)		25,228			28,859
Future non-current income tax liability (note 14)		79,914			85,804
Derivative liabilities (note 9)		3,920			25,116
Deferred credits (note 3)		39,379			-
Non controlling interest (note 13)		-			12,548
Shareholders’ equity:
Shareholders’ capital (notes 3 and 13)		787,037			722,215
Deficit		(344,676	)		(358,669	)
Accumulated other comprehensive loss		(48,712	)		(21,442	)

		393,649			342,104
Commitments and contigencies (note 18)


	$	1,013,413		$	978,515



	2009			2008


Revenue:

Energy sales	$	130,436		$	158,508
Waste disposal fees		14,468			15,706
Water reclamation and distribution		38,513			35,233
Other revenue (note 24)		3,848			4,349

		187,265			213,796


Expenses

Operating		102,736			120,479
Amortization of property, plant and equipment		38,578			36,541
Amortization of intangible assets		7,305			7,305
Management costs (note 17)		850			893
Administrative expenses		10,712			9,419
(Gain) / loss on foreign exchange		(1,261	)		4,018

		158,920			178,655


Earnings before undernoted		28,345			35,141

Interest expense		21,387			26,288
Interest, dividend income and other income (note 23)		(6,401	)		(7,023	)
Write down of property, plant and equipment (note 7)		5,354			-
Write down of note receivable (note 6)		1,103			-
(Gain) / loss on derivative financial instruments (note 15)		(17,318	)		37,748

		4,125			57,013


Earnings from operations before income taxes, non-controlling interest and corporatization costs		24,220			(21,872	)

Management internalization costs (note 16)		4,693			-
Other corporatization costs (note 3)		3,460			-


Earnings/(loss) before income taxes and non-controlling interest		16,067			(21,872	)

Income tax expense (recovery) (note 14)

Current		397			(184	)

Future		(18,324	)		492

		(17,927	)		308

Non-controlling interest in earnings (loss) of subsidaries		2,737			(3,142	)


Net earnings / (loss)	$	31,257		$	(19,038	)


Basic net earnings / (loss) per share (note 22)	$	0.39		$	(0.25	)

Diluted net earnings / (loss) per share (note 22)	$	0.39		$	(0.25	)



	2009			2008


Cash provided by (used in):

Operating Activities:

Net earnings / (loss)	$	31,257		$	(19,038	)
Items not affecting cash:
Amortization of property, plant and equipment		38,578			36,541
Amortization of intangible assets		7,305			7,305
Other amortization		1,441			1,130
Distributions received in excess of equity income		1,991			680
Future income taxes / (recovery)		(18,324	)		492
Gain on sale of land		(1,451	)		-
Gain on sale of note receivable and other assets		-			(918	)
Write down of property, plant and equipment		5,354			-
Write down of note recievable		1,103			-
Inducement expense on convertible debenture conversion		1,252			-
Management internalization costs		4,693			-
Unrealized (gain) / loss on derivative financial instruments		(23,106	)		42,426
Minority interest		2,737			(3,142	)
Unrealized foreign exchange (gain) / loss		(1,503	)		6,018

		51,327			71,494

Changes in non-cash operating working capital (note 21)		(1,305	)		5,729

		50,022			77,223
Financing Activities:
Cash distributions / dividends (note 20)		(19,043	)		(66,108	)
Cash distributions to non-controlling interest (notes 17 and 20)		(809	)		(1,996	)
Common share issue, net of costs		21,180			-
Convertible debenture issue, net of costs		57,975			-
Repayment / (advance) Trustee loans		218			(218	)
Deferred financing costs		(109	)		(463	)
Increase in long-term liabilities		23,000			64,300
Decrease in long-term liabilities		(69,175	)		(55,873	)
Increase / (decrease) in other long-term liabilities		(5,870	)		5,314

		7,367			(55,044	)
Investing Activities:
Decrease in restricted cash		343			1,787
Increase in short-term investments		(39,995	)		-
Decrease/ (increase) in other assets		(2,774	)		637
Receipt of principal on notes receivable		448			517
Increase in long-term investments (note 4(b))		(87	)		(191	)
Proceeds from liquidation of Highground assets (Note 4(c))		983			-
Proceeds from sale of land		2,502			-
Proceeds from sale on note receivable		-			2,954
Net additions to property, plant and equipment		(10,916	)		(45,561	)
Acquisition of Highground		-			20,617
The unit exchange transaction (note 3)		(10,813	)		-
Acquisitions of operating entities		-			(8,274	)

