ALGONQUIN POWER INCOME FUND ANNUAL INFORMATION FORM MARCH 31, 2006 TRUST UNITS OF ALGONQUIN POWER INCOME FUND ARE NOT "DEPOSITS" WITHIN THE MEANING OF THE CANADA DEPOSIT INSURANCE CORPORATION ACT (CANADA) AND ARE NOT INSURED UNDER THE PROVISIONS OF THAT ACT OR ANY OTHER LEGISLATION. THE FUND ................................................................. 2 DEVELOPMENT OF THE BUSINESS .............................................. 3 DESCRIPTION OF THE BUSINESS .............................................. 11 THE DEVELOPMENTS ......................................................... 12 DECLARATION OF TRUST ..................................................... 70 GOVERNANCE, MANAGEMENT AND OPERATIONS .................................... 76 TRUST UNIT AND LOAN CAPITAL OF THE FUND .................................. 79 THE INDEPENDENT POWER GENERATION INDUSTRY ................................ 86 WATER SERVICES INDUSTRY .................................................. 96 OTHER CONSIDERATIONS ..................................................... 98 SELECTED FINANCIAL INFORMATION ........................................... 101 DISTRIBUTION POLICY ...................................................... 102 MANAGEMENT'S DISCUSSION AND ANALYSIS ..................................... 103 CANADIAN FEDERAL INCOME TAX CONSIDERATIONS ............................... 103 ELIGIBILITY FOR INVESTMENT ............................................... 108 RATINGS .................................................................. 109 MARKET FOR SECURITIES .................................................... 110 TRUSTEES AND OFFICER OF THE FUND ......................................... 112 AUDIT COMMITTEE .......................................................... 113 DIRECTORS AND EXECUTIVE OFFICERS OF THE MANAGER AND POWER SYSTEMS ........ 114 LEGAL PROCEEDINGS ........................................................ 115 INTEREST OF MANAGEMENT AND OTHERS IN MATERIAL TRANSACTIONS ............... 115 TRANSFER AGENTS AND REGISTRARS ........................................... 115 MATERIAL CONTRACTS ....................................................... 115 LEGAL MATTERS ............................................................ 116 RISK FACTORS ............................................................. 116 ADDITIONAL INFORMATION ................................................... 122 SCHEDULE A GLOSSARY ...................................................... A SCHEDULE B ALGONQUIN POWER INCOME FUND AUDIT COMMITTEE CHARTER ........... B -i- -2- ALGONQUIN POWER INCOME FUND THE FUND Algonquin Power Income Fund is an unincorporated open ended trust created by a declaration of trust dated September 8, 1997, in accordance with the laws of the Province of Ontario. The head and principal office of the Fund is located at 2845 Bristol Circle, Oakville, Ontario L6H 7H7. The Declaration of Trust was amended on: (1) December 18, 1998, to provide the Fund with greater flexibility to borrow monies, which borrowings may be secured by the Fund's assets; (2) on June 1, 2000, to clarify that Fund indebtedness may be secured by some or all of the assets of the Fund, to increase the amount of permitted monthly cash redemptions from $10,000 to $250,000 and to expand the types of permitted investments which the Fund may make to include investments in energy-related assets and such other investments as the Trustees consider reasonable and appropriate; (3) on May 24, 2001, to provide that a quorum at a meeting of Unitholders shall, except in specified circumstances, consist of two or more individuals present in person or represented by proxy; (4) on May 23, 2002, to make clear the ability of the Fund to complete certain transactions in connection with any internal reorganization of the Fund's assets, without Unitholder approval; (5) on June 26, 2003, to clarify the ability of the Fund to dispose of certain assets of the Fund and provide guarantees of the obligations of the Fund's related entities, without Unitholder approval, permit fractional Units and to provide for certain other housekeeping amendments; and (6) on May 26, 2004, to authorize the Trustees to appoint up to two (2) additional Trustees between annual meetings of Unitholders. The Declaration of Trust was restated to reflect the foregoing amendments as of May 26, 2004. The Fund has direct or indirect interests in the following corporations: Algonquin Power Fund (Canada) Inc., Donnacona Holdings Inc., Algonquin Holdco Inc. and Algonquin Power Energy from Waste Inc. (formerly KMS Peel Inc.), Ontario corporations; Corporation D'Investissements Eoliennes Algonquin Power and Corporation D'Investissements Eoliennes St-Laurent Inc., Quebec corporations; Lakeport Hydroelectric Corporation, an S Corporation under United States law; Algonquin Power Fund (America) Inc., Algonquin Power Fund (America) Holdco Inc., Algonquin Water Resources of America, Inc., CSI Oswego Corp., KMS America, Inc. and KMS Crossroads, Inc., Delaware corporations; Algonquin Power (Biogas) LLC, Algonquin Power - Cambrian Pacific Genco LLC, MM Tajiguas Energy LLC, MM Prima Deshecha Energy LLC, MM Nashville Energy LLC, MM Hackensack Energy LLC, Suncook Energy LLC, MM Burnsville Energy LLC, Minnesota Methane II, LLC, NM Milliken Genco LLC, NM Colton Genco LLC, NM Mid-Valley Genco LLC, NM San Timateo Genco LLC, MM San Bernardino Energy LLC, NEO-Montauk Genco LLC, Montauk-Neo Gasco LLC, MN San Bernadino Gasco I LLC, MN San Bernadino Gasco II LLC, Algonquin Power Systems (LFG) LLC and Algonquin Power (Beaver Falls), LLC, Delaware limited liability companies; Landfill Power LLC, a Wyoming limited liability company, SFR Hydro Corporation, a New Hampshire corporation; Clement Dam Hydroelectric LLC, and Franklin Power, LLC, New Hampshire limited liability companies; Worcester Hydro Company, Inc, a Vermont corporation, Court Street Investments, Inc., Oswego Power Company, Inc. and Oswego Energy Corp., Massachusetts corporations; Tug Hill Energy, Inc., a New York corporation; Black Mountain Sewer Corporation, Gold Canyon Sewer Company, Bella Vista Water Co., Inc., Litchfield Park Service Company, Rio Rico Utilities Inc., Arizona corporations; Great Falls Energy, L.L.C., a Maryland limited liability company; Algonquin Sanger Power LLC, a California limited liability company; Woodmark Utilities, Inc. and Tall Timbers Utility Company, Inc., Texas corporations; Algonquin Water Resources of Texas LLC, a Texas limited liability company; Algonquin Water Resources of Missouri LLC, a Missouri limited liability company; Algonquin Water Resources of Illinois, LLC, an Illinois limited liability company; Algonquin Windsor Locks LLC, a Connecticut limited -3- liability company and Dyna Fibres Inc., a California corporation. In addition, Algonquin Power Acquisition Inc. and Algonquin Energy Services Inc., both Delaware corporations, were incorporated as acquisition vehicles for proposed acquisitions by the Fund in the United States and currently have no assets. The Fund also has direct or indirect interests in the following partnerships: Valley Power LP, an Alberta limited partnership; Societe Hydro-Donnacona, S.E.N.C, a Quebec general partnership; Societe en Commandite Algonquin (Eoliennes) and Algonquin Power (Mont-Laurier) Limited Partnership, Quebec limited partnerships; Algonquin Power (Campbellford) Limited Partnership, an Ontario limited partnership; Hollow Dam Power Company and Burt Dam Power Company, New York general partnerships; Hadley Falls Associates, HDI Associates III, Avery Hydroelectric Associates, Gregg Falls Hydroelectric Associates Limited Partnership, Pembroke Hydro Associates Limited Partnership and Mine Falls Limited Partnership, New Hampshire limited partnerships; Moretown Hydro Energy Company, a Vermont partnership; HDI Associates I, an Indiana general partnership; Great Falls Hydroelectric Company Limited Partnership, a Maryland limited partnership; Oswego Hydro Partners, L.P., a Delaware limited partnership; and Algonquin Power (Rattle Brook) Partnership, a Newfoundland partnership. The Fund is the sole beneficiary of Algonquin Power Trust, an unincorporated open ended trust created by a declaration of trust dated June 30, 2000 in accordance with the laws of the Province of Ontario. Algonquin Power Trust owns all of the outstanding units of Algonquin Power Operating Trust, an unincorporated open ended trust created by an amended and restated trust indenture effective January 2, 1997, in accordance with the laws of the Province of Alberta. Algonquin Power Trust also owns all of the outstanding trust units of KMS, an unincorporated open ended trust created by a declaration of trust dated February 18, 1997, in accordance with the laws of the Province of Alberta. With the exception of (a) Algonquin Power (Campbellford) Limited Partnership, in which the Fund has a 50% indirect ownership interest; (b) Algonquin Power (Rattle Brook) Partnership, in which the Fund has a 45% indirect interest; and (c) Valley Power LP, in which the Fund has a 50% indirect interest, all of the above-noted entities are wholly-owned, directly or indirectly, by the Fund, subject to the Manager's Interest. In addition, the Fund has a 50% ownership interest in Algonquin Water Services LLC ("AWS"). All information contained in this Annual Information Form is presented as at March 31, 2006, unless otherwise specified. Reference is made to the glossary attached as Schedule A for the meanings of certain defined terms. DEVELOPMENT OF THE BUSINESS GENERAL The Fund was created to acquire direct or indirect equity interests in hydroelectric generating facilities located in Canada and the United States. The Fund has since expanded its mandate and will consider investment opportunities which provide stable cash flow from renewable resource facilities. Potential candidates could include wind, biomass or natural gas powered generating stations or facilities within a regulated utility. The Fund, through its interests in the Fund Businesses, is engaged, indirectly, primarily in the business of generating and marketing electrical energy within the independent power generation industry. As at March 31, 2006, the Fund holds equity interests, directly and indirectly, in 48 hydroelectric generating facilities located in Ontario (5), Quebec (12), Newfoundland (1), Alberta (1), New York State (13), New Hampshire (13), Vermont (2) and New Jersey (1) representing aggregate installed generating -4- capacity of approximately 143 MW. The Fund holds equity interests in one energy from waste facility in Ontario with an installed generating capacity of 10 MW, 12 land-fill gas fired facilities in California, Tennessee, New Jersey, New Hampshire and Minnesota with total installed generating capacity of 36 MW and three natural gas-fired cogeneration facilities in each of Connecticut, New Jersey and California with an installed capacity of approximately 113 MW. In addition, the Fund owns partnership, share and debt interests in three bio-mass fired generating facilities with combined installed capacity of approximately 70 MW located in Alberta, Quebec and Nova Scotia. The Fund holds minority term investments in two natural gas/wood waste-fired generating facilities with joint installed capacity of approximately 138 MW located in northern Ontario and a subordinated construction/term debt investment in a 99 MW wind generating facility currently being constructed near St. Leon, Manitoba. In addition to its electricity generating assets, Algonquin owns 15 regulated water distribution and water reclamation facilities in Arizona, Illinois, Missouri and Texas. The facilities are grouped into four business segments: hydroelectric segment, natural gas cogeneration segment, alternative fuel segment and infrastructure segment. See "Description of the Business -- The Developments ". The Fund may, where practical and economic, expand its current operations. All investment opportunities must meet established guidelines and are subject to review by the Trustees. Such facilities will only be acquired if the Fund believes that the acquisition will likely result in an increase in Distributable Cash per Trust Unit, otherwise meet the Fund's acquisition guidelines and is in accordance with the Fund's objectives, as set out in the Declaration of Trust. The Trustees believe that the stability and sustainability of cash flows to Unitholders may be enhanced through the diversification of the current asset portfolio. Opportunities providing long term, statistically predictable future cash flows whose risk profile is generally consistent with the existing portfolio of energy and infrastructure assets will be considered. See "Acquisition Guidelines". The management of the Manager has extensive experience and contacts in the independent power industry in Canada and the United States and is expected, but is not obligated, to continue presenting appropriate acquisition opportunities to the Fund. Under the terms of the revised management compensation structure implemented between the Manager and the Fund, the Manager will not be paid any acquisition or transaction related fees in respect of acquisitions by the Fund. See "Governance, Management and Operations". ACQUISITION GUIDELINES After consultation with and approval by the Trustees of the Fund, who have established certain acquisition guidelines which may change depending on circumstances, the Manager uses an acquisition strategy which targets energy and/or infrastructure facilities and employs the following guidelines in the review and evaluation of possible acquisitions: (a) each facility, development or group of developments will only be acquired if the Fund believes that the acquisition will provide a forecast internal rate of return that is greater than 200 basis points above the yield of long-term (20 year) Government of Canada bonds over the expected life of the facility after deducting operating costs, general, administrative and management expenses and incorporating the impact of debt financing, but before income taxes; (b) each facility, development or group of developments will only be acquired if the Fund believes that the acquisition will likely result in an increase in Distributable Cash per Trust Unit; -5- (c) facilities or a group of facilities for which no existing debt financing is in place will be preferred; (d) facilities where Power Systems or AWS will become the operator will be preferred; (e) facilities in respect of which long term power purchase agreements with major electrical utilities exist or facilities within a regulated utility will be preferred and in other cases, commodity price forecasts and exchange rate assumptions used in acquisition evaluations will reflect market expectations; (f) the acquisition of each facility, or development, will be based on an engineering report confirming the condition of each facility or each of the facilities within the development or group, as applicable, and the technical assumptions utilized in the acquisition evaluation; (g) for each facility in which an interest with an indefinite term is being acquired, the expected useful life of such facility and associated structures will, with regular maintenance, overhauls and upkeep, be not less than 20 years; and (h) the acquisition of each facility, or development, will be reviewed and approved by the Trustees. All acquisitions must be in accordance with the Declaration of Trust. THE MANAGER AND THE OPERATOR The Fund is managed by Algonquin Power Management Inc. Management of the Manager has extensive experience and contacts in the independent power industry in Canada and the United States and may, but is not obligated to, present appropriate acquisition opportunities to the Fund. The Manager is owned by the shareholders of Algonquin Power Corporation Inc. The Manager and its affiliates provide design, financing, construction, management, operation and maintenance of independent hydroelectric power facilities ranging in size from 130 to 18,000 kilowatts. The principals of the Manager together have over 50 years of experience in the industry. Power Systems, an affiliate of Algonquin Power, provides, on a cost-recovery basis, operations-related services in respect of the facility interests indirectly owned by the Fund. Power Systems is one of the largest operators of independent hydroelectric generating facilities in Canada. Power Systems supplies both direct operations services to the various facilities and operations supervisory services to Algonquin and its related entities. AWS operates, on a cost-recovery basis, the water and water reclamation facilities owned by the Fund. In addition to the principals of the Manager, the human resources of Power Systems, AWS and various subsidiaries of the Fund of over 300 individuals is comprised of engineers, technicians, biologists, professional managers and administrative support staff, including a field team of trained plant operators and field supervisors. The head office of Power Systems, located in Oakville, Ontario, provides technical and management support, regulatory compliance and budget and accounting control for field personnel undertaking plant improvements and repairs. Field staff are organized into regional groups, each with its own trained supervisor. Most of the facilities are outfitted with remote computer controls and systems which allow the plants to be operated remotely in the field or by head office personnel. Power Systems -6- also has data management systems to track the performance of the facilities, with a view to optimizing facility output. See "Governance, Management and Operations". PUBLIC OFFERINGS SINCE JANUARY 1, 2003 In June 2004, the Fund delivered an aggregate of 1,803,983 Trust Units in connection with the take-over bid by Algonquin Power Trust of the outstanding convertible debentures of KMS Power Income Fund not already owned by Algonquin Power Trust. See "General Development of the Business - Other Developments in Fiscal 2004". In July 2004, the Fund completed an offering of $85 million principal amount Fund Debentures. The Fund Debentures are due July 31, 2011 and bear interest at 6.65% per annum, payable semi-annually in arrears. The Fund Debentures are to be repaid in cash or Trust Units and will be convertible at any time up to maturity at the option of the holder into Trust Units of the Fund at a conversion price of $0.65 per Trust Unit. The Fund Debentures may not be redeemed by the Fund prior to July 31, 2007. Net proceeds from the Fund Debenture offering were used to repay the Fund's acquisition line of credit and to fund working capital. ACQUISITIONS OF FACILITIES IN FISCAL 2003 In February 2003, the Fund acquired the Litchfield Facility for $34.9 million (US$23.4 million) plus amounts with respect to growth in its customer base until 2007. As at the end of 2005, the Fund paid growth premiums to the seller of $13.2 million (US$10.4 million). In March 2003, the Fund acquired the Windsor Locks Facility for $44 million (US$30 million). The facility produces electricity sold to Connecticut Light and Power Company pursuant to a long-term power purchase agreement ending in 2010. In addition, the facility delivers steam energy and a portion of the electricity produced to a speciality fibre composites mill located adjacent to the facility. The purchase price paid for the facilities, the nature of the acquisition and the dates of acquisition are set out in the table below. Purchase Price Nature of Date of Facility (in thousands) Acquisition Acquisition - ---------------------- -------------- ----------- ----------------- Litchfield Facility $34,928(1) Shares February 25, 2003 Windsor Locks Facility $44,009 Assets March 10, 2003 Other $ 371(2) ------- Total $86,347 ------- Notes: (1) In addition, since the closing of the transaction, growth premiums have been paid to the seller of the Litchfield Facility of $13.2 million (US$10.4 million). -7- (2) Under the purchase and sale agreement for the Gold Canyon Facility, the Fund was required to make additional payments to the seller far each additional customer connected to the utility until July 2003. The Fund discharged this obligation in 2003 with a payment to the seller in the amount of $371,000 (US$265,000). OTHER DEVELOPMENTS IN FISCAL 2003 In May 2003, the Fund completed renegotiations with the Public Service Company of New Hampshire of the pricing terms of the power purchase agreements associated with the Fund's portfolio of small hydroelectric generating facilities in New Hampshire. This renegotiation resulted in total proceeds to the Fund of approximately US$20.4 million. Approximately US$2 million of these funds remain in escrow pending resolution of payment of certain lease obligations with the State of New Hampshire. Net proceeds from the transactions were used to pay down debt and fund working capital. The Fund will continue to own and operate these generating facilities and sell all the electric output from the facilities to PSNH at the ISO-New England, Inc. market rate. In May 2003, the Fund completed the major overhaul at the Sanger Facility at a cost of approximately $5.2 million (US$3.4 million). The higher than anticipated overhaul costs were the results of greater than expected wear and tear on the equipment. The Sanger Facility has returned to normal operating efficiency levels and the overhaul will be amortized over its expected life of six years. The Fund is currently assessing its alternatives in an effort to recover some of the costs incurred with respect to the overhaul. In 2005, the Fund has entered into a settlement agreement with the vendor and the former operator of the facility in connection with these higher than expected overhaul costs under which they agreed to pay the Fund US$50,000 and to offset certain liabilities of the Fund to the vendor. ACQUISITIONS OF FACILITIES IN FISCAL 2004 On September 30, 2004, the Fund acquired an interest in 12 landfill gas fired generating stations in California, Tennessee, New Jersey, New Hampshire and Minnesota representing approximately 36MW of installed capacity. The purchase price for these facilities was $11.7 million (US$9.3 million). The majority of these facilities were commissioned in the late 1990s. The electricity produced is sold to a number of large utilities pursuant to long-term power purchase agreements with an average termination date of 2011. Approximately 66% of the installed capacity of these facilities are located at large landfills which are continuing to accept waste, including three regional landfills permitted for operation for at least 25 years located in the southern California basin. A subsidiary of Algonquin America acquired the corporations which owned the generating assets of these facilities. The purchase price paid for these facilities, the nature of the acquisition and the date of acquisition are set out in the table below. Purchase Price Nature of Date of Facility (in thousands) Acquisition Acquisition - ------------------------ -------------- ------------ ------------------ Landfill gas fired generating facilities $11,374 Shares September 30, 2004 ------- Total $11,374 ======= OTHER DEVELOPMENTS IN FISCAL 2004 Pursuant to an agreement with Confederation Life Insurance Company, in liquidation dated -8- September 5, 2001, Algonquin Power Trust had acquired, among other interests, a 16.9% interest in the senior debt issued by Cardinal Power of Canada L.P. ("CARDINAL"). On April 30, 2004, after notice was given by the borrower, the outstanding loan of approximately $18.5 million at March 31, 2004 was repaid plus a prepayment fee of $3.7 million and accrued interest. As a result, the Fund has no further interest in Cardinal. During the first quarter of 2004, the Fund earned a break fee of $400,000 net of all expenses. The Fund was in negotiations to acquire a facility, but as a result of a right of first refusal between the vendor and another party, the facility was sold to the other party. This fee was recognized as other income. On May 19, 2004, Algonquin Power Trust, the sole unitholder of KMS, made a take-over bid (the "TAKE-OVER BID") for all of the outstanding principal amount of convertible debentures ($15,806,400) of KMS (the "KMS DEBENTURES") not already owned by Algonquin Power Trust. The Take-over Bid expired on June 25, 2004 and an aggregate of $13,661,500 principal amount of KMS Debentures were tendered to the Take-over Bid. The price offered for the KMS Debentures under the Take-over Bid was 11.4130 Trust Units of the Fund per $100 principal amount of KMS Debentures (inclusive of any accrued and unpaid interest thereon). Algonquin Power Trust took up