		(60,309	)		(27,514	)

Effect of exchange rate differences on cash		(186	)		876


Increase / (decrease) in cash		(3,106	)		(4,459	)

Cash, beginning of the period		5,902			10,361


Cash, end of the period	$	2,796		$	5,902


Supplemental disclosure of cash flow information:
Cash paid during the period for interest expense	$	19,956		$	26,160
Cash paid / (received) during the period for income taxes	$	873		$	1,336


		News Release


	Three months ended December 31						Twelve months ended December 31
	2009			2008			2009			2008

Performance (MW-hrs sold)		147,482			145,050			571,505			597,923
Performance (tonnes of waste processed)		42,189			42,348			161,102			161,198

Revenue
Energy sales	$	13,819		$	21,806		$	62,209		$	82,959
Less:
Cost of Sales – Fuel *		(5,224	)		(11,597	)		(26,517	)		(44,706	)

Net Energy Sales Revenue	$	8,595		$	10,209		$	35,692		$	38,253

Waste disposal sales		3,786			3,998			14,468			15,706
Other revenue		545			1,691			3,848			4,349

Total net revenue	$	12,926		$	15,898		$	54,008		$	58,308

Expenses
Operating expenses *		(7,121	)		(8,807	)		(30,782	)		(32,515	)
Interest and other income		872			868			3,749			3,665


Division operating profit (including interest and dividend income)	$	6,677		$	7,738		$	26,975		$	31,053


	Three months ended December 31					Twelve months ended December 31
	2009			2008		2009		2008
ALGONQUIN POWER CO.

Renewable Energy Division
Maintenance expenditures	$	472		$	353	$	902	$	1,280
Growth and other expenditures		8			439		212		8,144

Total	$	480		$	792	$	1,114	$	9,424

Thermal Energy Division
Maintenance expenditures	$	664		$	1,212	$	2,398	$	3,457
Growth and other expenditures		-			1,853		1,123		4,985

Total	$	664		$	3,065	$	3,521	$	8,442


LIBERTY WATER CO.

Capital Investment in regulatory assets	$	(477	)	$	4,785	$	6,174	$	35,712


Consolidated (includes Corporate)
Maintenance expenditures	$	1,136		$	1,713	$	3,407	$	4,995
Capital investment in regulatory assets		(477	)		4,785		6,174		35,712
Growth and other expenditures		8			2,291		1,335		13,128

Total	$	667		$	8,789	$	10,916	$	53,835




	2009		2008 Restated (see note 2(b))


Balance, beginning of period, as originally reported	$ (358,669	)	$	(284,463	)
Changes in accounting policies (note 2(b)	-			878
Adjustments relating to adoption of EIC 173 without restatement of prior periods (note 2(c))	2,048			-

Balance, beginning of period as restated	(356,621	)		(283,585	)
Net earnings	31,257			(19,038	)
Distributions / dividends	(19,312	)		(56,046	)


Balance, end of period	$ (344,676	)	$	(358,669	)



	2009		2008

Regulatory assets	$	1,713	$	1,155
Wind development assets		788		709
Deferred transaction costs -
California Utility (note 4(a) )		1,084		-
Tinker Acquisition (note 4 (e))		390		-
Other		201		160


	$	4,176	$	2,024



	2009			2008

32.4% of Class B non-voting shares of Kirkland Lake Power Corp.	$	8,344		$	9,364
25% of Class B non-voting shares of Cochrane Power Corporation		6,544			7,379
45% partnership interest in the Algonquin Power (Rattle Brook) Partnership		3,827			3,881
Investment in Entrada Del Oro (note 4 (b))		709			820

12.1% interest in Tranche A and Tranche B term loan issued by Chapais Énergie, Société en Commandite The loans bear interest at the rate of 10.789% and 4.91%, respectively		3,701			4,034
Airlink Advance (note 17)		666			818
Note Receivable - Twin Falls. The note bears interest at the rate of 6.75%		759			783
Other		-			1,359


		24,550			28,438

Less: current portion		(521	)		(485	)


Total long term investments and notes receivable	$	24,029		$	27,953


2009

	Cost		Accumulated amortization		Net book value

Land	$	11,323	$	-	$	11,323
Facilities		953,826		224,244		729,582
Equipment		30,325		21,880		8,445


	$	995,474	$	246,124	$	749,350

2008

	Cost		Accumulated amortization		Net book value

Land	$	11,154	$	-	$	11,154
Facilities		980,281		195,120		785,161
Equipment		27,855		18,820		9,035