and paid for all of the KMS Debentures tendered to the Take-over Bid by delivering an aggregate of 1,559,186 Trust Units of the Fund to the tendering debentureholders. On June 29, 2004, the debentureholders of KMS passed a special resolution to amend the trust indenture governing the KMS Debentures, to provide that, on the maturity date of the KMS Debentures (June 30, 2004), KMS Power Income Fund would deliver to debentureholders 11.4130 Trust Units of the Fund per $100 principal amount of KMS Debentures (inclusive of any accrued and unpaid interest thereon). An aggregate of $2,144,900 principal amount of KMS Debentures were not tendered to the Take-over Bid and remained outstanding until maturity. On the maturity date, KMS paid for such KMS Debentures by delivering an aggregate of 244,797 Trust Units of the Fund to the debentureholders who had not tendered their KMS Debentures to the Take-over Bid. KMS ceased to be a reporting issuer effective August 12, 2004. In October 2004, the Fund provided debt financing in the amount of $8.0 million (US$6.7 million) to Across America LFG LLC, a majority-owned subsidiary of a Fortune 500 company. Across America LFG LLC, through its subsidiaries, owns and manages the landfill gas collection systems which provide landfill gas to the LFG Facilities. On November 12, 2004, Algonquin Power Operating Trust provided a subordinated acquisition debt facility (the "AIRSOURCE ACQUISITION DEBT FACILITY") of approximately $4.9 million to AirSource Power Fund I LP ("AIRSOURCE") and a subordinated construction/term debt facility (the "ST. LEON GP CONSTRUCTION FACILITY") of approximately $64.4 million to St. Leon GP. AirSource subsequently completed an initial public offering of limited partnership units raising gross proceeds of approximately $65 million. AirSource used the net proceeds of the offering and the AirSource Acquisition Debt Facility to acquire the shares of St. Leon GP and the limited partnership interests of St. Leon LP, with the balance being used, in part, to finance construction of the St. Leon Facility near St. Leon, Manitoba. See "General Development of the Business - Other Developments in Fiscal 2005". ACQUISITIONS OF FACILITIES IN FISCAL 2005 In January 2005, the Fund, AWRA and certain of its subsidiaries entered into a purchase and sale agreement to acquire all the assets used in the operation of eight water distribution and water reclamation facilities from Silverleaf Resorts, Inc. The facilities, which in aggregate serve approximately 5,000 equivalent residential connections, are located in Texas, Missouri and Illinois. The acquisition of the five -9- Texas and Illinois facilities, was completed on March 11, 2005 for a cash consideration of $11.2 million (US$9.4 million). On August 14, 2005, the Fund received approval from the regulator in the state of Missouri and completed the acquisition of the three Missouri facilities for a cash consideration of $4.6 million (US$3.8 million). On September 21, 2005, the Fund purchased the Beaver Falls Hydro Plant, a 2.5 MW hydro electric generating station located in Beaver Falls, New York, for cash consideration of $1.0 million (US$0.8 million). Electrical energy produced by the facility is sold to Niagara Mohawk under a power purchase agreement which expires in 2019. On December 13, 2005, the Fund completed the acquisition of all of the issued and outstanding shares of Rio Rico Utilities Inc., which owns the Rio Rico Facility, for $10.2 million. The Rio Rico Facility provides water distribution and water reclamation services to approximately 5,400 residential water customers and 1,800 residential waste water customers in the town of Rio Rico, Arizona. The town of Rio Rico serves as a bedroom community for the City of Tucson and the City of Nogales, approximately 20 kilometres north of the Mexico-US border. The town of Rio Rico has been growing at an average annual rate of approximately nine percent (9%) over the past few years and this growth is expected to continue in the coming years. Purchase Price Nature of Facility (in thousands) Acquisition Date of Acquisition - ---------------------------------------- -------------- ----------- ------------------- Water and waste water systems facilities $11,200 Assets March 11, 2005 (Texas and Illinois) Water and waste water systems facilities $ 4,600 Assets August 14, 2005 (Missouri) Beaver Falls Facility $ 1,000 Assets September 21, 2005 Rio Rico Facility $10,200 Shares December 13, 2005 ------- Total $27,000 ======= OTHER DEVELOPMENTS IN FISCAL 2005 The Fund provided notice to the limited partners of the gas collection systems on April 11, 2005 and to the land fill operator on April 18, 2005 of its intention to terminate operations at the Joliet Facility, as it had become uneconomical to operate. The Joliet Facility was permanently closed on May 10, 2005. It is not expected that the closure of the Joliet Facility will adversely impact the fund, including Distributable Cash. On August 30, 2005, the Fund renewed its revolving credit facility with a syndicate of Canadian banks. The credit facility matures on August 30, 2007 and has a total credit limit of $145 million and includes a $20 million operating line. As of December 31, 2005, the Fund has drawn $69.3 million of the facility primarily to the fund the Fund's commitments to AirSource and St. Leon Wind Energy Trust. -10- On September 1, 2005, Algonquin Power Trust received payment of $4.8 million owing under the term loan owned by it in respect of the Campbellford Facility. Algonquin Power Trust is seeking recourse for the payment of the prepayment fee owing in connection with such payment and in this regard, Algonquin Power Trust has exercised its rights as pledgee of the units held by 740769 Ontario Inc. in the Campbellford Partnership and replaced 740769 Ontario Inc. with Algonquin Power Corporation (Campbellford) Inc. as the operating general partner of the Campbellford Partnership. 740769 Ontario Inc. disputes the validity of the appointment of the new operating general partner. The Campbellford Partnership has made an application for, among other things, a declaration by the court confirming that 740769 Ontario Inc. is not the operating general partner of the Campbellford Partnership and that the appointment of Algonquin Power Corporation (Campbellford) Inc. as the general partner of the Campbellford Partnership was valid. The application was heard on January 11, 2006 and the presiding judge directed a trial of the issue of who is the proper operating general partner of the Campbellford Partnership. In response to this application, 740769 Ontario Inc. commenced an action against Algonquin Power Trust, the Manager, Algonquin Power and others requesting, among other things, damages for conspiracy to injure in the amount of $4,000,000 and punitive damages in the amount of $1,000,000. A motion to strike has been served on counsel to 740769 Ontario Inc. The Fund is vigorously defending this action. However, it is too early in the lawsuit to determine the potential exposure to the Fund. On November 3, 2005, funds previously advanced by Algonquin Power Operating Trust under the St. Leon GP Construction Facility were repaid by AirSource upon the closing of its new senior debt facility. In the event of a default under the senior debt facility, Algonquin Power Operating Trust and the Fund will be obliged to advance the full amount of the St. Leon Trust Construction Facility in order to complete the St. Leon Facility and/or repay the senior debt facility. Concurrently with the repayment of the St. Leon GP Construction Facility, Algonquin Power Operating Trust provided a subordinated construction/term debt facility (the "ST. LEON TRUST CONSTRUCTION FACILITY") of approximately $69.4 million to St. Leon Trust. The AirSource Acquisition Debt Facility and the St. Leon Trust Construction Facility bear interest during construction of the St. Leon Facility at a rate of approximately 11.2% and at a rate of approximately 10.7% thereafter. These debt facilities mature on September 30, 2014 and are secured, on a subordinate basis, by all of the assets relating to the St. Leon Facility. The Fund's total commitment to AirSource and St. Leon Trust is $74.4 million in the aggregate. As of March 31, 2006, the Fund has advanced $44.5 million to AirSource in addition to providing letters of credit of $15.4 million, for a total advance of $59.9 million. On December 15, 2005, the Fund announced that a global settlement agreement had been reached with the United States Department of Justice and the Office of the United States Attorney in Concord, New Hampshire with respect to the loss of some hydraulic fluid at the Franklin Facility between January 31, 2001 and February 15, 2001. Under the settlement, Algonquin Power Systems - New Hampshire Inc., the operator of the facility, agreed to plead guilty to two misdemeanour charges and to pay a US$10,000 fine and a US$100,000 civil penalty relating to the event. -11- DESCRIPTION OF THE BUSINESS ----------- UNITHOLDERS ----------- | | ----------------- |----- TRUST UNITS (100% | ----------------- | --------------------------- ALGONQUIN POWER INCOME FUND---------------- NOTES -------------------------------------------------- --------------------------- ------------ | | | | SHARES (100% | | | | ------------ | | | | | | | ------------------------------------------------------------- | | | --------------------- | | | | | | NOTES AND TRUST UNITS | | ---------- | | | --------------------- | | ALGONQUIN | | | | | HOLDCO | | - --------------- ----------- | ---------- | | ALGONQUIN POWER ALGONQUIN | | ------------ | | (OR AFFILAITE) POWER TRUST | | |[Illegible] | | - --------------- ----------- | ---------- |----------- | | | | | ALGONQUIN ------ | | | | | CANADA | | - --------------------- | FACILITY ---------- | | MANAGEMENT AGREEMENTS | LEASERS |-- | | - --------------------- | | | | ------------------- ----------- | | | | |-----QUEBEC DEVELOPMENTS---[Illegible] | | - ----------------- | | | | ------------------ ----------- | | ENERGY FROM WASTE ----------------| | | | | | | - ----------------- | --------------------------------- | | | | | | -------------------- | | | | |-----ONTARIO DEVELOPMENTS | | - ------------------------- | | | -------------------- | | LSR SUBORDINATE NOTE | ---------------------------- ||-|------------| | | AND LSR ROYALTY INTERESTS | LONG SAULT RAPIDS FACILITIES---|- | ------------------------ | | - ------------------------- | NOTES AND SHARES | - NEWFOUNDLAND DEVELOPMENT | | | ---------------------------- | ------------------------ | | - -------------- | -------------------- | |------------| | | WESTERN CANADA | PARTNERSHIP INTEREST -----|-- ---------------- | | DEVELOPMENT --------------------| (45%) |---- ALGONQUIN AMERICA ----------------------------- | - -------------- | -------------------- ----------------- | | | --------- - ---------------------- | | TRAFALGAR WIND POWER DEVELOPMENT------------| -------------------- | CLASS E - ---------------------- | ALGONQUIN WATER | NOTES | RESOURCES OF AMERICA-----------------| --------- - ----------------- -------------------- | | SUBORDINATED NOTE | | ---------------------------------- | - ----------------- | | PARTNERSHIP + MEMBERSHIP INTERESTS | -------------------------- | | AND SHARES (100%) | WATER RECLAMATION AND -------- | ---------------------------------- | DISTRIBUTION DEVELOPMENTS | | | ------------------------- | | | | | ------------------------ | | -------------------------------- |--- NEW ENGLAND DEVELOPMENTS | |------------ PARTNERSHIP INTERESTS AND SHARES | ------------------------ | (100%) | | -------------------------------- | | | | | | | | | | | -------------------- -------------- | | | | ---------------------- ----------------------- | --------------------- | NOTES AND SHARES (100% ------ US THERMAL DEVELOPMENTS NEW YORK DEVELOPMENTS ---------------- ---------------------- ----------------------- --------------------- - ---------- Notes: (1) Interest provides 100% of cash flows up to 2013, 65% up to 2027 and 58% thereafter. (2) Interest provides 100% of cash flows up to 2010 with a right to 75% of the equity value upon repayment. (3) Interest in the Glenford Facility provides 100% of cash flows up to approximately 2023 after which the facility is owned by the Fund. (4) Subject to the Manager's Interest. -12- THE DEVELOPMENTS As at March 31, 2006, the Fund owns, directly or indirectly, debt, equity and royalty and other interests in 69 power generation facilities including those identified in "Other Interests in Energy Related Developments" and 15 regulated water distribution and reclamation facilities. For the year ended December 31, 2005, the Fund derived approximately 75.9% of its revenues from its interests in power generation facilities (76.6% in 2004), 7.3% of its revenues from waste disposal fees (8.8% in 2004) and 15.8% of its revenues from its interests in regulated water distribution and reclamation facilities (14.6% in 2004). POWER DEVELOPMENT ANNUAL AVERAGE YEAR OF EXPECTED EXPIRY OF GENERATING ENERGY POWER YEAR OF GENERATING CAPACITY 2006 POWER PURCHASE PRODUCTION PURCHASE EXPIRY OF FACILITY (KILOWATTS) LOCATION RATES(1) (MW-HRS) AGREEMENT LEASE - ------------------- ----------- ---------------- ------------------------ ---------- ---------- --------- ONTARIO DEVELOPMENTS Long Sault 18,000 Abitibi River Summer Energy 119,499 2047 2048 Rapids near Cochrane, $0.04076/kW-hr Facility Ontario Summer Capacity (Hydroelectric) $0.06296/kW-hr Winter Energy $0.04992/kW-hr Winter Capacity $0.08316/kW-hr Hurdman Dam 570 Mattawa River Paid on Hourly Spot 4,429 2015 2015 Facility near Mattawa, Market Price - blended (Hydroelectric) Ontario rate of approximately $0.055/kWhr Drag Lake Dam 220 Trent River Winter Peak $0.09343 0(7) 2012 Owned Facility near /kW-hr (Hydroelectric) Haliburton, WinterOff-Peak $0.03797 Ontario /kW-hr Summer Peak $0.07573 /kW-hr Summer Off-Peak $0.03375/kW-hr Burgess Dam 140 Muskoka River Winter Peak $0.0809 932(8) 2009 Month to Facility near Bala, /kW-hr Month (Hydroelectric) Ontario Winter Off-Peak $0.0319 Lease (2) /kW-hr Summer Peak $0.0752 /kW-hr Summer Off-Peak $0.0228 kW-hr -13- ANNUAL AVERAGE YEAR OF EXPECTED EXPIRY OF GENERATING ENERGY POWER YEAR OF GENERATING CAPACITY 2006 POWER PURCHASE PRODUCTION PURCHASE EXPIRY OF FACILITY (KILOWATTS) LOCATION RATES(1) (MW-HRS) AGREEMENT LEASE - ------------------- ----------- ---------------- ------------------------ ---------- ---------- --------- Campbellford 4,000 Trent River Winter On-Peak 27,834 2019 2019 Facility near $0.0961/kW-hr (Hydroelectric) Campbellford, Winter Off-Peak Ontario $0.0373/kW-hr Summer On-Peak $0.0797/kW-hr Summer Off-Peak $0.0326/kW-hr QUEBEC DEVELOPMENTS Saint-Alban 8,200 Ste-Anne River $0.06563/kW-hr (Jan- 37,260 2016 Month to Facility near the Village Nov) month(3) (Hydroelectric) of Saint-Alban, $0.06760/kW-hr (Dec) Quebec Glenford Facility 4,950 Ste-Anne River $0.06563/kW-hr (Jan- 24,593 2020 Owned (Hydroelectric) near the Village Nov) of Ste-Christine $0.06760/kW-hr(Dec) d'Auvergne, Quebec Rawdon Facility 2,500 Ouareau River $0.06563/kW-hr (Jan- 13,900 2014 2014 (Hydroelectric) near the Village Nov) of Rawdon, $0.06760/kW-hr(Dec) Quebec Cote Ste- 11,120 St. Lawrence Phase I Phase I: Phase I: 2009 Catherine Facility River near the Energy $0.05225/kW-hr 16,616 2009 (Hydroelectric) Town of Ste.- Catherine, Phase II Quebec Energy $0.05599/kW-hr Phase II: Phase II: Capacity 37,625 2018 $137.43/kilowatt(over the average kilowatt output over the period December to March) Phase III Phase III: Phase III: Energy $0.05830/kW-hr 37,247 2021 Capacity $144,10/kilowatt (over the average kilowatt output over the period December to March) Ste-Raphael 3,500 Riviere de Sud $0.06563/kW-hr (Jan- 25,035 2014 2013 Facility near Quebec Nov) (Hydroelectric) City, Quebec $0.06760/kW-hr (Dec) Mont Laurier 2,725 Riviere-du- $0.06856/kW-hr (Jan- 20,824 2007 2023 Facility Lievre in the Nov) (Hydroelectric) Town of Mont $0.06993/kW-hr (Dec) Laurier, Quebec Riviere-du-Loup 2,600 Riviere-du- $0.06563/kW-hr (Jan- 16,059 2015 2015 -14- ANNUAL AVERAGE YEAR OF EXPECTED EXPIRY OF GENERATING ENERGY POWER YEAR OF GENERATING CAPACITY 2006 POWER PURCHASE PRODUCTION PURCHASE EXPIRY OF FACILITY (KILOWATTS) LOCATION RATES(1) (MW-HRS) AGREEMENT LEASE - ------------------- ----------- ---------------- ------------------------ ---------- ---------- --------- Facility Loup near the Nov) (Hydroelectric) Town of $0.06760/kW-hr(Dec) Riviere-du- Loup, Quebec Hydraska Facility 2,250 Yamaska River Summer Energy 9,910 2014 2014 (Hydroelectric) near the Town $0.05519/kW-hr of St.- Winter Energy Hyacinthe, $0.10121/kW-hr Quebec Ste-Brigitte 4,200 Nicolet River in $0.06563/kW-hr (Jan- 12,367 2014 Owned Facility the Nov) (Hydroelectric) Municipality of $0.06760/kW-hr (Dec) Ste-Brigitte- des-Saults, Quebec Belleterre Facility 2,200 Winneway Summer Energy: 14,743 2013 2011 (Hydroelectric) River in the $0.05471/kW-hr Municipality of Winter Energy: Laforce, $0.09724/kW-hr Quebec Capacity: $135.21/kilowatt(over the average kilowatt output over the period December to March) Donnacona 4,800 Jacques Cartier $0.06563/kW-hr (Jan- 20,970 2022 2017 Facility River near Nov) (Hydroelectric) Donnacona, $0.06760/kW-hr(Dec) Quebec St. Raphael de 650 Riviere du Sud $0.06563/kW-hr(Jan- 2,782 2013 Owned Bellechasse downstream Nov) Facility From Ste- $0.06760/kW-hr (Dec) (Arthurville) Raphael (Hydroelectric) NEWFOUNDLAND DEVELOPMENT Rattle Brook 4,000 Rattle Brook Summer 17,470 2024 2048 Facility near Jackson's $0.06796/kW-hr (Hydroelectric) Arm, Winter Newfoundland $0.09341/kW-hr NEW YORK DEVELOPMENTS Ogdensburg 3,675 Oswegatchie US$0.05/kW-hr (est) (4) 10,596 2007 2038 Facility River near (Hydroelectric) Ogdensburg, New York Forestport 3,300 Black River US$0.05/kW-hr (est) (4) 10,016 2007 Owned -15- ANNUAL AVERAGE YEAR OF EXPECTED EXPIRY OF GENERATING ENERGY POWER YEAR OF GENERATING CAPACITY 2006 POWER PURCHASE PRODUCTION PURCHASE EXPIRY OF FACILITY (KILOWATTS) LOCATION RATES(1) (MW-HRS) AGREEMENT LEASE - ----------------- ----------- --------------- ------------------------ ---------- ---------- --------- Facility near Boonville, (Hydroelectric) New York Herkimer Facility 1,680 West Canada US$0.05/kW-hr(4) 4,363 2007 Owned (Hydroelectric) Creek near Herkimer, New York Christine Falls 850 Sacandaga US$0.05/kW-hr(est)(4) 3,065 2028 Owned Facility River near (Hydroelectric) Clifton, New York Cranberry Lake 500 Oswegatchie US$0.05/kW-hr(est)(4) 2,154 2025 2035 (Hydroelectric) River near Clifton, New York Kayuta Lake 400 Black River US$0.0102/kW-hr(est) 0(7) 2028 Owned Facility near Boonville, (Hydroelectric) New York Adams Facility 350 Sandy Creek US$0.0102/kW-hr(est) 0(7) 2028 Owned (Hydroelectric) near Adams, New York Kings Falls 1,750 Deer River near US$0.05/kW-hr(4) 3,680 2009 Owned Facility Copenhagen, (Hydroelectric) New York Otter Creek 530 Otter Creek in US$0.05/kW-hr(est)(4) 1,944 2009 Owned Facility Craig, New (Hydroelectric) York Phoenix Facility 3,500 Oswego River US$0.09205/kW-hr Flat 11,760 2026 Owned (Hydroelectric) in Phoenix, Rate New York Beaver Falls 2,500 Beaver River in US$0.03427/kW-hr(est) 11,448 2019 2008 Facility Beaver Falls, (Hydroelectric) New York Burt Dam Facility 600 18 Mile Creek US$0.05/kW-hr(est)(4) 2,300 2009 2036 (Hydroelectric) near Newfane, New York Hollow Dam 900 Oswegatchie US$0.05/kW-hr(est)(4) 4,400 2009 2026 Facility River near (Hydroelectric) Gouverneur, New York NEW ENGLAND DEVELOPMENTS Gregg Falls 3,500 Piscataquog US$0.058/kW-hr(est)(5) 10,083 60 day 2031 Facility River near the written (Hydroelectric) Town of notice Goffstown, New Hampshire -16- ANNUAL AVERAGE YEAR OF EXPECTED EXPIRY OF GENERATING ENERGY POWER YEAR OF GENERATING CAPACITY 2006 POWER PURCHASE PRODUCTION PURCHASE EXPIRY OF FACILITY (KILOWATTS) LOCATION RATES(1) (MW-HRS) AGREEMENT LEASE - ----------------- ----------- --------------- ------------------------ ---------- ---------- --------- Pembroke Facility 2,600 Suncook River US$0.058/kW-hr(est)(5) 8,272 60 day Owned (Hydroelectric) near the Town written of Pembroke, notice New Hampshire Clement Facility 2,400 Winnipisauhee US$0.058/kW-hr(est)(5) 11,288 60 day 2032 (Hydroelectric) River near the written Town of Tilton, notice New Hampshire Franklin Facility River Bend Winnipesaukee US$0.058/kW-hr(est)(5) River Bend 60 day Owned (Hydroelectric) 1,600 River near the 7,550 written Town of notice - Steven's Franklin, New US$0.058/kW-hr(est)(5) Steven's both sites Mill Hampshire Mill 1,020 200 Lochmere Facility 1,200 Winnipesaukee US$0.058/kW-hr(est)(5) 4,083 60 day 2033 (Hydroelectric) River near written Lochmere, New notice Hampshire Lower Robertson 960 Ashuelot River US$0.058/kW-hr(est)(5) 3,729 60 day Owned Facility near Hinsdale, written (Hydroelectric) New notice Hampshire Ashuelot Facility 900 Ashuelot River US$0.058/kW-hr(est)(5) 3,629 60 day 2040 (Hydroelectric) near Hinsdale, written New notice Hampshire Lakeport Facility 600 Winnipesaukee US$0.058/kW-hr(est)(5) 2,650 60 day 2032 (Hydroelectric) River near written Laconia, New notice Hampshire Avery Facility 260 Winnipesaukee US$0.058/kW-hr(est)(5) 1,834 60 day 2035 (Hydroelectric) River near written Laconia, New notice Hampshire Hadley Falls 250 Piscataquoq US$0.058/kW-hr (est)(5) 1,007 60 day 2016 Facility River near written (Hydroelectric) Goffstown, notice New Hampshire Hopkinton 250 Contoocook US$0.058/kW-hr(est)(5) 920 60 day 2023 Facility River near written (Hydroelectric) Hopkinton, notice New Hampshire Milton Facility 1,335 Salmon River US$0.058/kW-hr(est)(5) 6,166 60 day Owned (Hydroelectric) near the Town written of Milton, New notice -17- ANNUAL AVERAGE YEAR OF EXPECTED EXPIRY OF GENERATING ENERGY POWER YEAR OF GENERATING CAPACITY 2006 POWER PURCHASE PRODUCTION PURCHASE EXPIRY OF FACILITY (KILOWATTS) LOCATION RATES(1) (MW-HRS) AGREEMENT LEASE - ----------------- ----------- --------------- ------------------------ ---------- ---------- --------- Hampshire Mine Falls 3,000 Nashua River US$0.058/kW-hr(est) 10,717 60 day 2024 Facility near the City (5) written (Hydroelectric) of Nashua, New notice Hampshire Great Falls 10,950 Passaic River US$0.05/kW-hr(est) 19,322 60 day 2021 Facility near the City (5) written (Hydroelectric) of Paterson, notice New Jersey Worcester 180 Winnooskie Winter On-Peak 438 2016 Owned Facility River in US$0.1573/kW-hr (Hydroelectric) Worcester, Winter Off-Peak Vermont US$0.0864/kW-hr SummerOn-Peak US$0.0844/kW-hr Summer Off-Peak US$0.0386/ kW-hr Capacity Adder US$0.0192 /kW-hr Moretown 1,200 Mad River near Winter On-Peak 2,778 2018 Owned Facility Moretown, US$0.1078/kW-hr (Hydroelectric) Vermont Winter Off-Peak US$0.0682/kW-hr Summer On-Peak US$0.0978/kW-hr Summer Off-Peak US$0.0539/kW-hr Capacity Adder US$0.0243/kW-hr WESTERN CANADA DEVELOPMENTS Valley Power 12,000 Drayton Energy: $0.07093/kW-hr 87,000 2014 Owned (Biomass) Valley, Alberta Dickson Dam 15,000 Innisfail, Energy: $0.0619/kW-hr 67,248 2012 2030 (Hydroelectric) Alberta COGENERATION DEVELOPMENTS Sanger Facility 43,500 Sanger, Winter: Oct - April 77,000 2021 Owned (Cogeneration) California PG&E Avoided Cost US$0.07466/kW-hr (estimated average)* Summer: May - Sept US$0.05386/kW-hr (estimated average)* * subject to gas price -18- ANNUAL AVERAGE YEAR OF EXPECTED EXPIRY OF GENERATING 2006 POWER ENERGY POWER YEAR OF GENERATING CAPACITY PURCHASE PRODUCTION PURCHASE EXPIRY OF FACILITY (KILOWATTS) LOCATION RATES(1) (MW-HRS) AGREEMENT LEASE - --------------- ----------- --------------- ------------------------------- ---------- ---------- --------- indexing CAPACITY PAYMENT US$ 190 per kW /year up to 38,000 kW-hrs + bonus of l8% 80% earned May - Oct Windsor Locks 56,000 Windsor CLP 364,000 2010 2018 Facility Locks, onpeak - US$0.09691 /kW-hr* (Cogeneration) Connecticut offpeak - US$0.08097 /kW-hr* 980 Rate = market rate Mill/NGC US$0.061.4/kW-hr* Capacity $171,000** Steam-DNM/NGC US$9.11/10001bs* Capacity $107,000** * Estimated average rate, includes variable component based on natural gas prices ** Estimated average rate, charges are partially CPI indexed. Crossroads 10,000 Mahwah, New O & R OR 17,400 2008- 2016 Facility Jersey FIXED COMPONENT CDA 7,600 OEFC (Cogeneration} Onpeak/Mid-US$0.0995 /kW-hr (used two 2017- Offpeak-US$ 0.027 /kW-hr quarters) Industrial VARIABLE COMPONENT* US$ 0.0778 (Q106) * subject to gas price indexing CDA Energy -US$0.16112 Thermal US$8.374/mmbtu (January 06) Subject to gas price indexing -19- ANNUAL AVERAGE YEAR OF EXPECTED EXPIRY OF GENERATING 2006 POWER ENERGY POWER YEAR OF GENERATING CAPACITY PURCHASE PRODUCTION PURCHASE EXPIRY OF FACILITY (KILOWATTS) LOCATION RATES(1) (MW-HRS) AGREEMENT