	$	1,019,290	$	213,940	$	805,350



	Amount		Average exchange rate

2011		26,450		1.01
2012		12,560		1.02
2013		750		1.07

	US $	39,760	$	1.02



	2009		2008


Revolving credit facility: Revolving line of credit interest rate is equal to bankers acceptance or LIBOR plus 0.95%. The effective rate of interest for 2009 was 1.71% (2008 – 4.25%).	$	94,000	$	137,000

AirSource Senior Debt Financing: Interest rate is equal to bankers’ acceptance plus 1% and matures on October 31, 2011. Interest payments only until April 2008 and monthly interest and quarterly principal payments totaling $1,649 (2008 – $1,179). The effective rate of interest for 2009 was 1.78% (2008 – 4.55%).		70,271		71,865

Senior Debt Long Sault Rapids: Interest at rate of 10.2% repayable in blended monthly installments of $402 which commenced in February 1999 and maturing December, 2027.		40,594		41,246

Sanger Bonds: U.S. $19,200 California Pollution Control Finance Authority Variable Rate Demand Resource Recovery Revenue Bonds Series 1990A, interest payable monthly, maturing September, 2020. The variable interest rate is determined by the remarketing agent. The effective interest rate for 2009 is 1.44% (2008 – 2.16%).		20,179		23,512

Litchfield Park Service Company Bonds: 1999 and 2001 IDA Bonds. Interest rates of 5.87% and 6.71% repayable in blended semi-annual installments maturing October 2023 and October 2031. Principal payments of U.S. $240 (2008 – U.S. $230) The balance of these notes at December 31, 2009 was U.S. $4,325 and U.S. $7,983, respectively (2008 – U.S. $4,527 and U.S. $8,077).		12,936		15,436

Senior Debt Chute Ford: Interest rate of 11.6% repayable in monthly installments of $64 which commenced in February 1996 and maturing April, 2020.		4,580		4,795

Bella Vista Water Loans: Water Infrastructure Financing Authority of Arizona Interest rates of 6.26% and 6.10% repayable in monthly and quarterly installments (U.S. $15 and U.S. $4) maturing March, 2020 and December, 2017. The balance of these notes at December 31, 2009 was US$1,478 and US$102 respectively (2008 – US$1,650 and US$111).		1,707		2,125



	2009			2008


Bonds Payable: Obligation to the City of Sanger due October 1, 2011 at interest rates varying from 5.45% to 5.55%. U.S. $445 (2008 - U.S. $650).		468			796


Other		37			50


	$	244,772		$	296,825
Less: current portion		(3,360	)		(3,235	)


	$	241,412		$	293,590


2010	$	3,360
2011		164,484
2012		1,567
2013		1,719
2014		1,875
Thereafter		71,767

	$	244,772


2009	New Series 1			New Series 2			Series 3			Total


Maturity date	2014 November 30			2016 November 30			2017 June 30

Interest rate		7.50	%		6.35	%		7.00	%

Conversion price per share	$	4.08		$	6.00		$	4.20



Carrying value at December 31, 2008		83,178			57,249			-			140,427

Issued pursuant to December 2, 2009 offering		-			-			63,250			63,250

Change in equity component (Note13)		(1,179	)		171			(4,275	)		(5,283	)

Conversion to shares (Note13), net of costs		(21,209	)		(33	)		-			(21,242	)

Deferred issue costs		(784	)		(1,453	)		(2,731	)		(4,968	)

Amortization and accretion		722			307			44			1,073


Carrying value at December 31, 2009	$	60,728		$	56,241		$	56,288		$	173,257


Face value at December 31, 2009	$	66,943		$	59,967		$	63,250		$	190,160


2008	Series 1			Series 2						Total


Maturity date		2011 July 31			2016 November 30

Interest rate		6.65	%		6.20	%

Conversion price per unit	$	10.65		$	11.00


Carrying Value, December 31, 2007	$	82,616		$	56,971					$	139,587

Amortization and accretion		562			278						840


Carrying value at December 31, 2008	$	83,178		$	57,249					$	140,427


Face Value at December 31, 2008	$	84,964		$	60,000					$	144,964



	2009			2008


Capital Leases Obligation for equipment leases. Interest rates varying from 1.90% to 5.80%, monthly interest and principal payments with varying dates of maturity from March 2012 to February 2013	$	456		$	375

Advances in aid of construction		14,952			17,500
Customer deposits		2,405			3,020
Deferred water rights inducement		3,089			3,170
Other		5,351			5,795