LEASE - --------------- ----------- --------------- ------------------------------- ---------- ---------- --------- THERMAL DEVELOPMENTS Prima Deschccha 6,100 San Juan US$ 0.04893/kW-hr 43,000 2007 2027 (Landfill Gas) Capistrano, (average estimate) California Tajiguas 3,050 Goleta, US$ 0.0632/kW-hr 21,500 2007 2018 (Landfill Gas) California (average estimate) Rate indexed to fuel price. Milliken 2,520 Ontario, US$0.05850/kW-hr + 14,800 2008 2008 (Landfill Gas) California California Energy Credits US$ 0.00675/kWhr Midvalley 2,520 Fontana, US$0.05850/kW hr + 16,400 2008 2008 (Landfill Gas) California California Energy Credits US$ 0.00675/kWhr Colton 1,250 Colton, US$ 0.06210/kW-hr 7,900 2008 2008 (Landfill Gas) California + 2% annual escalation + California Energy Credits US$ 0.00675/kWhr Bordeaux 1,900 Nashville, US$ 0.03672/kW hr 0(7) 2007+four 2007+four (Landfill Gas) Tennessee 4 year 4 year extensions extensions Balefill 3,800 Kearney, New US$ 0.05552/kW-hr 25,800 2006 2017 (Landfill Gas) Jersey (average estimate) PSE&G avoided costs +premium of 0.005/kW-hr Kingsland 2,900 North US$ 0.05579/kW-hr 15,200 2006 2017 (Landfill Gas) Arlington, (average estimate) New Jersey PSE&G avoided costs +premium of 0.005/kW-hr Four Hills 3,100 Nashua, New NE 19,200 2021 2024 (Suncook) Hampshire Onpeak/Mid - US$0.0665 (Landfill Gas) Offpeak-US$O.313 NH - US$ 0.0495 (est) Rate on an escalating scale plus capacity payment Burnsville 4,210 Burnsville, US$0.0165/kW-hr(est) 19,500 2015 2014 (Landfill Gas) Minnesota Excel Energy Avoided cost -20- ANNUAL AVERAGE YEAR OF EXPECTED EXPIRY OF GENERATING 2006 POWER ENERGY POWER YEAR OF GENERATING CAPACITY PURCHASE PRODUCTION PURCHASE EXPIRY OF FACILITY (KILOWATTS) LOCATION RATES(1) (MW-HRS) AGREEMENT LEASE - --------------- ----------- --------------- ------------------------------- ---------- ---------- --------- Capacity payment - US$ 40,000 monthly (est) Flying Cloud 4,890 Eden Prarie, US$0.0165/kW-hr(est) 0(7) 2021 2024 (Landfill Gas) Minnesota Excel Energy Avoided cost+ Capacity payment EFW Facility 10,100 Brampton, Winter Peak - 43,500 2012 Owned (Energy from Ontario $0.09687 /kW-hr Waste) Winter Offpeak - $0.0373/kW-hr Summer Peak - $0.08234/kW-hr Summer Offpeak - $0.0326/kW-hr Tipping- Peel - $84.00/tonne up to 127,900 tonnes, $60.82 tonnes thereafter Other - $146.59/tonne (average rate) Waste rates subject to CPI Increases WATER RECLAMATION AND DISTRIBUTION DEVELOPMENTS DECEMBER 31, 2005 UTILITY LOCATION TYPE OF UTILITY CONNECTIONS RATES - --------------- ----------------- ------------------ ------------ ---------------- Black Mountain Carefree, Arizona Water Reclamation 2,043 US$38.00/Month Gold Canyon Gold Canyon Water Reclamation 5,306 US$35.00/Month Arizona Bella Vista Sierra Vista, Water Distribution 7,778 US$27.41/Average Arizona monthly residential rate Tall Timbers Tyler, Texas Water Reclamation 1,091 US$40.08/Month Woodmark Tyler, Texas Water Reclamation 1,155 US$44.00/Month Litchfield Park Litchfield, Park, Water Reclamation 13,045 US$27.20/Month Arizona residential US$46.00/Month Commercial Water Distribution 13,416 US$19.25/Average monthly residential rate -21- DECEMBER 31, 2005 UTILITY LOCATION TYPE OF UTILITY CONNECTIONS RATES - ----------------- ------------------ ------------------ ------------ -------------------- Fox River Sheridan, Illinois Water Reclamation 219 currently no charge Water Distribution 220 US$ 120.25 flat rate Timber Creek DeSoto, Missouri Water Reclamation 24 US$6.00 min & $7.57/1000 gal. Water Distribution 29 US$3.00 min. & $3.02/1000 gal Holliday Hills Branson, Water Distribution 470 US$3.00 min. & Missouri $3.02/1000 gal Ozark Mountain Kimberling City, Water Reclamation 230 US$6.00 min & Missouri $7.57/1000 gal. Water Distribution 249 US$3.00 min. & $3.02/1000 gal Holly Lake Ranch Big Sandy, Texas Water Reclamation 149 US$68.39 min & $5.05/1000 gal. Water Distribution 1822 US$21.36 min. & $1.94/1000 gal Big Eddy Flint, Texas Water Reclamation 345 US$68.39 min & $5.05/1000 gal. Water Distribution 590 US$21.36 min. & $1.94/1000 gal Piney Shores Conroe, Texas Water Reclamation 181 US$68.39 min & $5.05/1000 gal. Water Distribution 186 US$21.36min. & $1.94/1000 gal Hill Country New Braunfels, Water Reclamation 305 US$68.39 min & Texas $5.05/1000 gal. Water Distribution 236 US$21.36 min. & $1.94/1000 gal Rio Rico Rio Rico, Water Reclamation 1,818 US$59.20 residential Arizona rates Water Distribution 5,402 US$9.65 min. & 0-4,000 gal - US$1.44/1,000 gal 4,001-10,000 gal - US$ 1.70/1,000 gal >10,000 gal - US$1.90/1,000 gal Notes: (1) 2006 power purchase rates have been rounded to four decimals and are not representative of long term power purchase rates under the applicable power purchase agreements. Long-term rates under different agreements will be both higher and lower than current rates. Seasonal periods and daily periods vary from project to project. (2) Burgess Dam - No agreement has been obtained for a long-term lease; it is still on a month-to-month lease. (3) St. Alban - A long-term lease is currently being finalized and is expected to be concluded in 2006. (4) These rates have been changed to the Avoided Costs of Niagara Mohawk. (5) The Fund has renegotiated with PSNH the pricing terms of the power purchase agreements. PSNH will continue to purchase the energy produced by these generating stations at the ISO-New England, Inc. market rates. These agreements are cancellable on 60 days written notice. (6) These rates have been changed to the Avoided Costs of Commonwealth Edison Company, effective February 2004. (7) Offline for repairs in 2005. No decision has been made as to the timing of repairing this facility. -22- (8) One unit is offline for repairs until summer 2006. The Fund also has notes receivable and equity in companies which own five generating facilities, including a wind power facility. See "Other Interests in Energy-Related Developments". ONTARIO DEVELOPMENTS - LONG SAULT RAPIDS, HURDMAN DAM, DRAG LAKE DAM, BURGESS DAM AND CAMPBELLFORD FACILITIES LONG SAULT RAPIDS FACILITY The Long Sault Rapids Facility is an 18,000 kilowatt hydroelectric generating facility located on the Abitibi River, 19 kilometres north of the Town of Cochrane, in northern Ontario. The facility was commissioned on April 1, 1998. The facility was developed by a joint venture between Algonquin Power (Long Sault) Partnership and N-R Power Partnership. The facility is owned by the Co-Owners as tenants-in-common and not as joint tenants, with the Co-Owners each having an undivided 50% interest in the facility. The partners in the Algonquin Power (Long Sault) Partnership, Algonquin Power (Long Sault) Corporation Inc. and Energy Acquisition (Long Sault) Ltd., are wholly-owned subsidiaries of Algonquin Power. The partners in the N-R Power Partnership are Nicholls Holdings Inc. and Radtke Holdings Inc., companies controlled by two independent businessmen. There are two non-recourse loans outstanding which are secured against the facility and the Co-Owners' interest therein (see "Ontario Development - Long Sault Rapids Facility - Credit Agreements" below). The facility includes a 125 meter long rock filled dam that crosses the Abitibi River. The dam has created a narrow headpond approximately ten kilometres in length. The facility is a run-of-the-river facility and the headpond will not be utilized for storage and peaking purposes. The powerhouse is an integrated structure, housing four pit turbine generating units each rated at 4,500 kilowatts of generating capacity which were manufactured by Sulzer Canada Inc. Electricity produced by the facility is sold directly to OEFC for distribution to its customers by means of a 23.5 kilometre 115 kV transmission line, which crosses both private property and provincially owned land pursuant to easements, rights of way and land use permits. Rights to all necessary lands have been obtained in order to construct, operate and maintain the transmission line. Power Purchase Agreement Pursuant to the terms of the power purchase agreement, the Co-Owners sell power produced by the facility exclusively to OEFC. The power purchase agreement terminates 50 years from the commercial in-service date, April 1, 1998, and may be renewed for a further term upon request by either party on terms and conditions to be mutually agreed. The agreement provides that the payment made by OEFC for power produced by the facility is calculated as the sum of the monthly capacity payment and the monthly energy payment. The monthly capacity payment is calculated as the product of the number of On-peak hours for the month and the sum of the applicable energy and capacity rates. The monthly energy payment is the product of Off-peak hours and the applicable energy rate. The rates are escalated annually based on an index figure tied to the greater of OEFC's all customer rate or direct customer rate. The agreement provides that the rates will not decrease based on this index. -23- The Co-Owners will not receive a monthly capacity payment unless the facility delivers an average of at least 1,800 kilowatts of power to OEFC during at least 85% or more of the On-peak period fifteen minute intervals for that month. The monthly payment from OEFC will now include an amount for any monthly capacity power delivered in excess of target generation specified in the agreement. The amount for any monthly energy in excess of 115% of target generation is specified in the new additional agreement. Waterpower Lease The waterpower lease with the Province of Ontario in respect of the dam site expires in 2048. The lease provides for an annual land rental and an annual water rental charge. The water rental charge will not commence until 10 years after the commissioning of the generating station (2008). Partnership Agreements There are partnership agreements governing the affairs of both Co-Owners. The provisions of each partnership agreement are virtually identical. The partnerships were formed for the purpose of carrying on the business of financing, holding and operating undivided interests in the facility. Co-Owners Agreement and Management Agreement The Co-Owners have entered into an agreement concerning, among other things, their holding of undivided interests in the facility. Upon the occurrence of specified events of default, the non-defaulting Co-Owner may purchase the defaulting Co-Owner's interest for 90% of the fair market value. The Co-Owners have entered into a management agreement with NR-Algonquin Energy Management Inc. to manage the facility on their behalf for nominal consideration. Credit Agreements There is an outstanding senior loan against the facility in the amount of $42,868,000 at December 31, 2005. The loan was provided by a syndicate comprised of The Clarica Life Insurance Company ("CLARICA"), The Canada Life Assurance Company and The Maritime Life Assurance Company. Clarica acts as agent for the syndicate. The loan has a term of 30 years, maturing in December 2028 and bears interest at an interest rate of 10.36% for the first 15 years and 10.21% thereafter, compounded annually. Blended payments of principal and interest are made monthly. The loan is non-recourse and is secured by the facility and the ownership interests therein. Under the terms of the credit agreement, a debt reserve is required. At December 31, 2005, the debt reserve was fully funded and contained a balance of $1.2 million. The LSR Subordinate Note is also an outstanding loan against the facility which the Fund currently owns. HURDMAN DAM, DRAG LAKE DAM AND BURGESS DAM FACILITIES The Drag Lake Dam facility, with a generating capacity of 225 kilowatts is located on the Trent River at the Drag Lake Dam, in Haliburton, Ontario. This facility is currently offline for repairs. No decision has been made as to the timing of repairing the facility. The resulting loss of Distributable Cash is insignificant to the Fund. -24- The Burgess Dam facility, with a generating capacity of 130 kilowatts, is located at the outlet of Lake Muskoka River at Moon River, in Bala, Ontario. This facility currently has one turbine offline for repairs. This turbine is scheduled to be repaired during the summer of 2006. The resulting loss of Distributable Cash is insignificant to the Fund. The Hurdman Dam facility, with a generating capacity of 570 kilowatts, is located on the Mattawa River, two kilometres upstream from the Town of Mattawa, Ontario. These three facilities are owned by Algonquin Canada. Power Purchase Agreements Pursuant to the terms of the power purchase agreements for the Drag Lake Dam and Burgess Dam facilities, each facility will sell all power produced at such facility exclusively to OEFC and OEFC agrees to purchase all such power. The initial term of the agreement (a) for the Drag Lake Dam facility is 20 years commencing in March 1992; and (b) for the Burgess Dam facility is 20 years commencing in August, 1989. The Hurdman Dam facility sells all power produced at the facility to Hydro One Inc. pursuant to a power purchase agreement which expires in January 2016 Land and Water Rights For the Hurdman Dam facility, the waterpower renewal lease agreement with the Province of Ontario, providing for waterpower and land usage rights, expires in 2015 with two further 10 year renewal terms. Upon expiry or termination of the lease, improvements on the site become the property of the Province of Ontario upon payment of the value of such improvements. Water levels must be maintained as specified in the lease. The lease is subject to termination if the power purchase agreement is terminated. With respect to the Drag Lake Dam facility, the land on which the powerhouse and penstock are located is owned by Algonquin Canada. The dam site is licenced from the Trent-Severn Waterway. The Burgess Dam facility lease for the facility site with The Corporation of the Township of Muskoka Lakes expired on April 30, 1998 and the Manager is currently negotiating a renewal with the Township. The Township has agreed to extend the lease on a month-to-month basis during the negotiations. The lease includes the water rights owned by the Township and under the direction of the Ontario Ministry of Natural Resources. Rights to all necessary lands have been obtained in order to operate and maintain the transmission lines for the facilities. CAMPBELLFORD FACILITY The Campbellford Facility is a 4,000 kilowatt hydroelectric generating facility located at Lock No. 14 on the Trent-Severn Waterway approximately four kilometres north of Campbellford, Ontario. This facility was an expansion project by the Town of Campbellford and the Fund to the existing 2,100 kilowatt generating station owned by the town. The expansion was completed in late 1993 and commissioned in January 1994. The facility is owned by Algonquin Power (Campbellford) Limited Partnership, a limited partnership of which Algonquin Power Trust owns all of the Class B units as a limited partner, representing 50% of the equity of the partnership. See also "Developments of the Business - Other Developments ". -25- The facility is a run-of-the-river facility that consists of a shared 240 meter power canal leading to a concrete powerhouse housing two S-Kaplan double regulated turbines. Land and Water Rights The Town of Campbellford has a lease from the Government of Canada which gives the municipality the rights to all the available water in excess of that required for navigation at Lock No. 14 on the Trent-Severn Waterway. In addition to the water, the Town of Campbellford also has a lease for the land adjacent to Lock No. 14 where the Campbellford Facility was developed. In 1991, the Town of Campbellford entered into an arrangement with an Algonquin Power entity to develop the under-utilized water resources at the Lock No. 14 site on the Trent-Severn Waterway. The Town of Campbellford subleased the necessary lands and water rights to the Algonquin Power entity to allow it to build the Campbellford Facility. The arrangement is for 25 years from the commencement of the agreement, being March 8, 1994. At the conclusion of the term, the plant and equipment will be turned over to the Town of Campbellford. On November 15, 1994, the Campbellford Facility was granted by Environment Canada - Parks Services, under the Dominion Water Act, a licence to operate a low head hydro power facility at Lock No. 14 on the Trent River. The term of the approval is 30 years, commencing July 1, 1994 and ending June 30, 2024. Power Purchase Agreement The agreement has a term of 25 years commencing March 10, 1994. Under the agreement, the fixed rates will be paid to the producer annually for the initial 10 years of the term. In the 11th and subsequent years, the rates shall be reviewed by the power purchaser and only increased if authorized by the power purchaser. There was no increase in rates in 2005. The rates will never be less than those applicable in the first 10 years. Under a contract with the local utility, some of the energy is wheeled to the local utility. QUEBEC DEVELOPMENTS -- SAINT-ALBAN, GLENFORD, RAWDON, COTE STE-CATHERINE, STE-RAPHAEL, MONT LAURIER, RIVIERE-DU-LOUP, HYDRASKA, STE-BRIGITTE, BELLETERRE, DONNACONA, AND ST. RAPHAEL DE BELLCHASSE FACILITIES. Power Purchase Agreements - General The Quebec Developments have power purchase agreements with Hydro-Quebec under which all power generated by the facilities is sold to Hydro-Quebec. The standard Hydro-Quebec power purchase agreement stipulates annual minimum energy production requirements in each contract year. Under most Hydro-Quebec power purchase agreements, if a facility produces less energy than the minimum, a penalty is payable to Hydro-Quebec. The facility can opt to reduce any energy production shortfall over a two year period using energy produced in excess of the minimum requirement, after which, a penalty is payable on any outstanding amounts at the current year prices. The power purchase agreement for the Hydraska Facility does not include any penalty provisions. Power purchase rates under the Hydro-Quebec agreements (other than for the Mont Laurier and Cote Ste-Catherine (Phase I) Facilities) increase in accordance with the Consumer Price Index for the Montreal Urban Community, as published by Statistics Canada, with a minimum annual escalation of 3% and a maximum annual escalation of 6%. The Mont Laurier Facility is subject to a maximum annual -26- escalation of 5.2%. The Cote Ste-Catherine Facility (Phase I) is subject to a maximum annual escalation of 6%. SAINT-ALBAN FACILITY The facility is an 8,200 kilowatt hydroelectric generating facility located on the Ste-Anne River approximately one kilometre from the Village of Saint-Alban, Quebec and approximately 200 kilometres east of Montreal. The facility is located at the site of a decommissioned hydroelectric generating facility previously owned by Hydro-Quebec. The facility consists of a newly gated spillway and the existing dam and spillway, which were rehabilitated and reconditioned in 1996, two penstocks, a powerhouse structure and a tailrace canal and has been designed as a run-of-the-river facility. Land and Water Rights The land upon which the facility is located is currently owned by the Government of Quebec, although certain hydraulic rights are owned by Shawinigan Electric Company, a wholly-owned subsidiary of Hydro-Quebec. The Government of Quebec is in the process of acquiring all outstanding hydraulic rights from Shawinigan Electric Company. Once this process is complete, it is anticipated that the Government of Quebec will enter into a final 20 year lease agreement with SLI from the facility's commissioning date in 1996. SLI is presently negotiating the terms of the final lease agreement with the Government of Quebec. The long term lease has not been finalized; however, an agreement is expected in 2006. It is expected that the lease will expire in 2016 and will be retroactive to the commissioning date of the facility in 1996. The facility operates under an Order-in-Council of the Government of Quebec. In addition to contractual lease payments and other amounts payable to the Government of Quebec, an annual royalty is payable in respect of the Saint-Alban municipal park. Approval from the Government of Quebec to the transfer of the leasehold interests from SLI to Algonquin Canada has been sought and should be obtained following signature of the final lease agreement. Acquisition of legal title to this facility is expected to be completed once the lease has been finalized by SLI. GLENFORD FACILITY The facility is a 4,950 kilowatt hydroelectric generating facility located on the Ste-Anne River approximately one kilometre from the Village of Ste-Christine d'Auvergne, Quebec and approximately 230 kilometres east of Montreal. The facility is located at the site of a decommissioned hydroelectric generating facility previously owned by Hydro-Quebec. The facility consists of the existing dam and spillway, which were rehabilitated and reconditioned in 1995, an intake, powerhouse and tailrace structure and has been designed as a run-of-the-river facility. The Glenford Facility is owned by the Glenford Partnership. Land and Water Rights The Glenford Facility has been constructed on certain lands purchased by the Glenford Partnership and which lands include the existing structures associated with the historic generating facility. In addition, certain easements were granted to the former owner in respect of flooding rights and the access road. The land owned by the Glenford Partnership includes the bed of the river upon which the existing dam structure is located and certain lands on either side of the river. Accordingly, no lease from the Province of Quebec is required. -27- Credit Agreement The Glenford Senior Debt is an outstanding senior loan provided to the Glenford Partnership in the amount of $5.3 million at December 31, 2005. The loan was provided by Corpfinance International Limited and has a term of 25 years which commenced in April 1995. The loan is to be repaid in equal monthly payments of $63,591 representing blended interest and principal during its term. The loan is secured solely by the facility and the ownership interests therein, A hydrology reserve fund with a balance as at December 31, 2005 of $178,000 has been established to provide additional security in respect of the payment of interest and principal on the Glenford Senior Debt. Under the terms of the credit agreement, such reserve is required to be increased at the rate of 9% on an annual basis. A maintenance reserve fund with a balance as at December 31, 2005 of $29,000 has been established in respect of major capital expenditures which may be incurred by the Glenford Partnership. RAWDON FACILITY The facility is a 2,500 kilowatt hydroelectric generating facility located on the Ouareau River approximately one kilometre from the Village of Rawdon, Quebec and approximately 70 kilometres north of Montreal. The facility consists of an existing dam (which was rehabilitated and reconditioned in 1986 by Hydro-Quebec), intake, spillway, penstock, powerhouse and tailrace structure and has been designed as a run-of-the-river facility. The Rawdon Facility is owned by Algonquin Canada. Land and Water Rights The land upon which the facility is located and the hydraulic rights necessary for the operation of the facility are leased from the Ministry of Natural Resources, Quebec pursuant to a 20 year lease agreement. The lease expires in June 2014 and includes a renewal option for an additional 20 year period, exercisable by the lessee upon mutually acceptable terms. The lease may be terminated by the Province of Quebec upon, among other events, termination of the power purchase agreement for the facility with Hydro-Quebec or transfer of the leasehold interest without approval of the landlord. Saint-Alban, Glenford and Rawdon Power Purchase Agreements The term of the power purchase agreements for the Rawdon Facility and the Saint-Alban Facility is 20 years from the commercial start-up date and is 25 years from the commercial start-up date for the Glenford Facility. The power purchase agreements expire in 2014, 2016 and 2020 for the Rawdon, Saint-Alban and Glenford Facilities, respectively. The agreements may be renewed at the option of the generator for a period not exceeding the original term upon mutually acceptable terms. COTE STE-CATHERINE FACILITY The Cote Ste-Catherine Facility is located at the Cote Ste-Catherine lock of the Lachine section of the St. Lawrence Seaway. The bypass canal upon which the facility is located was constructed as part of the St. Lawrence Seaway in 1958. The facility has a total installed capacity of 11,120 kilowatts and was constructed in three separate phases, each phase having a total installed capacity of 2,120 kilowatts, 4,500 kilowatts and 4,500 kilowatts, respectively, and each phase was commissioned in 1989, 1993 and 1996, respectively. Due to the year round, high volume water flows of the St. Lawrence River, the Manager expects there to be sufficient water to operate the Cote Ste-Catherine Facility at full capacity throughout the year. The Cote Ste-Catherine Facility uses approximately 2% of the river flow at any given time. The facility is owned by Algonquin Power (Mont-Laurier) Limited Partnership. -28- Land and Water Rights The land and water rights necessary for the construction and operation of the Cote Ste-Catherine Facility have been obtained from the St. Lawrence Seaway Authority by way of a lease agreement dated March 1, 1988, as amended. The lease agreement will expire on February 28, 2009. The lease can be extended for an additional period of 21 years upon the lessee giving 6 months notice. The facility is located on a federal waterway. However, the Province of Quebec has asserted jurisdiction over the water rights to this facility. STE-RAPHAEL FACILITY The Ste-Raphael Facility is a 3,500 kilowatt facility located on the Riviere de Sud approximately 60 kilometres east of Quebec City, Quebec. The site was formerly developed by Hydro Quebec and then released by the Ministry of Energy (Quebec), for private development in 1991. The site was rebuilt by a former owner and placed back into operation in January 1994. The facility is owned by Algonquin Canada. Land and Water Rights The land and hydraulic rights necessary for the operation of the facility have been leased by the Ministry of Natural Resources and the Ministry of Environment (Quebec) pursuant to a lease agreement dated December 14, 1993. The lease will expire on December 14, 2013 and may be renewed for an additional period of 20 years at the option of the lessee upon terms imposed by the government. MONT LAURIER FACILITY The Mont Laurier Facility is a 2,725 kilowatt facility located on the Riviere-du-Lievre in the Town of Mont Laurier, Quebec. The site has been historically utilized for the production of power and was refurbished in 1989. The rehabilitation included extensive repairs to the civil works, rebuilding of all three turbines and replacement of all electrical and control works. Land and Water Rights The facility is constructed on lands owned by MTL Partnership. Water rights necessary for the operation of the facility have been leased from the Ministry of Natural Resources (Quebec) pursuant to a lease agreement dated March 23, 1988 and assigned to the MTL Partnership on October 31, 1994. The term of the lease expires on December 31, 2023. RIVIERE-DU-LOUP FACILITY The Riviere-du-Loup Facility is located on the Riviere-du-Loup in close proximity to the downtown section of the Town of Riviere-du-Loup, Quebec. The site has been historically utilized for the production of power and was decommissioned in 1977. A major refurbishment undertaken in 1995 included complete rehabilitation of the civil works, installation of a new turbine, rebuilding of two existing turbines and replacement of all electrical and control works. The installed capacity of the plant has been increased to 2,600 kilowatts. The facility is owned by Algonquin Canada. Land and Water Rights The land and hydraulic rights necessary for the operation of the facility have been leased from the Ministry of Natural Resources and the Ministry of the Environment (Quebec) pursuant to a lease -29- agreement dated November 20, 1997. The lease terminates on October 22, 2015. The lease can be extended for an additional period of 20 years at the option of the lessee upon terms imposed by the government. HYDRASKA FACILITY The Hydraska Facility is located on the Yamaska River at Penmans Dam near the Town of St-Hyacinthe, Quebec. Construction on the site commenced in 1993 and commissioning was successfully completed in May 1994. The civil works include a 250 meter long tailrace canal and have been designed to be attractively integrated into the park in which the site is located. The capacity of the plant is 2,250 kilowatts. The facility is owned by Algonquin Power Trust. Land and Water Rights The land rights and existing structures on the site are leased from the City of St-Hyacinthe pursuant to a 20 year lease agreement dated August 30, 1993, the term of which commenced in May 1994. The lease can be extended on the same terms for an additional period of 20 years at the option of the lessee. The hydraulic rights necessary for the operation of the facility have been leased by the lessee from the Ministry of Natural Resources and the Ministry of the Environment (Quebec) pursuant to a lease agreement dated March 24, 1994. The lease terminates on May 23, 2014 and may be renewed for an additional period of 20 years at the option of the lessee upon terms imposed by the government. Cote Ste-Catherine, Ste-Raphael, Mont Laurier, Riviere-du-Loup and Hydraska Power Purchase Agreements The term of the power purchase agreements for each of the Cote Ste-Catherine - Phase I, Hydraska, Ste-Raphael, Mont Laurier and Riviere-du-Loup facilities is 20 years from the commercial start-up date and is 25 years from the commercial start-up date for the Cote Ste-Catherine - Phase II and Cote Ste-Catherine - Phase III facilities. For the Cote Ste-Catherine Facility Phases I, II and III, the power purchase agreements expire in 2009, 2018 and 2021, respectively. The expiry dates for the power purchase agreements for the Mont Laurier, Hydraska, Ste-Raphael, and Riviere-du-Loup facilities are 2007, 2014, 2014 and 2015, respectively. The agreements may be renewed at the option of the producer for a period not exceeding the original term upon terms imposed by Hydro-Quebec. In 2005, the Ste-Raphael Facility failed to meet its minimum production obligations under its power purchase agreement. The facility has opted to reduce the energy production shortfall over a two year period using excess energy production. Should the facility be unable to reduce the energy production shortfall, a penalty will be assessed by Hydro-Quebec on the outstanding balance in 2007. STE-BRIGITTE FACILITY The Ste-Brigitte Facility is a 4,200 kilowatt hydroelectric generating facility located on the Nicolet River, in the Municipality of Ste-Brigitte-des-Saults, Quebec. The facility is located at the site of an historic mill, but none of the original structures have been utilized for the new powerhouse. The site layout involves an intake canal equipped with a gate structure, a powerhouse containing a single 4,200 kilowatt turbine generator and a tailrace canal which conveys the waterflow back to the natural watercourse. It has been designed as a run-of-the-river facility. The facility incorporates a 1.1 metre high movable dam utilized to increase available water level differential. The facility is owned by Algonquin Canada. -30- Land and Water Rights Algonquin Canada owns the facility site, and easements in respect of the access road, transmission line and Hydro-Quebec interconnection. The land includes the bed of the river upon which the existing weir structure is located and land on either side of the river. On May 10, 2002, certain upstream residents of the Ste-Brigitte Facility commenced an action in the Quebec Supreme Court against certain Fund entities and others claiming in excess of $5 million as a result of a flood event which occurred on April 13, 2001. The flood apparently resulted from an ice jam upstream from the facility that flooded properties near the river. In addition to the claim for damages, the plaintiffs are seeking an order requiring that the facility cease operation and that it be removed. The Fund entities are vigorously defending the action. BELLETERRE FACILITY The Belleterre Facility is a 2,200 kilowatt hydroelectric generating facility located on the Winneway River, in the Municipality of Laforce, Quebec. The facility is located at the point of discharge of the Winneway River into Lac Simard/Lac des Quinzes. Commissioning of the Belleterre Facility involved the rehabilitation of a generating facility constructed in the 1930s to supply power to local mining operations. The rehabilitation work included replacement of the turbine-generating equipment, restoration of site structures, including the penstock and gates, and replacement/recomrnissioning of the electrical interconnection to the Hydro-Quebec grid. The rehabilitation and recommissioning was completed and the facility was brought into commercial service with Hydro-Quebec in March 1993. The facility is owned by Algonquin Canada. Land and Water Rights The land and water rights necessary for the Belleterre Facility were originally leased from the Province of Quebec to the Town of Belleterre pursuant to a lease dated July 17, 1991. The lease expires in December 2011 and includes a renewal option for an additional 20 year period, exercisable by the lessee upon terms imposed by the Province of Quebec. The lease may be terminated by the Province of Quebec upon, among other events, termination of the power purchase agreement for the facility with Hydro-Quebec. The Town of Belleterre is entitled to an annual payment from the facility equal to a percentage of the gross revenues earned by the facility from the sale of energy to Hydro-Quebec. Ste-Brigitte and Belleterre Power Purchase Agreements The Ste-Brigitte Facility agreement expires in 2014 and the Belleterre Facility agreement expires in 2013. The agreements may be renewed at the option of the producer for a period not exceeding the original 20 year term upon terms imposed by Hydro-Quebec. DONNACONA FACILITY The Donnacona Facility is a 4,800 kilowatt hydroelectric generating facility located on the lower portion of the Jacques Cartier River, near the Town of Donnacona, Quebec. The Jacques Cartier River flows south and empties into the St. Lawrence River approximately 60 kilometres west of Quebec City, Quebec. The facility was constructed at the site of an existing dam and is located on property purchased from Alliance Forest Products Inc./Produits Forestiers Alliance Inc. ("ALLIANCE"). The powerhouse houses eight identical 600 kilowatt turbine generators. Construction commenced in April 1996 and the -31- facility was commissioned in December 1996. Electricity produced by the facility is delivered to the Hydro-Quebec distribution system. The facility is owned by the Donnacona Partnership, of which all of the partnership interests are held directly or indirectly by Algonquin Canada. Power Purchase Agreement The power purchase agreement for the facility has a term of 25 years, expiring in 2022. The agreement may be renewed at the option of the Donnacona Partnership for a period not exceeding the original 25 year term upon terms to be negotiated. Hydro-Quebec can veto the renewal, but only if the Donnacona Partnership is in default of a material term of the agreement. Land and Water Rights The real property interest required for the construction and operation of the facility consists of a deed of transfer of certain land and easement rights obtained from Alliance in April 1996. In addition to the land, the existing dam structure, the bed of the Jacques Cartier River upstream of the facility and the natural hydraulic forces of that part of the river were transferred to the Donnacona Partnership. Under the deed of transfer, the Donnacona Partnership agrees to allow water flows in the Jacques Cartier River of up to 2.25 cubic metres per second to be utilized by Alliance for the Donnacona paper mill located approximately one kilometre from the facility site until such time as a permanent pumping system is conveyed by the Donnacona Partnership to Alliance. During construction, the deed of transfer required the partnership to design and install a temporary water pumping system to supply the Alliance mill with water if there was a problem with the existing gravity water supply system. This temporary pumping equipment was then transferred to Alliance and the equipment is located in a building on the site. The Donnacona Partnership also has the obligation to construct a permanent pumping station in the unlikely event there is a permanent failure of the existing dam and the existing gravity water supply system is permanently disrupted. The deed of transfer grants the Donnacona Partnership certain easements across land retained by Alliance, which easements are required to allow access to the dam and other structures located near the powerhouse. Under the terms of the deed of transfer, the Donnacona Partnership has agreed, among other things, to maintain the dam in good condition and maintain certain insurance which will protect Alliance against loss of water caused by negligence of the Donnacona Partnership until completion of a permanent pumping facility. The Donnacona Partnership has entered into a lease with the Province of Quebec in respect of a section of the bed of the river upstream from the facility and water rights relating to the Jacques Cartier River necessary for the operation of the facility which expires on February 6, 2017. The lease includes a renewal option for an additional 20 year period, exercisable at the request of the Donnacona Partnership upon terms imposed by the Province of Quebec. Rights to all necessary lands have been obtained in order to operate and maintain the transmission line for the facility. ST. RAPHAEL DE BELLECHASSE FACILITY The St. Raphael de Bellechasse Facility is a 650 kilowatt hydroelectric generating facility located on the Du Sud River near Saint-Raphael de Bellechasse, approximately 40 kilometres east of Quebec City. The site was originally developed in the late 1700s as a sawmill, and later, in the early 1900s as a flourmill. The facility was commissioned as a hydroelectric generating facility in 1993. The powerhouse -32- building is estimated to be approximately 230 years old. The facility is owned by Algonquin Power Trust. This run-of-the-river facility consists of a concrete gravity dam and spillway that spans the river, an intake, two penstocks, a stone masonry powerhouse and a tailrace canal. Land and Water Rights The St. Raphael de Bellechasse Facility is constructed on private land, such that the generator owns the land and the associated hydraulic forces. The land owned includes the bed of the river upon which the existing spillway is located. Accordingly, no water lease with the Province of Quebec is required. Power Purchase Agreement The power purchase agreement for the facility has a term of 20 years, expiring in 2013. NEWFOUNDLAND DEVELOPMENT - RATTLE BROOK FACILITY RATTLE BROOK FACILITY The facility is a 4,000 kilowatt hydroelectric generating facility located on Rattle Brook, approximately four kilometres north of the Town of Jackson's Arm, in the Province of Newfoundland. Construction commenced in September 1997 and the facility was commissioned in December 1998. The facility is owned by Rattle Brook Partnership. The facility is a run-of-the-river facility and there is no storage of water for peaking purposes. A penstock runs 1,100 metres from a small dam to the powerhouse. The powerhouse is a single storey building which houses a single horizontal turbine attached to a synchronous air cooled generator. The interconnection point for delivery of electricity to the power purchaser is adjacent to the facility and therefore no transmission line is included. Laud and Water Rights All necessary land and water rights and environmental approvals have been obtained by the Rattle Brook Partnership, including a 50 year lease from the Province of Newfoundland for use of the land required by the facility. Power Purchase Agreement Electricity produced by the facility is sold directly to Newfoundland and Labrador Hydro. Pursuant to the power purchase agreement, Newfoundland and Labrador Hydro agrees to purchase all power delivered to the interconnection point and the Rattle Brook Partnership agrees to sell all power produced by the facility to Newfoundland and Labrador Hydro. The power purchase agreement is for a term of 25 years from the commercial in-service date, which occurred on October 23, 1998, and may be renewed for a further term of 25 years upon terms mutually agreed. The power purchase agreement provides that payments made by Newfoundland and Labrador Hydro consists of two components: a capacity component and an energy component, for each of the -33- winter period and the summer period. The energy component is adjusted annually by the change in the Consumer Price Index for Canada, provided that any escalation does not exceed 6% year over year. The capacity component is fixed and is not escalated over the term of the power purchase agreement. Partnership Agreement The partnership agreement between Algonquin Power Corporation (Rattle Brook) Inc. and Algonquin Canada governs the affairs of the Rattle Brook Partnership. The partnership agreement specifies, inter alia, that income allocations, cash distributions and voting rights at meetings of the partners will be divided as to 55% to be equally divided among the four shareholders of the Manager and 45% to Algonquin Canada. Generally, management decisions for the partnership are made by majority vote of the partners. Certain matters, including capital expansion of the facility, disposition of the facility by the partnership and dissolution of the partnership, require unanimous consent of the partners. NEW YORK DEVELOPMENT - OGDENSBURG, FORESTPORT, HERKIMER, CHRISTINE FALLS, CRANBERRY LAKE, KAYUTA LAKE, ADAMS, KINGS FALLS, OTTER CREEK, PHOENIX, BEAVER FALLS, BURT DAM AND HOLLOW DAM FACILITIES TRAFALGAR POWER, INC. AND CHRISTINE FALLS CORPORATION The Trafalgar Companies are controlled by the same independent businessman and own seven hydroelectric generating facilities located in upper New York State. The Ogdensburg Facility, Forestport Facility, Herkimer Facility, Cranberry Lake Facility, Kayuta Lake Facility and the Adams Facility are owned by Trafalgar and the Christine Falls Facility is owned by Christine Falls Corporation. Each of the facilities has received a licence or a licence exemption from FERC and sell electricity to Niagara Mohawk pursuant to separate power purchase agreements. These agreements are either front-end loaded, whereby the rate paid by Niagara Mohawk is high in the early years to enable the developer to recoup its capital costs and is adjusted downward in later years to compensate for the overpayment based on the balance in a tracking account set up for such purpose, or specified rate, whereby the rate is as set out in the agreement in the early years and thereafter is set as a percentage of Niagara Mohawk's Avoided Costs. Niagara Mohawk has the right to suspend its obligations under such agreements if its transmission system is unable to accept power generated from the facilities. It also retains a right of first refusal to negotiate the acquisition of a facility in the event of a proposed disposition thereof. The Trafalgar Companies must maintain such facilities in good working order, maintain the interconnection with Niagara Mohawk's transmission system and provide insurance coverage. Trafalgar Operations Subcontract Under the Trafalgar Operations Contract, Algonquin Power provides the Trafalgar Companies with certain services in respect of the Trafalgar Facilities. Under the Trafalgar Operations Subcontract, Algonquin Canada provides, on a subcontractor basis, Algonquin Power services required in respect of the operation of the Trafalgar Facilities. As consideration for these services, Algonquin Canada is entitled to receive monthly payments in respect of its operating costs in providing such services and an annual payment for the Trafalgar Contingency Participation. Power Systems has assumed responsibility for providing the operations services required by the Trafalgar Facilities. Power Systems' compensation does not include any portion of the Trafalgar Contingency Participation. Until the holder of the Trafalgar Class B Note has received aggregate payments above a cumulative target, the Trafalgar Contingency Participation will be equal to 50% of Trafalgar Operating Cashflows up to certain annual targets and 10% of cash flows above those targets. After the holder of the Trafalgar Class B Note has received aggregate payments exceeding such certain cumulative target, the -34- Trafalgar Contingency Participation will be equal to 33% of Trafalgar Operating Cashflows. Trafalgar Class B Note The Fund acquired the Trafalgar Class B Note on December 23, 1997. The Trafalgar Class B Note was issued jointly and severally by the Trafalgar Companies pursuant to the Trafalgar Indenture. It bears interest at the rate of 6.10% per annum. It is secured by a charge against all assets of the Trafalgar Companies including, without limitation, the generating equipment comprising the Trafalgar Facilities and the interest in the key contracts held by the Trafalgar Companies for the operation of the Trafalgar Facilities. Under the terms of the Trafalgar Indenture, until the holder of the Trafalgar Class B Note has received aggregate payments exceeding a certain cumulative target, 50% of Trafalgar Operating Cashflows in amounts up to certain annual targets, and 90% of cash flows above those targets, will be paid to the holder of the Trafalgar Class B Note on account of interest and principal. After the holder of the Trafalgar Class B Note has received aggregate payments exceeding such cumulative target, 33% of Trafalgar Operating Cashflows will be paid to the holder of the Trafalgar Class B Note on account of interest and principal payments. Under the terms of the various securities purchased and agreements entered into by the Fund and Algonquin Canada, the Fund is indirectly entitled to a 100% interest in the cash flows generated from the Trafalgar Facilities up to the year 2010 and thereafter until all amounts outstanding under such note are repaid if the Trafalgar Companies elect not to repay the Trafalgar Class B Note. If the Trafalgar Companies fully repay the Trafalgar Class B Note upon its maturity on December 31, 2010, the Fund will receive a payment equal to 75% of the equity value of the Trafalgar Facilities, expected to be satisfied by delivery of a 75% equity interest in the Trafalgar Companies. In August 1999, the Fund and Algonquin Canada declared the Trafalgar Class B Note in default, accelerated the indebtedness represented by the Note and initiated foreclosure proceedings. The outstanding balance of the Trafalgar Class B Note as at December 31, 2005 was approximately $US23.0 million. Trafalgar commenced an action in New York District Court against the Fund, Algonquin Canada, Algonquin Power and Aetna Life Insurance Company ("AETNA") in connection with the sale of the Trafalgar Class B Note by Aetna to the Fund and Algonquin Canada and the Fund's foreclosure on the security for the Trafalgar Class B Note. The Manager believes that this case is without merit. In a separate action, Trafalgar obtained a judgment against a third party and received an award of approximately US$10 million. The Fund has made a claim against this award. On August 27, 2001, Trafalgar and Marina Development, Inc. (the sole shareholder of the Trafalgar Companies) filed for bankruptcy protection. As a result of the bankruptcy proceedings, all revenue generated by the Trafalgar Facilities are being held as part of the estate of Trafalgar, together with the amount of the US$10 million judgment award. All operating expenses are being paid from these amounts. Based on the current power rates, the facilities are operating at a small positive operating cash flow (see discussion under "The Developments - New England Development - Franklin Facility"). As a result of a settlement of the lawsuit at the Franklin Facility, US$2.75 million of these funds are to be paid to the Fund upon the conclusion of the Trafalgar dispute, irrespective of the outcome of the Trafalgar dispute. -35- Although the Manager paid one half of the external legal fees incurred up to July 1, 2002 with respect to this dispute, the Fund is funding the litigation. In the event of a recovery by the Fund of all or part of the funds, the Fund and the Manager will divide such amounts in proportion to the amount of legal fees funded, after reimbursement of expenses. OGDENSBURG FACILITY The facility is located on the Oswegatchie River, in the City of Ogdensburg, New York. The facility was built at an existing concrete dam located immediately upstream of the St. Lawrence River. The dam is owned by the City of