		26,253			29,860
Less: current portion		(1,025	)		(1,001	)


	$	25,228		$	28,859


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

2010	$	1,025
2011		694
2012		107
2013		9
2014		-
Thereafter		24,418


	$	26,253



	2009		2008


Balance of Trust units, beginning of period	$	721,953	$	691,734

Issued on conversion of Airsource exchangeable units		14,487		4,016

Conversion of convertible debentures, net of costs		21,825		-

Common Share issue, net of costs		22,026		-

Issued pursuant to Highground transaction (Note 4 (c))		-		26,203

Proceeds from liquidation of Highground assets (Note 4 (c))		983		-


Balance of Trust units, end of the period			$	721,953
Balance of Shares, end of the period	$	781,274

Trustee Loans (Note 17)		-		(217	)

Equity component of convertible debentures (Note 11)		5,763		479


Unitholders’ equity, end of period			$	722,215
Shareholders’ equity, end of period	$	787,037



	2009	2008


Trust units, beginning of period	77,574,372	73,644,356
Issued on conversion of Algonquin (AirSource) Power LP exchangeable units	2,005,721	422,873
Conversion of convertible debentures (Note 11)	6,607,027	-
Issued pursuant to Highground transaction (Note 4(c))	-	3,507,143
Issued pursuant to offering	6,877,000	-


Trust units, end of period		77,574,372
Common shares, end of period	93,064,120



	2009			2008


Expected income tax expense / (recovery) at Canadian statutory rate		5,302			(7,228	)
Increase (decrease) resulting from:
Accounting losses (income) of the Fund taxed at the unitholder level		(20,790	)		4,513
Differences in tax rates in subsidiaries and changes in tax rates		(1,848	)		426
Change in valuation allowances		10,688			21,239
Foreign exchange loss on intercompany items		(13,464	)		(18,329	)
Non deductible expenses and other		2,185			(313	)


Income tax expense / (recovery)	$	(17,927	)	$	308



	2009			2008


Future tax assets:
Non-capital losses, investment tax credits, currently non-deductible interest expense and financing costs	$	104,455		$	25,355
Unrealized foreign exchange differences on US entity debt		25,138			11,674
Customer advances in aid of construction		5,393			6,768
Foreign exchange hedges and interest rate swaps		2,865			3,940

Total future tax assets		137,851			47,737

Less: Valuation allowance		(35,393	)		(24,705	)

Total future tax assets		102,458			23,032


Future tax liabilities:
Property, plant and equipment		(96,960	)		(95,157	)
Intangible assets		(8,409	)		(9,861	)
Other		(2,131	)		(2,115	)

Total future tax liabilities		(107,500	)		(107,133	)


Net future tax liability	$	(5,042	)	$	(84,101	)

Classified in the financial statements as:

	2009			2008

Future current income tax asset	$	14,566		$	-
Future non-current income tax asset Future current income tax liability		61,219 (913	)		2,894 (1,191	)

Future non-current income tax liability		(79,914	)		(85,804	)


	$	(5,042	)	$	(84,101	)



Year of expiry	Non-capital loss carryforward

2010	$	19,390
2014		29,788
2015		37,487
2019		116
2020 and onwards		175,323

	$	262,104



	2009			2008


Unrealized loss/(gain) on derivative financial instruments:
Foreign exchange contracts	$	(15,682	)	$	25,473
Interest swaps		(7,424	)		16,953

Total unrealized loss/(gain) on derivative financial instruments	$	(23,106	)	$	42,426


Realized loss/(gain) on derivative financial instruments:
Foreign exchange contracts	$	284		$	(5,077	)
Interest rate swaps		5,504			399

Total realized loss/(gain) on derivative financial instruments	$	5,788		$	(4,678	)


Loss/(gain) on derivative financial instruments	$	(17,318	)	$	37,748



	2009	2008

Weighted average shares – basic	79,830,906	75,265,940
Shares issuable on conversion of AirSource exchangeable units	1,499,222	2,042,103


Weighted average shares – diluted	81,330,128	77,308,043



	2009		2008

Interest income	$	710	$	918
Dividend income		2,928		2,928
Equity income		361		373
Gain on sale of Brooklyn note		-		918
Gain on sale of land and land rights		1,451		700
Other		951		1,186


	$	6,401	$	7,023



	2009		2008

Natural gas sales	$	588	$	481
Hydro mulch sales		3,260		3,832
Other		-		36


	$	3,848	$	4,349