Ogdensburg and is used by Trafalgar under an agreement with the City. It is a run-of-the-river facility. The facility is rated at 3,675 kilowatts. The facility has five bevel geared, double regulated Kaplan turbines. Power Purchase Agreement The agreement is for a term of 20 years from the commencement of commercial operations, which occurred on December 15, 1987. For the period January 1, 2001 through December 31, 2007, power purchase rates are equal to Niagara Mohawk's Avoided Costs plus a capacity payment. FERC Licence The facility received a forty year licence (Major Project) for a 3,675 kilowatt hydroelectric generating facility from FERC on June 15, 1987 (FERC Project No. 9821). The facility was commissioned on December 18, 1987. The main compliance conditions associated with the facility are that: (i) it must operate as an instantaneous run-of-the-river facility; and (ii) the FERC licence requires a complex and strict minimum flow regime. The first 183 cubic feet per second through the site is spilled over the dam. River flow between 183 to 733 cubic feet per second is discharged through turbine No. 5 which is directed towards the base of the dam and maintains a minimum flow along the downstream reach of the facility. Flows greater than 733 cubic feet per second are discharged through the remaining four turbines, but Turbine No. 5 must always discharge the maximum 733 cubic feet per second. FORESTPORT FACILITY The facility is rated at 3,300 kilowatts and is located on an existing canal system along the Black River, near the Town of Boonville, which is located about 30 kilometres north of Utica, New York. The canal system is owned and maintained by the New York State Thruway Authority/Canal Corporation and is used mainly by recreational canoers. The facility generates electricity from flows from both the Black River and Alder Creek. The powerhouse is located adjacent to the canal and water is diverted to it by a steel penstock. The powerhouse includes a conventional, horizontal "S" type Kaplan turbine generator set. After passing through the turbine, water is discharged into the Black River. Power Purchase Agreement The agreement is for a term of 20 years from commencement of commercial operations which occurred on December 30, 1987. From the period January 1, 2001 through the remainder of the term, the power purchase rates are equal to Niagara Mohawk's Avoided Costs plus a capacity payment. -36- FERC Licence The facility received a forty year licence (Major - Existing Dam) for a 3,300 kilowatt hydroelectric facility producing power from one turbine from FERC on March 20, 1987 (FERC Project No. 4900). The facility was commissioned in October 1988. The main compliance conditions associated with the facility are that: (i) it must operate as an instantaneous run-of-the-river facility; and (ii) a minimum flow of 140 cubic feet per second must be released downstream of the dam at all times. The minimum flow requirements are based on recommendations from federal and state regulatory agencies. The NYSTA/CC operates the barge canal system and has required an additional minimum flow within the canal for recreation. As a result, an additional 30 cubic feet per second is discharged into the canal during the summer months. HERKIMER FACILITY The facility is located on West Canada Creek, upstream of the Village of Herkimer, New York. The facility is rated at 1,680 kilowatts. The facility is located at a new concrete dam and overflow structure. There are four siphon-type turbine generators and one vertical turbine generator installed at the facility. Power Purchase Agreement The power purchase agreement with Niagara Mohawk has a term of 20 years from the commencement of commercial operations on December 29, 1987. From the period January 1, 2001 through the remainder of the contract term on December 31, 2007, the power purchase rates are equal to Niagara Mohawk's Avoided Costs plus a capacity payment. FERC Licence The facility received a forty year licence (Major Project) for a 1,680 kilowatt hydroelectric generating facility from FERC on April 22, 1987 (FERC Project No. 9709). The facility was commissioned in February 1988. The main compliance conditions associated with the facility are that: (i) it must operate as an instantaneous run-of-the-river facility; (ii) the producer is required to install and maintain stream gauging stations for the purpose of measuring the stage and flow of the river; and (iii) a minimum flow of 160 cubic feet per second be released downstream of the dam at all times. CHRISTINE FALLS FACILITY The facility is located on the Sacandaga River approximately eight kilometres east of the Town of Specular, which is located within the Adirondack Mountain State Park, in upper New York State. The facility is rated at 850 kilowatts and consists of two horizontal shaft, Francis turbine/generators. The site was previously developed by Niagara Mohawk and was rehabilitated by Christine Falls Corporation. Water from the Sacandaga River is diverted to the plant at an existing concrete dam through a small intake structure and steel penstock. The total head at the site is 15 metres. It is a run-of-the-river facility. Power is delivered to the utility grid at Highway 30. -37- Power Purchase Agreement The agreement has a term of 40 years, ending in January 2028. The facility commenced commercial operations on April 15, 1988. Currently, power purchase rates are equal to Niagara Mohawk's Avoided Costs. For years 19 through 30, power purchase rates will be equal to 90% of Niagara Mohawk's Avoided Costs. For the remainder of the term, power purchase rates will be equal to 80% of Niagara Mohawk's Avoided Costs plus a capacity payment. FERC Licence The facility received a forty year licence (Minor Project) for a hydroelectric generating facility from FERC on October 18, 1983 (FERC Project No. 4639). The original licence was amended to 850 kilowatts on February 15, 1989. The facility was commissioned in April 1988. The main compliance conditions associated with the facility are that: (i) it must operate as an instantaneous run-of-the-river facility; and (ii) a minimum flow of 25 cubic feet per second must be released downstream of the dam during March, April and May and ten cubic feet per second must be released at all other times of the year. The minimum flow is controlled through a small valve in the dam. CRANBERRY LAKE FACILITY The facility is located on the Oswegatchie River, at the outlet of Cranberry Lake, in the Town of Clifton, New York. The facility is located on land and utilizes water that is leased pursuant to a long term agreement with the Oswegatchie River Cranberry Reservoir Regulating District (OR-CRRD) dated October 19, 1987 and expires in 2035. The facility is rated at 500 kilowatts and is a run-of-the-river facility using flow available from Cranberry Lake. The facility was constructed within the existing dam structure at the outlet of the lake. The facility configuration includes an ESAC bulb-type turbine generator set in a small powerhouse. The facility is interconnected to Niagara Mohawk's grid immediately at the facility gate. Power Purchase Agreement The agreement has a term ending December 31, 2025. Commercial operations commenced on December 31, 1987. From the current period through December 31, 2010, power purchase rates are equal to 90% of Niagara Mohawk's Avoided Costs. For the remainder of the term, power purchase rates will be equal to 80% of Niagara Mohawk's Avoided Costs plus a capacity payment. FERC Licence The Cranberry Lake Facility received a forty year licence (Minor Project) for a 595 kilowatt hydroelectric generating facility from FERC on April 27, 1987 (FERC Project No. 9685). The facility was commissioned in May 1988. The facility is required to operate according to the direction of the OR-CRRD, which determines the water level of Cranberry Lake and, therefore determines the water flow available for generation. The main compliance condition associated with the facility is that it must operate as an instantaneous run-of-the-river facility. KAYUTA LAKE FACILITY The facility is rated at 400 kilowatts. The facility is located on the Black River at the outlet of Kayuta Lake. The site is immediately upstream of the Forestport facility, in the Town of Boonville, New York. The site was developed at an existing concrete control structure at the outlet of Kayuta Lake. It is -38- a run-of-the-river facility with the powerhouse built around an ESAC bulb-type turbine generator set located adjacent to the dam. The facility interconnects with the utility grid immediately at the facility fence. During 2005, the facility experienced mechanical failure and is not currently in operation. No decision has been made as to the timing of repairing the facility. The resulting loss of Distributable Cash is insignificant to the Fund. Power Purchase Agreement The agreement is for a term of 40 years ending January 2028. Commercial operations commenced on January 1, 1988. Power purchase rates are front-end loaded. Power purchase rates will be equal to Niagara Mohawk's Avoided Costs until year 22 of the term and 95% of Niagara Mohawk's Avoided Costs for years 23 through 30. These rates have been reduced to eliminate the balance in the Advance Payment Account. The balance in the Advance Payment Account as at December 31, 2005 was $729,000 (US$625,000). During the period following the 31st year, power purchase rates will be equal to 90% of Niagara Mohawk's Avoided Costs, without adjustment. The agreement specifies that, at the end of the 30th year, the unrepaid balance of the Advance Payment Account must be paid to Niagara Mohawk, if the balance is positive, or to the facility, if the balance is negative. Given the current status of the Advance Payment Account, it is expected that a large payment will have to be made to Niagara Mohawk at the end of the 30th year if Trafalgar wishes to retain the facility. Niagara Mohawk has a lien on the facility to secure any positive balance in the Advance Payment Account, which lien is subordinate to the security under the Trafalgar Indenture. FERC Licence The facility received a forty year licence (Minor Project) for a hydroelectric generating facility from FERC on September 12, 1984 (FERC Project No. 5000). The facility is built at the outlet of Kayuta Lake at the site of an existing control structure. The facility was commissioned in March 1988. The main compliance condition associated with the facility is that it must operate as an instantaneous run-of-the-river facility. ADAMS FACILITY The facility is a 350 kilowatt hydroelectric generating facility located on Sandy Creek, in the Village of Adams, New York. It is a run-of-the-river facility located at an existing concrete dam structure. A small powerhouse located at the dam houses an ESAC bulb-type turbine generator set. Electricity produced by the facility is connected to the Niagara Mohawk grid at the facility fence. During 2003, the facility experienced mechanical failure and is not currently in operation. No decision has been made as to the timing of repairing the facility. The resulting loss of Distributable Cash is insignificant to the Fund. Power Purchase Agreement The power purchase agreement for the Adams facility has a term of 40 years ending January 2028. The facility commenced commercial operations on January 1, 1988. Power purchase rates under the agreement are front-end loaded. Power purchase rates are equal to Niagara Mohawk's Avoided Costs until year 22 of the term and 95% of Niagara Mohawk's Avoided Costs for years 23 through 30. These rates have been reduced to eliminate the balance in the Advance Payment Account. The balance in the Advance Payment Account as at December 31, 2005 was $512,000 (US$439,000). -39- During the period following the 31st year, the facility will be paid a rate equal to 90% of Niagara Mohawk's Avoided Costs, without adjustment. The agreement provides that, at the end of the 30th year, the unrepaid balance of the Advance Payment Account must be paid to Niagara Mohawk, if the balance is positive, or to the facility, if the balance is negative. Given the current status of the Advance Payment Account, it is expected that a large payment will have to be made to Niagara Mohawk at the end of the 30th year if Trafalgar wishes to retain the facility. Niagara Mohawk has a lien on the facility to secure any positive balance in the Advance Payment Account, which lien is subordinate to the security under the Trafalgar Indenture. FERC Licence The facility received an exemption from the licensing of a 358 kilowatt hydroelectric generating facility from FERC on July 12, 1983 (FERC Project No. 6878). The facility was commissioned in December 1987. The main compliance conditions associated with the facility are that: (i) it must operate as an instantaneous run-of-the-river facility; and (ii) a minimum flow of 15 cubic feet per second must be released downstream of the dam, when available. KINGS FALLS FACILITY The facility is located on the Deer River, near Copenhagen in Lewis County, New York, approximately 300 feet upstream from Kings Falls. It is a run-of-the-river facility and is rated at 1,750 kilowatts. The facility has one Waplins Vertical Kaplan turbine. The facility is owned by Tug Hill Energy Inc., a subsidiary of Algonquin America. Power Purchase Agreement A three-year power purchase agreement was signed with Niagara Mohawk, expiring in 2009. Power purchase rates are equal to Niagara Mohawk's Avoided Costs plus an ancillary payment for station service costs. Land and Water Rights Tug Hill Energy Inc. acquired all land necessary for the operation of the facility. As a result of its ownership of the generating station site, Tug Hill Energy Inc. was granted the water rights for the facility. FERC Licence The facility received a licence (Minor Project) for a hydroelectric generating facility from the FERC on September 30, 1986. An order approving transfer of licence to Tug Hill Energy Inc. was granted by FERC on June 30, 2000. The facility was commissioned in 1988. The main compliance conditions associated with the facility are that: (i) it must operate as an instantaneous run-of-the-river facility; and (ii) the FERC licence requires a minimum flow of eight cubic feet per second year round. The minimum flow is required for fisheries and water quality and was based on recommendations from applicable regulatory agencies. OTTER CREEK FACILITY The facility is located on the Otter Creek, near Craig, New York. The facility is located at a rehabilitated stone and masonry dam with a concrete overlay about 115 feet long. It is a run-of-river -40- facility and is rated at 530 kilowatts. The facility has one Ossberger Cross- Flow turbine. The facility is owned by Tug Hill Energy Inc. Power Purchase Agreement A three-year power purchase agreement was signed with Niagara Mohawk, expiring in 2009. Power purchase rates are equal to Niagara Mohawk's Avoided Costs plus an ancillary payment for station service costs. Land and Water Rights Tug Hill Energy Inc. acquired all land necessary for the operation of the facility. As a result of its ownership of the generating station site, Tug Hill Energy Inc. was granted water rights for the facility. FERC Licence The facility received an exemption from licensing for a less than 5,000 kilowatt hydroelectric generating facility from FERC on September 9, 1985. The facility was commissioned in 1986. The main compliance conditions associated with the facility are that: (i) it must operate as an instantaneous run-of-the-river facility; (ii) there is a minimum flow requirement of 52 cubic feet per second year round to the natural streambed; the minimum flow requirements are based on recommendations from applicable regulatory agencies; and (iii) there is a fish bypass pipe which must pass water at 44 cubic feet per second to the natural streambed. PHOENIX FACILITY The facility is located on the Oswego River, in the Town of Phoenix, Onondaga County, New York. The facility is located at an 866 foot long concrete ogee spillway which is owned by New York State Thruway/Canal Corporation. It is a run-of-the-river facility and is rated at 3,500 kilowatts. The facility has two ESAC single regulated turbines. This facility is owned by Oswego Hydro Partners L.P. Power Purchase Agreement The original agreement was dated September 19, 1989 and had a term of 40 years from the date of issuance of the project licence by FERC. Therefore, from March 28, 1986 until March 28, 2026, the specified settlement rates set out in the agreement will be paid. The agreement requires maintenance of an adjustment account based on the difference between the specified rate and 90% of the long run Avoided Costs. The agreement states that the obligation to repay this balance in the adjustment account expires on expiry of the term of the agreement. Land and Water Rights Oswego Hydro Partners holds certain permanent easements on land and buildings used by the facility. The Phoenix Facility is located at the Oswego Canal Lock No. 1 on the Oswego River. The dam, reservoir and navigation lock are owned by the State of New York and are operated and maintained by the NYSTA/CC. The lock is operated by the NYSTA/CC and is open from April through October. However, the NYSTA/CC and Oswego Hydro Partners have an agreement to allow the facility operator to operate and be responsible for three Rodney-Hunt gates at the center of the dam. -41- FERC Licence The facility received a licence for a 3,500 kilowatt hydroelectric generating facility from FERC on March 28, 1986. The facility was commissioned in December 1990. The main compliance conditions associated with the facility are that: (i) it must operate as an instantaneous run-of-the-river facility; and (ii) the FERC licence requires a complex and strict minimum flow regime. FERC has provided an order amending the minimum flow requirements, which requires certain discharges over the flashboards, spillway crest or from the tainter gates to maintain dissolved oxygen below the Phoenix dam. BEAVER FALLS FACILITY The facility is consists of two power plants located approximately 100 metres apart on the Black River in the town of Beaver Falls, NY. The upper plant consists of a single 1.5 MW Kaplan vertical unit and the lower plant consists of 2 Francis vertical units rated at 500 kW each. Power is transmitted across the river to a substation that is jointly operated by the plant and a local paper company. The upper facility was installed in 1937, while the lower facility was installed in 1979. Power Purchase Agreement The agreement is for a term of 34 years from commencement of commercial operations in April, 1985. Power purchase rates are equal to 70% of Niagara Mohawk's Avoided Costs until June, 2010, and thereafter, 65% of the Avoided Costs. FERC Licence The facility received the licence for the 1500 kilowatt upper hydroelectric facility from FERC on April 19, 1985 and the licence for the 1000 kilowatt lower hydroelectric facility on October 18, 1979. The main compliance conditions associated with the facilities are that: (i) they must operate as instantaneous run-of-the-river facilities; and (ii) both facilities must have a minimum flow of 88 cubic feet per second that must be released over the spillway before the generating units can operate. The minimum flow requirements are based on recommendations from federal and state regulatory agencies. BURT DAM FACILITY The facility is a 600 kilowatt hydroelectric generating facility located on the Eighteen Mile Creek in the Town of Newfane, New York. The facility consists of a dam with an integrated intake structure, powerhouse and tailrace and is designed to operate as a run-of-the-river facility. The facility was reconstructed in 1987 from an old hydroelectric generating facility. The facility is owned by the Burt Dam Partnership, of which Algonquin America and Algonquin America Holdco are the partners. Power Purchase Agreement The power purchase agreement with Niagara Mohawk expires in 2009. Power purchase rates are equal to Niagara Mohawk's Avoided Costs plus an ancillary payment for station service costs. -42- Land and Water Rights The land and certain facility structures are leased. The lease agreement is for a term equal to the greater of 50 years or the term of the FERC licence. Payment is based on a percentage of net income from the facility. The Eighteen Mile Creek has been identified as one of six areas of concern in New York State by the Water Quality Board of the International Joint Commission due to high levels of chemicals in the sediments within the river, mainly PCBs and dioxins. A Remedial Action Plan was jointly developed by the New York State Department of Environmental Conservation (NYDEC) and SLI, the former owner, to provide environmental protection at this site. The Remedial Action Plan does not affect day-to-day operations of the facility, but the program will have to be considered if major works are required to be constructed with respect to the facility in and around the watercourse. FERC Licence The facility received an exemption from licensing for a less than 5,000 kilowatt hydroelectric generating facility from FERC on May 15, 1986 (FERC Project No. 7477). The facility was commissioned in 1988. The main compliance conditions associated with the facility are that: (i) it must operate as an instantaneous run-of-the-river facility; and (ii) if the NYDEC proceeds with a salmon stocking program, the Burt Dam Partnership must provide a flow over the dam to provide for downstream passage of fish. NYDEC has stated that it presently has no plans to stock Eighteen Mile Creek. HOLLOW DAM FACILITY The facility is located on the West Branch of the Oswegatchie River in the Town of Fowler, New York, approximately 16 kilometres south of Gouverneur, New York. The facility is rated at 900 kilowatts. The facility was constructed in 1987 and is located at an existing dam of 100 metres in length and includes a 70 metre spillway. The facility is equipped with two submersible Flygt turbine/generators, each capable of generating 450 kilowatts. The facility is owned by the Hollow Dam Partnership, of which Algonquin America and Algonquin America Holdco are the partners. Power Purchase Agreement The power purchase agreement with Niagara Mohawk expires in 2009. Power purchase rates are equal to Niagara Mohawk's Avoided Costs plus an ancillary payment for station service costs. Land and Water Rights The facility was built in 1987 on leased land pursuant to a long term lease agreement dated December 13, 1988. The lease has been assigned to the Hollow Dam Partnership. The agreement provides that all lands and facilities revert back to the landlord on April 26, 2026. FERC Licence The facility received a licence for a 1,000 kilowatt hydroelectricity generating facility from FERC on May 30, 1986 (FERC Project No. 6972). -43- The main compliance conditions associated with the facility are that: (i) it must operate as an instantaneous run-of-the-river facility; and (ii) pursuant to an amending order dated February 27, 1990, the facility must maintain a minimum flow of 21 cubic feet per second by ensuring the water levels within the headpond are not lower than an elevation of 630.8 feet above sea level. The amending order also required continuous recording of the water levels within the headpond. NEW ENGLAND DEVELOPMENT -- GREGG FALLS, PEMBROKE, CLEMENT DAM, FRANKLIN, LOCHMERE, LOWER ROBERTSON, ASHUELOT, LAKEPORT, AVERY DAM, HADLEY FALLS, HOPKINTON, MILTON, MINE FALLS, GREAT FALLS, WORCESTER AND MORETOWN FACILITIES GREGG FALLS FACILITY The Gregg Falls Facility is located on the Piscataquog River near the Town of Goffstown, New Hampshire. The site was historically used for the generation of electrical energy and was decommissioned in the 1970's. A major refurbishment was undertaken is 1985, which included the installation of two new turbines and generators and the replacement of all electrical and control works. The installed capacity of the facility is 3,500 kilowatts. The Gregg Falls Facility is owned by the Gregg Falls Partnership, of which Algonquin America and Algonquin America Holdco are the partners. Land and Water Rights All rights to the existing structures located at the facility site are made available to the Gregg Falls Facility pursuant to a lease agreement with the New Hampshire Water Resources Board ("NHWRB"), a public corporation and an agency of the State of New Hampshire. The leased premises include all physical structures and the water rights necessary for the operation of the facility. The lease expires on December 29, 2032. FERC Licence The Gregg Falls Facility received an exemption from the licensing of a 3,280 kilowatt hydroelectric generating facility from FERC on July 21, 1983 (FERC Project No. 3180). The main compliance conditions associated with the facility are that: (i) it must operate as an instantaneous run-of-the-river facility; and (ii) a minimum flow of 20 cubic feet per second must be released downstream of the dam, when available. PEMBROKE FACILITY The Pembroke Facility is located on the Suncook River near the Town of Pembroke, New Hampshire. The site consists of a 500 foot power canal and a 480 foot penstock leading to a concrete powerhouse housing a single turbine generator. The site was constructed in 1986 and has an installed capacity of 2,600 kilowatts. The Pembroke Facility is owned by the Pembroke Hydro Associates Limited Partnership, a limited partnership between Algonquin America and Algonquin America Holdco. Land and Water Rights The land necessary for the operation of the facility is owned and the water rights for the Suncook River available at the facility site for the operation of the facility have been granted to the owner. The terms of the use of such water rights are governed by the NHWRB. -44- FERC licence The Pembroke Facility received an exemption from the licensing of a 2,600 kilowatt hydroelectric generating facility from FERC in February, 1983 (FERC Project No. 3185). The main compliance conditions associated with the facility are that: (i) it must operate as an instantaneous run-of-the-river facility; and (ii) a minimum flow of 10 cubic feet per second must be released downstream of the dam, when available. CLEMENT DAM FACILITY The facility is located on the Winnipesaukee River approximately five miles upstream from its confluence with the Pemigewasset River and near the Town of Tilton, New Hampshire. The facility is rated at 2,400 kilowatts and was constructed in 1984 at the location of an existing 120 foot wide dam and includes a 275 foot steel penstock which is 12 feet in diameter. The Clement Dam Facility is owned by Clement Dam Hydroelectric LLC, of which Algonquin America and Algonquin America Holdco are the sole members. Land and Water Rights The land upon which the Clement Dam Facility is located is leased from the former owners. Payments under the lease are equal to a percentage of the revenues earned by the facility from the sale of energy. The lease expires in 2032. Algonquin America has the right to purchase the lands upon the termination of the lease. The former owners have been granted the option to require Algonquin America to purchase the lands at any time after January 1, 2010. Water rights for the site have been obtained from the NHWRB pursuant to a water user's agreement. Semi-annual payments under the water user agreement are based on energy production. Although the original term of the water user's agreement has expired, the parties continue to operate under the terms of the water user's agreement pending negotiation of a new agreement. The State of New Hampshire, Department of Environmental Services - Water Resources Department is the administrator of State water user agreements and is currently reviewing all expired water user agreements and will be commencing discussions with all stakeholders. There has been no schedule developed by the State to commence these discussions. FERC Licence The Clement Dam Facility received an exemption from the licensing of a small hydroelectric generating facility from FERC on May 17, 1982 (FERC Project No. 2966). The order was later amended to increase the rated capacity to 2,400 kilowatts. The main compliance conditions associated with the facility are that: (i) it must operate as an instantaneous run-of-the-river facility; and (ii) a minimum flow of 30 cubic feet per second must be released downstream of the dam, when available. FRANKLIN FACILITY The Franklin Facility consists of two independent powerhouses located on the Winnipesaukee River in the Town of Franklin, New Hampshire, and located several kilometres downstream from the Clement Dam Facility. The River Bend Turbine-Generator is rated at 1,600 kilowatts and is located in a powerhouse which was constructed in 1985. The facility is constructed at the location of an existing 70 foot wide dam and includes a 1,000 foot long concrete penstock. The Steven's Mill Turbine-Generator, rated at 228 kilowatts, is housed in a powerhouse located immediately adjacent to the dam. The facility is owned by Franklin Power LLC, which is wholly-owned by Algonquin America. -45- The Franklin Facility was acquired on a foreclosure and secured party sale of the collateral securing the Franklin Note which included the Franklin Facility. The Fund filed an action in the District Court in New Hampshire for the balance of the amount owing on the Franklin Note. The court determined that the amount still due under the Franklin Note was US$4,810,710. Franklin Industrial Complex, Inc. ("FRANKLIN"), the borrower under the Franklin Note, and Marina Development Inc. and Arthur Steckler (collectively, the "BORROWERS") have filed a complaint against Algonquin Canada, Power Systems, Algonquin Power and others alleging, among other things, that the Algonquin entities conspired against Franklin, mismanaged the facility and breached fiduciary duties owed to Franklin. In 2004, a settlement was reached with the Borrowers, whereby the Borrowers agreed to pay the Fund US$2.75 million upon conclusion of the Trafalgar dispute, irrespective of the outcome of the dispute. In January 2005, the Fund announced that it was in negotiations with the Office of the United States Attorney in New Hampshire to resolve potential criminal charges for releases of hydraulic fluid into the Winnipesaukee River at the Franklin Facility between January 31, 2001 and February 15, 2001 and for improper reporting of the release. No environmental harm resulted from the loss of hydraulic oil, which appears to have resulted from a defective seal within the turbine assembly. On December 15, 2005, the Fund announced that a global settlement agreement had been reached with the United States Department of Justice and the Office of the United States Attorney in Concord, New Hampshire with respect to this release. Algonquin Power Systems - New Hampshire Inc., the operator of the Franklin Facility, agreed to plead guilty to two misdemeanour charges based on the release of the hydraulic fluid and to pay a US$10,000 fine and a US$100,000 civil penalty. The fine was paid by a Fund entity on behalf of the operator pursuant to an indemnity agreement between the Fund and the operator. Land and Water Rights The Franklin Facility is located on lands owned by Franklin Power LLC. The subsurface penstock which connects the intake to the powerhouse is located on an easement granted by the Town of Franklin. There is no transmission line associated with the facility as the interconnection with PSNH is located on the owned lands. The water rights necessary for the operation of the facility are leased from the NHWRB. The lease expired in August 2002 and is renewable on a year-to-year basis. Currently, the facility is operating on the old water user agreement while the State establishes a new water user agreement. FERC Licence The Franklin Facility received an exemption from the licensing of a small hydroelectric generating facility from FERC on June 14, 1983 (FERC Project No. 3760). The FERC exemption order was amended on April 16, 1991 to increase the stipulated capacity to 2,161 kilowatts. The main compliance conditions associated with the facility are that: (i) it must operate as an instantaneous run-of-the-river facility; and (ii) a minimum flow of 100 cubic feet per second must be released downstream of the dam, when available. At the time of issuance of the FERC exemption order, the U.S. Fish and Wildlife Service requested a downstream passage for Atlantic salmon seeded by the resource agencies. The cost of installing such fish passage, if required, is not expected to be significant. In addition, protection measures at the intake will also be required during the downstream migration of smolts, the cost of which is not significant. -46- LOCHMERE FACILITY The facility is a 1,200 kilowatt hydroelectric generating facility located on the Winnipesaukee River, in the Village of Lochmere, within the city limits of Tilton, New Hampshire. The facility consists of a dam, intake canal, intake, powerhouse and tailrace structures and is designed and operated as a run-of-the-river facility. The facility was reconstructed from an old hydroelectric generating facility at the site of an existing dam at the outlet of Winnisquam Lake. The Lochmere Facility is owned by the HDI Partnership, of which Algonquin America and Algonquin America Holdco are the partners. Land and Water Rights The land for the facility site is leased from the NHWRB. The term of the lease is 50 years, expiring in 2033. Payments under the lease are based on a percentage of adjusted gross revenues generated by the facility, which payments are in lieu of property taxes. The water use licence grants the facility the right to utilize the hydraulic resources for hydroelectric generation purposes by the State of New Hampshire. The licence has expired; however, the arrangement is being continued on the same basis as the original licence. Payments are made on a semiannual basis in accordance with a simple formula contained in the licence. The payment rate escalates on every fifth anniversary of the licence. FERC Licence The facility received an exemption from the licensing of a 1,200 kilowatt hydroelectric generating facility from FERC on March 15, 1984 (FERC project No. 3128). The main compliance conditions associated with the facility are that: (i) it must operate as an instantaneous run-of-the-river facility; (ii) from October to March, a minimum flow of 35 cubic feet per second must be released downstream of the dam, when available, and, during the months of April to September, the minimum flow must be 50 cubic feet per second; and (iii) a series of inexpensive, hand-built check dams constructed of natural river bed material must be maintained annually downstream of the dam for the creation of fish habitat. The cost of maintaining such check dams is not significant. LOWER ROBERTSON FACILITY The facility is a 960 kilowatt hydroelectric generating facility located on the Ashuelot River approximately one kilometre upstream of the Highway Bridge at Hinsdale, New Hampshire. The facility consists of a dam, intake, powerhouse and tailrace structures and is designed and operated as a run-of-the-river facility. The facility was constructed in 1988 at the site of an existing concrete dam, which was rebuilt to facilitate the generating facility. The facility is owned by the HDI III Partnership, of which Algonquin America and Algonquin America Holdco are the partners. Land and Water Rights The HDI III Partnership has title to the land on which all structures associated with the facility are located, including the dam structure, as well as access to both sides of the Ashuelot River required for the operation and maintenance of the facility and an interest in the riparian rights at the site, including all water power rights and privileges on the Ashuelot River. HDI III Partnership is party to an agreement with the Town of Winchester for payment of a percentage of gross revenues in lieu of property taxes for the facility. The term of the agreement is for 30 years commencing on the initial date of commercial operation, which occurred in June 1987. -47- FERC Licence The facility received an exemption from licensing for a hydroelectric generating facility of five megawatts or less from FERC on July 31, 1986 (FERC Project No. 8235). The main compliance conditions associated with this facility are that: (i) the facility must operate as an instantaneous run-of-the-river facility; and (ii) a minimum flow of ten cubic feet per second has to be released downstream of the dam, when available. At the time of issuance of the FERC exemption order, the U.S. Fish and Wildlife Service and New Hampshire Department of Fish and Game indicated that there may be a future requirement for the installation of an upstream fish by-pass at the facility, estimated by the Manager to cost approximately $400,000. To date, no such by-pass system has been installed. The government agencies may be reconsidering the necessity for this structure. ASHUELOT FACILITY The facility is a 900 kilowatt hydroelectric generating facility located on the Ashuelot River near the highway bridge at Hinsdale, New Hampshire. The facility consists of a dam, intake, powerhouse and tailrace structures and is designed and operated as a run-of-the-river facility. The facility was constructed in 1988 at the site of an existing concrete dam which was rebuilt to facilitate the generating facility. The Ashuelot Facility is owned by HDI III Partnership. Land and Water Rights The land and water rights for the site are leased from the Ashuelot Paper Company. The term of the lease is 55 years, expiring on December 31, 2040. Payments under the lease are structured as a percentage of gross revenues from the facility. HDI III Partnership is party to an agreement with the Town of Winchester for payment of a percentage of gross revenues in lieu of property taxes for the facility. The term of the agreement is for 30 years commencing on the initial date of commercial operation, which occurred in June 1987. FERC Licence The Ashuelot Facility received an exemption from the licensing of an 850 kilowatt hydroelectric generating facility from FERC on July 31, 1986 (FERC Project No. 7791). The main compliance conditions associated with this facility are that: (i) the facility must operate as an instantaneous run-of-the-river facility; and (ii) a minimum flow of ten cubic feet per second has to be released downstream of the dam, when available. At the time of issuance of the FERC exemption order, the U.S. Fish and Wildlife Service and the New Hampshire Department of Fish and Game indicated that there may be a future requirement for the installation of an upstream fish by-pass at the facility, estimated by the Manager to cost approximately US$500,000. To date, no such by-pass system has been installed. The government agencies may be reconsidering the necessity for this structure. LAKEPORT FACILITY The facility is a 600 kilowatt hydroelectric generating facility located on the Winnipesaukee River near the Town of Lakeport, New Hampshire. The facility consists of a dam, powerhouse and tailrace structures and is designed and operated as a run-of-the-river facility. The facility was constructed in 1984 at the site of an existing concrete dam. The Lakeport Facility is owned by Lakeport Corporation, a subsidiary of the Fund. -48- Land and Water Rights The facility is constructed on certain lands purchased by Lakeport Corporation. Additional land and water rights necessary for the operation of the facility are leased from the New Hampshire Water Resources Board. The term of the lease is 50 years and payments under the agreement are structured as a percentage of gross revenues from the facility. As a condition under the lease, Lakeport Corporation has entered into a water user's agreement with the NHWRB in respect of certain water management services provided by the NHWRB to users located on the Winnipesaukee River. Payments under the water user's agreement are structured based on energy production from the facility. FERC Licence The Lakeport Facility received a forty year licence for a 600 kilowatt hydroelectric generating facility from FERC on September 8, 1983 (FERC Project No. 6440). The main compliance conditions associated with this facility are that: (i) the facility must operate as an instantaneous run-of-the-river facility; and (ii) a minimum flow of 180 cubic feet per second has to be released downstream of the dam, when available. AVERY DAM FACILITY The facility is a 260 kilowatt hydroelectric generating facility located on the Winnipesaukee River in the City of Laconia, New Hampshire. The facility was constructed in 1985 at an existing site that was used for power generation. The facility is owned by the Avery Dam Partnership, of which Algonquin America and Algonquin America Holdco are the partners. Land and Water Rights Avery Dam Partnership has entered into a lease agreement with the NHWRB, for the water rights, land and associated facilities of the Avery Dam on the Winnipesaukee River. The term of the lease agreement expires on the earlier of 50 years or the termination of the FERC licence. The rental payments are structured as a percentage of the adjusted gross revenue for the year. The Avery Dam Partnership entered into a contract with water users with the NHWRB dated November 27, 1985. The term of the agreement is 15 years and can be extended after that period on a yearly basis upon mutual agreement. The rent includes both a base fee and an incentive fee. FERC Licence The facility received an exemption from the licensing of a small hydroelectric generating facility from FERC on March 22, 1985 (FERC Project No. 6752). The main compliance conditions associated with the facility are that: (i) it must operate as an instantaneous run-of-the-river facility; and (ii) it must maintain a minimum flow of 30 cubic feet per second from April to September and 20 cubic feet per second during the remainder of the year. HADLEY FALLS FACILITY The facility is a 250 kilowatt hydroelectric generating facility located on the Piscataquog River near the Town of Goffstown, New Hampshire. The facility is designed and operated as a run-of-the-river facility. The facility was commissioned in 1986 at the site of an existing concrete dam which was rebuilt -49- to facilitate the generating facility. The facility is owned by Hadley Falls Associates, of which Algonquin America and Algonquin America Holdco are the parties. Land and Water Rights The land and facilities required in order to construct and operate the Hadley Falls Facility are leased for a term of 35 years commencing in 1981. The rent is negotiated based on competitive rents. Water rights are leased under a lease agreement with the NHWRB. FERC Licence The facility received an exemption from licensing for a small hydroelectric generating facility of five megawatts or less from FERC on January 19, 1982 (FERC Project No. 5379). The main compliance condition is that the facility must operate as an instantaneous run-of-the-river facility. HOPKINTON FACILITY The facility is a 250 kilowatt hydroelectric generating facility located on the Contoocook River, in the Village of Contoocook, New Hampshire. The facility is designed and operated as a run-of-the-river facility. The facility was constructed at the site of an existing concrete dam which was rebuilt to facilitate the new generating facility. The Hopkinton Facility is owned by the HDI Partnership. Land and Water Rights Land and water rights for the site are leased from the Town of Hopkinton for a term of 40 years, expiring in 2023. Payments under the agreement are based on a step-rated percentage of annual gross revenues from the facility. The lease makes provision to significantly reduce lease payments in the event that dam repairs exceed $345,000 (US$250,000). A separate agreement with the Town of Tilton provides for payments in lieu of property taxes based on gross revenues generated by the facility. FERC Licence The Hopkinton Facility received an exemption from the licensing of a 250 kilowatt hydroelectric generating facility from FERC on March 14, 1984 (FERC project No. 5735). The main compliance conditions associated with the facility are that: (i) it must operate as an instantaneous run-of-the-river facility; and (ii) a minimum flow of two cubic feet per second must be released downstream of the dam, when available. At the time of issuance of the FERC exemption order, the U.S. Fish and Wildlife Service requested a downstream passage for Atlantic salmon seeded by the resource agencies. If there is a successful arrival of naturally migrating salmon, an upstream fish ladder will be required. The cost of installing such fish ladder, if required, is unknown at this time. MILTON FACILITY The Milton Facility is located on the Salmon River on the Maine-New Hampshire border, approximately 70 km from Manchester, New Hampshire. It has an installed capacity of 1,335 kilowatts. The facility is located at a site which was historically utilized for electrical and mechanical energy production for mill purposes. The facility was substantially rehabilitated and expanded in 1986 and includes a 3,800 foot penstock leading from the intake to the powerhouse. The Milton Facility is owned by SFR Hydro Corporation, a subsidiary of the Fund. -50- Land and Water Rights SFR Hydro Corporation owns all land necessary for the operation of the Milton Facility. In addition to direct ownership of certain parcels of land, SFR Hydro Corporation holds certain permanent easements on land and buildings employed by the facility. As a result of its ownership of the facility site, SFR Hydro Corporation holds the water rights for the Salmon River available at the facility site for the operation of the facility. FERC Licence The Milton Facility received an exemption from the licensing of a small hydroelectric generating facility from FERC in June 30, 1981 (FERC Project No. 3984). The main compliance conditions associated with the facility are that: (i) it operate as an instantaneous run-of-the-river facility; and (ii) a minimum flow of 25 cubic feet per second must be released downstream of the dam between April and June, when available. MINE FALLS FACILITY The Mine Falls Facility is a 3,000 kilowatt hydroelectric generating station located on the Nashua River near the City of Nashua, New Hampshire. The site is comprised of two turbine-generators housed in a new concrete powerhouse located at the site of a historic concrete dam. The site was commissioned in 1986. The Mine Falls Facility is owned by the Mine Falls Limited Partnership, which is a subsidiary limited partnership of the Fund. Land and Water Rights The land, physical structures and water rights associated with the facility are leased. The lease has a term of 40 years and expires in 2024. Payments pursuant to the lease are based on a percentage of gross revenues earned from the sale of energy from the facility. FERC Licence The Mine Falls Facility received a FERC Licence (FERC Project No. 3442) for a 3,032 kilowatt hydroelectric generating facility on March 26, 1985. The main compliance conditions associated with the facility are that: (i) it operate as an instantaneous run-of-the-river facility; and (ii) a minimum flow of 20 cubic feet per second must be released over the dam plus a minimum flow of 10 cubic feet per second must be released into an adjacent watershed, when available. Pursuant to a request by the U.S. Fish and Wildlife Service, the Manager is in the process of submitting maintenance plans for the existing upstream fish hoist system to FERC for approval. New Hampshire Power Purchase Agreements As discussed under "General Development of the Business - Other Developments in 2003", the Fund entered into new agreements with PSNH on May 31, 2003 in connection with the renegotiation of the power purchase rates associated with the Fund's portfolio of small hydroelectric generating facilities in New Hampshire (Gregg Falls, Pembroke, Clement Dam, Franklin, Lochmere, Lower Robertson, Ashuelot, Lakeport, Avery Dam, Hadley Falls, Hopkinton, Milton and Mine Falls). The agreements provide that PSNH will continue to purchase the energy produced by the facility at the ISO-New England, Inc. market rates. The agreements may be terminated by either party upon 60 days' notice. -51- GREAT FALLS FACILITY The Great Falls Facility is a 10,950 kilowatt hydroelectric generating station located on the Passaic River near the City of Paterson, New Jersey. The site was originally utilized for the production of electrical energy and was decommissioned in January 1969. The powerhouse was declared a United States national historic landmark in 1971. In 1986, the facility underwent a major rehabilitation with the installation of three new turbine-generators and new electrical and control equipment and was recommissioned in December 1986. The Great Falls Facility is owned by the Great Falls Partnership, of which Algonquin America and Great Falls Energy, L.L.C. are the partner. Power Purchase Agreement A power purchase agreement for the facility was entered into between the Great Falls Partnership and Public Service Electric and Gas Company (PSE&G). PSE&G purchases all electrical energy from the facility. The rates paid for such energy and capacity are based on the local marginal energy pricing paid by PSE&G for energy and capacity. In 2005, the average blended energy price was approximately US $0.068/kW-hr. PSE&G pays the producer for energy at the location-based market price for onpeak, offpeak and intermediate time periods. A capacity payment is also required to be paid by PSE&G. The term automatically renews annually, and may be terminated on 60 days' written notice. Land and Water Rights The land, physical structures and water rights associated with the facility are leased from the Paterson Municipal Utilities Authority. The lease expires on March 10, 2021. Payments pursuant to the lease are based on a percentage of gross revenues earned from the sale of energy from the facility, with a minimum annual payment. FERC Licence The Great Falls Facility received an exemption from the licensing of a small hydroelectric generating facility from FERC on March 1, 1981. The exemption was amended on September 6, 1985 (FERC Project No. 2814) to allow for a 10,950 kilowatt facility. The main compliance conditions associated with the facility are that: (i) it must operate as an instantaneous run-of-the-river facility; and (ii) a minimum flow of 200 cubic feet per second must be released over the dam, when available. WORCESTER FACILITY The Worcester Facility is located on the North Branch of Winnooskie River, in the Town of Worcester, Vermont approximately 10 miles north of Montpelier, Vermont. The facility is located at a concrete gravity dam 80 feet long and 21 feet in height. It is a run-of-the-river facility and is rated at 180 kilowatts. The facility has one Ossberger Cross-Flow turbine. The facility is owned by Worcester Hydro Company, Inc., a subsidiary of Algonquin America. Power Purchase Agreement The agreement with Vermont Power Exchange, Inc. has a term of 30 years. Specified settlement rates based on seasonal, as well as on/off peak production levels, are paid to the producer. Land and Water Rights Worcester Hydro Company, Inc. owns all land and water rights, as well as certain permanent -52- easements on land and buildings necessary for the operation of the facility. FERC Licence The facility received an exemption from licensing for a less than 5,000 kilowatt hydroelectric generating station facility from FERC on June 11, 1985. The facility was commissioned in 1985. The main compliance conditions associated with the facility are that: (1) it must operate as an instantaneous run-of-the-river facility; and (ii) a minimum flow of ten cubic feet per second must be released downstream of the dam, when available. MORETOWN FACILITY The facility is a 1,200 kilowatt hydroelectric generating facility located on the Mad River in the Town of Moretown, Vermont. The facility includes a 12 metre dam, forebay, intake structure, penstock, powerhouse and tailrace. The powerhouse includes a turbine generator rated at 1,250 kilowatts. The facility was constructed in 1989 and is owned by the Moretown Partnership, of which Algonquin America and Algonquin America Holdco are the partners. Power Purchase Agreement Under the power purchase agreement with Vermont Power Exchange, Inc., a purchasing agent authorized by the Vermont Public Service Board, Vermont Power Exchange, Inc. agreed to purchase all the electrical energy produced from the facility. The term of the contract is 30 years and the power purchase rates include an energy rate, a capacity rate and a payment lag adder rate. Moretown Partnership is a party to an interconnection agreement with Washington Electric Cooperative, Inc. permitting the facility to interconnect with the electrical system in Moretown, Vermont. Land and Water Rights All land and water rights required for the construction and operation of the facility are owned by the Moretown Partnership. Under the tax stabilization agreement with the Town of Moretown and the Town School District, municipal and school taxes owing with respect to the property are capped at amounts tied to power purchase rates paid by the Vermont Power Exchange, Inc. The term of the agreement is approximately 18 years, expiring March 31, 2008. FERC Licence The facility received a forty year licence (Minor Project) for a hydroelectric generating facility from FERC on December 7, 1982 (FERC Project No. 5944). The main compliance condition associated with the facility is that the facility must maintain an instantaneous minimum flow of 25 cubic feet per second over the dam, when available. WESTERN CANADA DEVELOPMENTS - DICKSON DAM FACILITY AND VALLEY POWER FACILITY DICKSON DAM FACILITY The Dickson Dam Facility is located 20 kilometres west of the Town of Innisfail, Alberta. The Dickson Dam Facility is a 15.0MW hydroelectric generating facility utilizing the infrastructure located at the Dickson Dam and powered by the waterflows of the Red Deer River. The facility consists of three horizontal Francis type turbines and was commissioned into commercial operation on January 16, 1992, The facility is owned by Algonquin Power Operating Trust. -53- Power Purchase Agreement The Dickson Dam power purchase agreement was entered into with TransAlta Utilities Corporation ("TRANSALTA") on December 7, 1990 and was approved by the Alberta Public Utilities Board on January 16, 1991. It has a term of 20 years ending on January 16, 2012. Under this agreement, TransAlta is obligated to accept delivery of all electricity in amounts up to 115% of the 12.7MW capacity which is allocated to the facility at rates stipulated by the Small Power Act. The price paid by TransAlta during 2005 was $0.062/kw-hr. Use of Works Agreement The Dickson Dam Facility is subject to a Use of Works Agreement with the Government of Alberta under which it has the right to utilize available waterflows for generating power until March 31, 2030. Under the Use of Works Agreement, the Dickson Darn Facility must operate in accordance with the requests of the Minister of Environment (Alberta) to accommodate water release changes. The Minister does not guarantee any reservoir water level or any supply of water to the Dickson Dam Facility, which is dependent upon water flows in the Red Deer River. The Minister also reserves the right to control releases and direct that the Dickson Dam Facility be operated to meet water management objectives relating to flood control, water quality levels and inter-provincial treaty obligations. Valley Power Facility The Valley Power Facility is a 12.0 MW bio-mass fired generating facility which produces electricity from burning wood waste provided by Weyerhaeuser Canada Ltd. using a single steam turbine. The facility was commissioned in 1994. Algonquin Power Operating Trust and Algonquin Power Trust own, directly and indirectly, a 50% interest in the partnership which owns the Valley Power Facility. The other 50% interest in the partnership is owned by the operator. The operator has extensive experience in operating biomass-fired generating facilities. Power Purchase Agreement The facility has entered into a 20 year agreement with TransAlta dated December 13, 1994, pursuant to which TransAlta is obligated to purchase all electricity produced at the Valley Power Facility up to 10.5MW at prices stipulated by the Small Power Act. Electricity generated at the Valley Power Facility is delivered to TransAlta through interconnection facilities erected on and adjacent to the facility site. Fuel Supply Under a fuel agreement with Weyerhaeuser, Weyerhaeuser is obligated to supply, without charge, all wood waste produced at the Weyerhaeuser sawmill plant which is co-located with the Valley Power Facility. The agreement, which expires in 2017, requires the facility to establish a storage pile of wood waste in an amount which will enable the facility to operate at an 87% capability factor for more than six months without further wood waste deliveries. The facility, operating at approximately 95% of maximum annual capacity, consumes approximately 84,000 oven dried tonnes (odt) of wood waste each year. The fuel agreement provides for delivery of approximately 90,000 odt of wood waste each year. The Manager understands that Weyerhaeuser plans to operate the Dray ton Valley plant beyond the term of the fuel agreement with the Valley Power Facility. However, it is estimated that there is approximately 100,000 odt of bio-mass wood waste available from alternative suppliers within a 160 kilometre radius of the -54- Valley Power Facility. No assessment has been made of the impact of transportation costs for such alternative bio-mass fuel upon the economics of the Valley Power Facility. COGENERATION DEVELOPMENTS - SANGER FACILITY, WINDSOR LOCKS FACILITY AND CROSSROADS FACILITY SANGER FACILITY The Sanger Facility is a 43.5 MW natural gas-fired generating facility located in Sanger, California. The Sanger Facility is a combined cycle generating station comprised of a 32 MW Westinghouse natural gas fired turbine and a 11.5 MW General Electric steam turbine, commissioned in 1991. The facility is owned by Algonquin Sanger Power, LLC, a subsidiary of Algonquin America. In November 2005, the Sanger Facility was closed for a six month period during which the facility was entitled to lower capacity payments. During this period, the Sanger Facility entered into an agreement to resell the natural gas normally consumed by the facility at favourable fixed prices. The closure of the facility is not expected to have a negative impact on Distributable Cash in 2006. Power Purchase Agreement Output of the facility is governed by the terms and conditions of a firm capacity and energy power purchase agreement with Pacific Gas and Electric Company ("PG&E"). The agreement has a term of 30 years, expiring in 2022, and calls for delivery of 38,000 kW of firm capacity. Capacity payments are based on a fixed amount of US $190 per kW/ year and are paid monthly on the basis of a capacity allocation factor and a transmission loss factor. The facility is entitled to a higher capacity payment and a lower energy price in the summer months (May to September) and a lower capacity payment and higher energy prices in the winter months (October to April). To qualify for the full capacity payment, the facility must maintain a capacity factor of 80% during the peak and/ or partial-peak hours of each monthly billing period. Annual capacity payments are estimated to be approximately US $7.2 million annually. The facility will not be eligible to receive a capacity payment of approximately US $1.0 million during the period of closure in 2006. Under the power purchase agreement, energy prices are fixed based on an estimate of PG&E's Avoided Costs until July 15, 2006. After this date, barring any decision to revise PG&E's Avoided Costs pricing by the California Public Utility Commission, energy pricing will revert to a variable cost formula impacted in part by market pricing for natural gas. The summer energy price is estimated at US $0.05386 per kW-hr. The winter energy price is estimated at US $0.07466 per kW-hr. Actual energy prices vary depending on a time-of-day adjustment. The power purchase agreement requires that the facility meet and maintain its status as a FERC Qualifying Facility under the Public Utility Regulatory Policies Act. A Qualifying Facility must be owned by an entity which is not primarily engaged in the sale or generation of electric power. In order to meet the ownership criteria, the applicant must demonstrate that no more than 50% of the equity interest in a Qualifying Facility site is held, directly or indirectly, through subsidiaries, by electric utilities and/or electric utility holding companies. The Manager is of the view that the Sanger Facility qualifies as a Qualifying Facility. Fuel Supply Natural gas for the facility is delivered under the terms of a gas supply agreement with Sempra Energy Trading Corp. expiring July 31, 2006. The agreement provides for a fixed price for all quantities -55- below a base amount. All natural gas required above the base amount is purchased at the spot price available on the day burned. On expiry of the agreement, the facility will purchase natural gas at market rates. Energy Lease Pursuant to a lease, energy supply and common services agreement with Dyna Fibers Inc., a wholly-owned subsidiary of Algonquin Sanger Power, LLC, Dyna Fibers Inc. leases a portion of the facility site in order to carry on its hydro mulch business and purchases certain energy at a cost equal to a percentage of the fuel costs incurred by the facility, to offset the incremental cost of fuel to supply such energy. The water consumption, exhaust heat and steam consumption by the hydro mulch operations are metered and recorded for FERC qualifying facility calculations that are submitted to PG&E on an annual basis. WINDSOR LOCKS FACILITY The Windsor Locks Facility is a 56 MW (gross) natural gas-fired generating facility located in Windsor Locks, Connecticut. The Windsor Locks Facility is a combined cycle generating station comprised of a 40 MW General Electric natural gas fired turbine and a 16 MW General Electric steam turbine and was commissioned in 1990. The facility is owned by Algonquin Windsor Locks LLC, a subsidiary of Algonquin America. Power Purchase Agreement The majority of the output of the Windsor Locks Facility is governed by the terms and conditions of a power purchase agreement with Connecticut Light and Power Company. The agreement expires in April 2010. The agreement calls for delivery of 38 MW summer and 39 MW winter firm capacity. The peak hours energy price is estimated at US $0.09691/kW-hr and the off-peak energy price is estimated at US $0.08087/kW-hr. Energy payments are based on a fixed amount of US $0.0218 per kW-hr during peak hours and US $0.0058 per kW-hr for off-peak hours. In addition, a variable payment of US $0.022 per kW-hr multiplied by the ratio of the buyer's gas cost divided by US $2.66 MMBtu is payable, insulating the facility from changes to the price of natural gas. The power purchase agreement requires that the facility meet and maintain its status as a FERC Qualifying Facility under PURPA or rate reductions will result. PURPA requires that a Qualifying Facility be owned by an entity which is not primarily engaged in the sale or generation of electric power. In order to meet the ownership criteria, the applicant must demonstrate that no more than 50% of the equity interest in a Qualifying Facility site is held, directly or indirectly, through subsidiaries, by electric utilities and/or electric utility holding companies. The Manager is of the view that the Windsor Locks Facility qualifies as a Qualifying Facility. Fuel Supply Natural gas for the facility is delivered under a gas supply agreement with Yankee Gas Service Company. Gas is supplied by Yankee Gas at a percentage of its weighted average cost of gas (WACOG) for the month. The gas contract contains minimum annual consumption requirements with associated penalties for shortfalls. -56- Energy Services Agreement and Ground Lease Pursuant to a ground lease and an energy services agreement with Ahlstrom Windsor Locks, LLC ("AHLSTROM"), Ahlstrom leases to Algonquin Windsor Locks, LLC the facility site and utilizes thermal steam energy and a portion of electrical generation of the Windsor Locks Facility for use at its specialty fibres composites mill located adjacent to the Windsor Locks Facility. Both the ground lease and the energy services agreement expire in January 2018, subject to certain early termination rights in favour of Ahlstrom and rights of renewal in favour of both parties. Payments under the energy services agreement are fully indexed to the cost of natural gas consumed by the facility. CROSSROADS FACILITY KMS Crossroads, Inc., a subsidiary of Algonquin Power Operating Trust, operates the Crossroads Facility. The facility is located in an office building complex in Mahwah, New Jersey and utilizes one 7.0 MW Solar Taurus 70 natural gas fired turbine to produce electricity and thermal energy. Power Purchase Agreement KMS Crossroads, Inc. has entered into a power sales agreement with Orange and Rockland Utilities Inc. (O&R) for the purchase of up to 3.88 MW of capacity. The power sales agreement expires on December 31, 2008. The sales price of electricity under the power sales agreement includes both a variable and a fixed component. The variable component is redetermined once each calendar quarter for the term of the power sales agreement. The variable component is based on the weighted average price at which O&R transfers natural gas to its electric department for the purpose of generating electricity, as ordered by the New York Public Service Commission, in the previous calendar quarter. In the event no natural gas is transferred in a calendar quarter, the variable component will be based on the weighted average price of number six fuel oil burned by O&R at its Lovett and Bowline generating facilities in that calendar quarter. The fixed component is US$0.0995/kW-hr for on peak hours, US$0.0770 for mid-peak hours and US$0.02704 for off-peak hours. Effective for the first quarter of 2006, the variable component is US$0.0778/kW-hr. The variable component remains constant regardless of the hour during which the kilowatts are generated. Pursuant to an energy services agreement, KMS Crossroads, Inc. is obliged to use reasonable efforts to provide firm electrical and thermal energy to the Crossroads Corporate Park, owned by Crossroads Developers Associates L.L.C. ("CDA") and CDA must purchase all of its required electricity from the KMS Crossroads, Inc. and all thermal power produced by KMS Crossroads, Inc. Pursuant to the energy services agreement, the sales price paid by CDA for electricity for the year ended December 31, 2005 was an average price of US$0.1309/kW-hr for each kilowatt hour generated and a variable price for thermal energy based on the market price for natural gas, averaging US$6.07/MMTU of thermal energy sold in 2005. Effective for 2006, the price for electricity is US$0.161/kW-hr while the January 2006 price for thermal energy is US$8.374/MMBTU. The Fund is in the process of monetizing the power purchase agreement, realizing on the value of the assets and closing the facility. As part of this process, the Fund has negotiated an agreement with CDA to allow the facility to terminate the power and thermal purchase agreement. This process in expected to be completed during the first half of 2006. Fuel Supply Natural gas is presently provided to KMS Crossroads, Inc. by Public Service Electric and Gas Company (PSE&G), the local public gas utility. KMS Crossroads, Inc. is a Qualifying Facility under the -57- Public Utilities Regulatory Policy Act and therefore takes advantage of the lowest available gas transportation rates prices provided by PSE&G. As a result, KMS Crossroads, Inc. benefits because gas rates provided by PSE&G are lower than the gas rates used to establish the thermal prices to CDA. THERMAL DEVELOPMENTS - EFW FACILITY, PRIMA DESHECHA FACILITY, TAJIGUAS FACILITY, MILLIKEN FACILITY, MID-VALLEY FACILITY, COLTON FACILITY, NASHVILLE (BORDEAUX) FACILITY, BALEFILL FACILITY, KINGSLAND FACILITY, SUNCOOK FACILITY, BURNSVILLE FACILITY AND FLYING CLOUD FACILITY EFW FACILITY The EFW Facility is a 10.0 MW generating station which produces electricity from incinerating non-recyclable materials, including municipal solid waste, using steam to drive a turbine generator to produce electricity. It is owned by Algonquin Power Energy from Waste Inc. (formerly KMS Peel Inc.), an Ontario corporation which is wholly-owned by KMS. Power Purchase Agreement The EFW Facility has entered into a power purchase agreement with OEFC which requires OEFC to purchase all the electricity produced by the facility. The current electricity rates are as follows (escalating price based on changes in the consumer price index): (1) winter peak - $0.0969/kW-hr, (2) winter off-peak - $0.0373/ kW-hr, (3) summer peak - $0.08234/kW-hr and (4) summer off-peak -$0.0326/kW-hr. The power purchase agreement expires in 2012. Fuel Supply Under a "tip or pay" waste supply agreement with the Regional Municipality of Peel, the Regional Municipality supplies the facility with a minimum of 127,000 tonnes and up to 36,000 tonnes per year of acceptable municipal solid waste, respectively. The agreement expires in 2012. The Regional Municipality has the option to renew the agreement for an additional five-year term. The agreement requires the Regional Municipality to pay a "tipping fee" in the amount of $84.00 for each tonne of acceptable waste delivered up to 127,900 tonnes. A fee of $60.82 is charged for each tonne of acceptable waste delivered above the base amount. This fee is adjusted monthly throughout the term of the agreement based on changes in the Toronto-area consumer price index. Additional volumes of waste may be supplied by the Regional Municipality at the request of either party, subject to the agreement of the other. The agreement provides that if certain taxes are imposed or revised standards are set for certain environmental or operating matters affecting the facility, the tipping fees paid by the Regional Municipality will be increased to reflect the increased capital or operating costs so imposed by the taxes or revised standards. The EFW Facility also incinerates waste generated from international flights arriving at the Lester B. Pearson International Airport in Toronto, Ontario for an average "tipping fee" in the amount of $146.59 for each tonne of acceptable waste delivered up to 13,000 tonnes. This fee is adjusted annually based on changes in the Toronto-area consumer price index. PRIMA DESCHECHA FACILITY The Prima Deschecha Facility is a 6.1 MW landfill gas to electricity facility located in San Juan Capistrano, Orange County, California. The facility uses two Caterpillar 3616 engine-generators. The facility was opened in 1998 and is eligible for certain emission tax credits until 2007. The facility is owned by MM Prima Deshecha Energy LLC. -58- Power Purchase Agreement The facility has a power purchase agreement with San Diego Gas & Electric Company based on a rate of US$0.04893/kW-hr and anticipates producing 43.0 MW of energy annually. The agreement expires in 2007. The Manager is currently working to extend the term of this agreement. Location Rights The facility is situated on one of the largest permitted landfills in the State of California. The site is open and continues to accept waste. The facility's lease with Orange County, California expires in 2027, with options to renew for successive 5-year periods. TAJIGUAS FACILITY The Taijiguas Facility is a 3.05 MW landfill gas to electricity facility located in Goleta, County of Santa Barbara, California. The facility uses one Caterpillar engine-generator. The facility was opened in 2000 and is eligible for certain emission tax credits until 2007. The facility is owned by MM Tajiguas Energy LLC. Power Purchase Agreement The facility has a power purchase agreement with Southern California Edison ("SCE"). Energy payments are variable, based on SCE's avoided costs. The facility anticipates producing 21.5 GW of energy annually. Energy rates vary based on the time of day and demand and are indexed to the price of fuel. This results in an average estimated rate for 2006 of US$O.O632/kW-hr. The agreement expires in 2007. The Manager is currently working to extend the term of this agreement. Location Rights The facility is situated on a landfill that remains open and continues to accept waste. The facility's lease with the County of Santa Barbara, California expires in 2018 with options to renew for successive 5-year periods. MILLIKEN FACILITY The Milliken Facility is a 2.52 MW landfill gas to electricity facility located in Ontario, San Bernadino County, California. The facility uses two engine-generators. The facility was opened in 2003 and is eligible for certain emission tax credits until 2007. The Milliken Facility is owned by NM Milliken Genco LLC, Power Purchase Agreement The facility has a power purchase agreement with the City of Riverside Municipal Utility at a rate of US$0.0585/kW-hr and anticipates producing 14.8 GW of energy annually. The agreement expires in 2008. The facility receives California Energy Commission energy payments in an amount of US$0.00675/kW-hr until July 2008. The Manager is working to finalize a new long-term agreement. Location Rights The facility is situated on a closed landfill site. The facility's lease with San Bernardino County, California expires in 2008 with options to renew for successive 5 year periods. -59- MID-VALLEY FACILITY The Mid-Valley Facility is a 2.52 MW landfill gas to electricity facility located in Fontana, San Bernadino County, California. The facility uses two engine-generators. The facility was opened in 2003 and is eligible for certain emission tax credits until 2007. The facility is owned by NM Mid Valley Genco LLC. Power Purchase Agreement The facility has a power purchase agreement with the City of Riverside Municipal Utility at a rate of rate of US$0.0585/kW-hr and anticipates producing 16.4 GW of energy annually. The agreement expires in 2008. The facility receives California Energy Commission energy payments in an amount of US$0.00675/kW-hr until April 2008. Location Rights The facility is situated on a landfill that remains open and continues to accept waste. The facility's lease with San Bernardino County, California expires in 2008 with options to renew for successive 5 year periods. COLTON FACILITY The Colton Facility is a 1.26 MW landfill gas to electricity facility located in Colton, San Bernadino County, California. The facility uses one engine-generator. The facility was opened in 2003 and is eligible for certain emission tax credits until 2007. The facility is owned by NM Colton Genco LLC. Power Purchase Agreement The facility has a power purchase agreement with the City of Colton Municipal Utility at a rate of rate of US$0.0621/kW-hr, with an annual price increase and anticipates producing 7.9 GW of energy annually. The agreement expires in 2008 with a mutual option for two 5-year extensions. The facility receives California Energy Commission energy payments in an amount of US$0.00675/kW-hr until April 2008. Location Rights The facility is situated on a landfill that remains open and continues to accept waste. The facility's lease with San Bernardino County, California expires in 2008 with options to renew for successive 5 year periods. NASHVILLE (BORDEAUX) FACILITY The Nashville (Bordeaux) Facility is a 1.9 MW landfill gas to electricity facility located in Nashville, Tennessee. This facility is currently offline for repairs. No decision has been made as to the timing of repairing the facility. The resulting loss of Distributable Cash is insignificant to the Fund. The facility uses two containerized Caterpillar engine-generators and is equipped with a 2 MW standby diesel generator. The facility was opened in 1998 and is eligible for certain emission tax credits until 2007. The facility is owned by MM Nashville Energy LLC. -60- Power Purchase Agreement The facility has a power purchase agreement with the Metropolitan Government of Nashville & Davidson County at a rate of rate of US$0.03672/kW-hr less various adjustments. This resulted in an average rate for 2005 of US$0.0052/kW-hr. The agreement expires in 2007 with an option of two 4-year extensions. Location Rights The facility is situated on a closed landfill site. The facility's lease with the Metropolitan Government of Nashville & Davidson County expires in 2007 with two 4 year extensions. BALEFILL FACILITY The Balefill Facility is a 3.8 MW landfill gas to electricity facility located in North Arlington, New Jersey. The facility uses two tandem Caterpillar engine-generators. The facility was opened in 1998 and is eligible for certain emission tax credits until 2007. The facility is owned by MM Hackensack Energy LLC. Power Purchase Agreement The facility has a power purchase agreement with PSE&G Energy Resource and Trade, LLC (PSE&G) and anticipates producing 25.8 GW of energy annually. Payments are variable and based on PSE&G's avoided costs plus a premium of US$0.005/kW-hr. The facility earned an average of US$0.005/kW-hr in 2005 and estimates an average rate in 2006 of US$0.05552/kW-hr for the facility. The agreement expires in 2007 with two four-year extensions. Location Rights The facility is situated on a closed landfill site. The facility's lease with Hackensack Meadowlands Development Commission expires in 2017 with an optional annual extension. KINGSLAND FACILITY The Kingsland Facility is a 2.9 MW landfill gas to electricity facility located in North Arlington, New Jersey. The facility uses three containerized Caterpillar engine-generators. The facility was opened in 1999 and is eligible for certain emission tax credits until December 2007. The facility is owned by MM Hackensack Energy LLC. Generation capacity at this facility is currently limited due to reduced gas availability. The Manager is taking various steps including running the engine-generators strategically to manage production issues. Power Purchase Agreement The facility has a power purchase agreement with PSE&G Energy Resource and Trade, LLC and anticipates producing 15.2 GW of energy annually. Payments are variable and based on PSE&G's avoided costs plus a premium of US$0.005/kW-hr. The facility earned an average US$0.0733/kW-hr in 2005 and estimates an average rate for 2006 of US$0.05579/kW-hr for the facility. The agreement expires in 2006 and the Fund is currently negotiating to extend the power purchase agreement. -61- Location Rights The facility is situated on a closed landfill site. The facility's lease with Hackensack Meadowlands Development Commission expires in 2017 with an optional annual extension. SUNCOOK FACILITY The Suncook Facility is a 3.1 MW landfill gas to electricity facility located in Nashua, New Hampshire. The facility uses two Caterpillar engine-generators. The facility was opened in 1997 and is eligible for certain emission tax credits until 2007. The facility also qualifies for Connecticut Renewable Energy Certificates, currently valued at approximately US$0.035/kW-hr. The facility is owned by Suncook Energy LLC. Power Purchase Agreement The facility has power purchase agreements to sell approximately 70% of the energy generated to New England Power ("NEP") and the remainder to Public Services of New Hampshire and anticipates producing 19.2 MW of energy annually. The agreements expire in 2021 and 2015, respectively. The NEP rates were US$0.0665/kW-hr during peak hours and US$0.0313/kW-hr during off peak hours. PSNH rates are US$0.049/kW-hr plus a capacity payment. The average rate, including capacity payment, in 2006 is estimated to be US$0.0571/kW-hr. Location Rights The facility is situated on a landfill that remains open and continues to accept waste. The facility's lease with the City of Nashua, New Hampshire expires in 2024 or earlier, if the City advises that the landfill cannot produce commercially viable quantities of landfill gas. BURNSVILLE FACILITY The Burnsville Facility is a 4.21 MW landfill gas to electricity facility located in Burnsville, Minnesota. The facility uses two tandem Caterpillar engine-generators and one single Caterpillar 3516 engine-generator. The facility was opened in 1994. It is owned by MM Burnsville Energy LLC. Power Purchase Agreement The facility has a power purchase agreement with Excel Energy (formerly Northern States Power Company). Payments are variable and based on Excel's avoided costs plus a capacity payment of US$40,000. The facility earned an average of US$0.0686/kW-hr in 2005 and estimates an average rate for 2006 of US$0.0415, after capacity payments. The agreement expires in 2015. Location Rights The facility is situated on a landfill that remains open and continues to accept waste. The facility's lease with Burnsville Sanitary Landfill, Inc. expires in 2014. FLYING CLOUD FACILITY The Flying Cloud Facility is a 4.89 MW landfill gas to electricity facility located in Eden Prairie, Minnesota. This facility has been offline for repairs since April 2005. No decision has been made as to the timing of repairing the facility. The resulting loss of Distributable Cash is insignificant to the Fund. -62- The facility uses three tandem Caterpillar engine-generators. The facility was opened in 1995. It is owned by Landfill Power LLC, Power Purchase Agreement The facility has a power purchase agreement with Excel Energy. Payments are variable and based on Excel Energy's avoided costs estimated at US$0.0165/kW-hr plus a capacity payment. Location Rights The facility is situated on a closed landfill. The facility's lease with Allied Waste Industries Inc. expires in 2024 or the termination of the power purchase agreement, if earlier. OTHER INTERESTS IN ENERGY-RELATED DEVELOPMENTS KIRKLAND FACILITY The Kirkland Facility is a 102 MW combined cycle co-generation facility located in Kirkland Lake, Ontario owned by Kirkland Lake Power Corporation ("KIRKLAND") which burns natural gas and wood waste to generate electricity using three 23 MW gas turbines and two steam turbines. The facility was commissioned in 1991 and is currently operated by Northland Power Inc. ("NORTHLAND"). Electricity produced by the facility is sold to OEFC pursuant to a 40 year contract executed in 1989. Electricity in excess of that committed to OEFC under the power purchase agreement may be sold into the deregulated market in Ontario. Natural gas used by the facility is supplied under 20 year supply contracts commencing in 1991. Price increases under such gas supply agreements are generally tied to price increases under the power purchase agreement with OEFC. Wood waste consumed by the facility is supplied by local forest product companies under contracts of varying terms with the longest being 31 years. The capital structure of Kirkland is comprised of approximately $85.2 million of senior debt outstanding and 3,562,963 Class A voting shares and 37,000,000 Class B non-voting shares. The Class A and Class B shares are identical in all respects except the Class A shares have voting rights. Algonquin Power Trust owns 32.4% of the Class B non-voting shares issued by Kirkland. The management agreement between Northland and Kirkland contemplates that Kirkland will achieve specified target operating profits from the operation of the Kirkland Facility, failing which, among other things, Kirkland may terminate the management agreement. It is Kirkland's policy to declare and pay quarterly dividends on its shares equal to substantially all of its after-tax income, and the amount of dividends to date have been consistent with the targeted operating profits (net of applicable tax) established in the management agreement. Northland has granted Kirkland a put option to sell the Kirkland Facility to Northland with an exercise date of February 28, 2011 at an exercise price of $10 million. Under the management agreement, 90% of operating income of the facility will be paid to Northland after the exercise date and, accordingly, it is anticipated that Kirkland will exercise such put option and the proceeds of such sale will be utilized to repay debt and make distributions to shareholders. COCHRANE FACILITY The Cochrane Facility is a 35.8 MW combined cycle co-generation facility located in Cochrane, Ontario owned by Cochrane Power Corporation ("COCHRANE") which burns natural gas and wood waste to generate power using a 26.5 MW gas turbine and a steam turbine. The facility was commissioned in 1990 and is currently operated by Northland. Electricity produced by the facility is sold to OEFC pursuant to a 25 year contract executed in 1989. Electricity in excess of that committed to OEFC under the power purchase agreement may be sold into the deregulated market in Ontario. The majority (90%) -63- of the natural gas used by the facility is supplied under a supply contract which expires in 2012. Price increases under such gas supply agreements are generally tied to price increases under the power purchase agreement with OEFC. Wood waste consumed by the facility is supplied by local forest product companies under contracts of varying terms with the longest being 30 years. The capital structure of Cochrane consists of 6,000,000 Class A voting shares representing 11.54% of the equity interests and 46,000,000 Class B non-voting shares representing approximately 88.46% of the equity interests. Cochrane currently has a line of credit in the amount of $1.5 million. Algonquin Power Trust owns 25% of the Class B non-voting shares issued by Cochrane. The management agreement between Northland and Cochrane contemplates that Cochrane will achieve specified target operating profits from the operation of the Cochrane Facility, failing which, among other things, Cochrane may terminate the management agreement. It is Cochrane's policy to declare and pay quarterly dividends on its shares equal to substantially all of its after-tax income, and the amount of dividends to date have been consistent with the targeted operating profits (net of applicable tax) established in the management agreement. Northland has granted Cochrane a put option to sell the Cochrane Facility to Northland with an exercise date of February 28, 2011 at an exercise price of $3.0 million. Under the management agreement, 90% of operating income of the facility will be paid to Northland after the exercise date and, accordingly, it is anticipated that Cochrane will exercise such put option and the proceeds of such sale will be distributed to shareholders. CHAPAIS FACILITY Chapais Energie, Societe en Commandites ("CHAPAIS") owns this wood waste electricity generating facility located in the Town of Chapais, Quebec. The Chapais Facility was placed into commercial operation after significant commissioning difficulties and delays in August 1995. The Chapais Facility sells electricity to Hydro Quebec pursuant to a power purchase agreement expiring December 1, 2015, with a 5 year renewal option. Wood waste is purchased from local sawmills in the area with transportation expense being the principal cost incurred to obtain the wood waste supply. As part of a restructuring which occurred as a result of commissioning delays and difficulties, the original debt incurred by Chapais in the construction of the facility was temporarily exchanged for certain preferred shares which converted to senior secured debt on July 31, 2004. The capital structure of Chapais is comprised of 50 common shares, 400 Class A non-voting shares and 336 Class B non-voting preferred shares. Chapais is also the debtor under a term loan held by CHEL Subco Inc. ("CHEL"). The authorized capital of CHEL consists of common shares (all of which are held by Chapais), as well as Class A preferred shares (the "TRANCHE A SHARES"), Class B preferred shares (the "TRANCHE B SHARES") and Class C preferred shares. There are approximately $47.5 million of Tranche A Shares and $15.3 million of Tranche B Shares outstanding. Both tranches of preferred shares are expected to pay dividends at the rate of 6.5% per annum. On July 31, 2004, the Tranche A Shares and Tranche B Shares were exchanged for term loan interests issued by Chapais, which loans will bear interest at the rate of 10.789% and 4.91%, respectively. The Fund did not realize a gain or a loss due to this exchange. Algonquin Power Trust owns a 12.1% interest in both the Tranche A Shares and Tranche B Shares and a 33.9% interest in the Class B non-voting preferred shares of Chapais. BROOKLYN FACILITY Brooklyn Power Corporation ("BROOKLYN") owns this 28 MW bio-mass-fired electric generating facility located in Queen's County, Nova Scotia. The Brooklyn Facility was commissioned in December 1995 and consumes the wood waste produced by the Bowater Mersey Paper Company Limited facility in addition to certain wood waste purchased from several local sawmill operators in southern Nova Scotia. Brooklyn sells electricity to Nova Scotia Power Inc. ("NSPI") pursuant to a power purchase contract -64- expiring in 2028, the pricing under which is based on NSPI's Avoided Costs. Brooklyn delivers steam to Bowater in exchange for a portion of the wood waste fuel. The capital structure of Brooklyn is comprised of approximately $54.0 million of senior debt and 1,000,000 common shares. Algonquin Power Trust owns a 13.6% interest in the senior debt issued by Brooklyn and a 13.6% interest in the outstanding common shares of Brooklyn. The outstanding principal amount of the interest in the senior debt owned by Algonquin Power Trust as at December 31, 2005 was approximately $8.2 million. ST. LEON FACILITY AirSource Power Income Fund I LP is undertaking the construction of this 99 MW wind powered generating facility near St. Leon, Manitoba (150 km southwest of Winnipeg) that will sell its entire output to Manitoba Hydro pursuant to a 25 year power purchase agreement. The St. Leon Facility consists of sixty-three 1.65 MW wind turbines manufactured by Vestas Wind A/S and constructed in two phases. The first phase consisting of twelve wind turbines was completed in 2005 and interim sales of power at the pre-commercial operating rate commenced on April 27, 2005. Construction of the second phase, consisting of fifty-one wind turbines, was completed on March 8, 2006. AirSource is currently working towards having the project commissioned by Manitoba Hydro. Once this occurs, the facility will be entitled to receive the higher commercial operating rate under the power purchase agreement. The St. Leon Facility has been connected to the electricity transmission grid owned and operated by The Manitoba Hydro-Electric Board. Algonquin Power Trust has provided a $69.4 million subordinated construction debt facility to the St. Leon Wind Energy Trust and a $4.9 million subordinated acquisition debt facility to Airsource. Airsource, a public income fund, indirectly owns the St. Leon Facility through St. Leon Wind Energy Trust. The acquisition debt facility and the construction facility bear interest at the annual rate of approximately 11.2% prior to project completion. This yield will be reduced to 10.7% following project commissioning. At the end of 2005, the Fund had advanced a total of $74.3 million to AirSource and St. Leon Trust, collectively. Upon default under AirSource's $73.3 million senior debt facility, Algonquin Power Operating Trust and the Fund will be obliged to advance the full amount of its construction facility in order to complete the St. Leon Facility and/or repay the senior debt facility. Environmental Licence St. Leon LP holds an Environmental Act Licence pursuant to The Environment Act (Manitoba) from the Ministry of the Environment (Manitoba) allowing the construction of sixty-three wind turbines. Power Purchase Agreement St. Leon LP and St. Leon GP have entered into a power purchase agreement with Manitoba Hydro dated as of October 28, 2004. The term of the power purchase agreement is 20 years, with a price renewal term of up to an additional 5 years. All electricity produced at the St. Leon Facility will be sold to Manitoba Hydro pursuant to the power purchase agreement. There are two price levels under the power purchase agreement: one for dependable energy and one for non-dependable energy. The quantity of dependable energy will be nominated under the power purchase agreement by St. Leon LP from time to time during the term of the power purchase agreement. For the contract period commencing on May 1, 2005 -65- to December 31, 2005, the dependable and non-dependable prices were approximately 50.61 per MW-hr and $39.84 per MW-hr, respectively. The facility has been approved to receive a wind power production incentive from the Federal Government of $1.00 per MW-hr. WATER DISTRIBUTION AND WATER RECLAMATION DEVELOPMENTS - BLACK MOUNTAIN, GOLD CANYON, BELLA VISTA, TALL TIMBERS, WOODMARK, LITCHFIELD, FOX RIVER, TIMBER CREEK, HOLIDAY HILLS, OZARK MOUNTAIN, HOLLY RANCH, BIG EDDY, PINEY SHORES, HILL COUNTRY AND RIO RICO FACILITIES BLACK MOUNTAIN FACILITY The Black Mountain Facility was established in 1971 to support the development of the Boulders Resort and golf course. This resort is located ten miles north of Scottsdale, Arizona, in the town of Carefree, Arizona. The facility currently serves approximately 2,900 customers in the Town of Carefree. During 2004, the facility experienced a 6% growth rate in the number of connections to the facility. The Black Mountain Facility is owned by a wholly-owned subsidiary of AWRA. The existing plant is located in the residential portion of the Boulders Resort, in the immediate vicinity of residences and the Boulders golf course. The plant owned by the utility treats 120,000 gallons per day and presently runs at capacity every day. The reclaimed water produced by the plant is delivered by pipe to a lake on the Boulders golf course. The facility is an activated sludge plant and produces an effluent which exceeds quality standards for effluent discharge and reuse and which is used for irrigation of the Boulders golf course and surrounding vegetation. Excess wastewater is delivered by pipe to the City of Scottsdale Wastewater Treatment Plant. The facility operates under a perpetual regulated agreement called a Certificate of Convenience and Necessity and is regulated by the Arizona Corporation Commission. The facility operates under Arizona Department on Environmental Quality - Aquifer Protection Permits and Reuse Permits. The facility provides sewer services for a flat tariff rate of US$38 per month. The Black Mountain Facility has initiated a rate case and is requesting a tariff increase of approximately 13.5%. It is anticipated that this process will be completed by early 2007. GOLD CANYON FACILITY The Gold Canyon Facility was established in 1984 to serve a number of residential developments in the City of Gold Canyon area, approximately 25 miles east of downtown Phoenix, Arizona. The facility currently serves over 5,300 residential customers. During 2004, the facility experienced an 8% growth rate in the number of connections. The Gold Canyon Facility is owned by a wholly-owned subsidiary of AWRA. The treatment process is comprised of an extended aeration facility combined with a sequencing batch reactor. The expansion of the facility from a capacity of 750,000 gallons per day to 1.9 million gallons per day was completed in October 2005. The facility is expected to ultimately serve approximately 9,000 customers. The facility is a consumptive re-use facility and sells its reclaimed water for use as irrigation water on five neighbouring golf courses. Excess reclaimed water is recharged, i.e. put back into the ground to replenish underground water, via three recharge ponds. The treatment facility operates under Arizona Department on Environmental Quality - Aquifer Protection Permits and Reuse Permits. The Gold Canyon Facility operates under a Certificate of Convenience and Necessity and is regulated by the Arizona Corporation Commission. The facility provides sewer services at a flat tariff of -66- US$35 per month. A rate case was initiated for this facility, requesting a tariff increase of approximately 100%. It is anticipated that this process will be completed by early 2007. BELLA VISTA FACILITY The Bella Vista Facility was formed in 1952 to serve a new motel and several small commercial buildings developed in the Town of Sierra Vista, Arizona. The facility currently serves approximately 7,800 connected water customers and has experienced long term growth at the rate of 3% per year. The Bella Vista Facility is owned by a wholly-owned subsidiary of AWRA. All potable water supplied by the facility is obtained from deep well groundwater. There are 29 wells supplying the Bella Vista infrastructure and water from all wells is disinfected at the source prior to distribution. The Bella Vista Facility currently has outstanding indebtedness to the Water Infrastructure Finance Authority evidenced by two 25 year fully amortizing notes. The first note, issued in 1995, bears interest at the rate of 6.10% and has a remaining balance as at December 31, 2005 of US$134,000. The other note bears interest at the rate of 6.26% and has an outstanding balance of US$ 1,802,000 as at December 31, 2005. In 2005, the average water bill for each residential connection to this facility was approximately US$27.41 per month. The facility operates under a Certificate of Convenience and Necessity and is regulated by the Arizona Corporation Commission. The facility operates under Arizona Department on Environmental Quality - Aquifer Protection Permits and Reuse Permits. TALL TIMBERS FACILITY The Tall Timbers Facility was formed in 1983 to serve subdivision developments in the City of Tyler, Texas approximately 90 miles east of Dallas. The facility now serves approximately 1,100 connected customers consisting of approximately 30 commercial/light industrial connections and the balance representing residential connections. The facility experienced growth of approximately 5% in 2005. A new highway under construction through the service area is substantially complete and is anticipated to result in increased growth. The facility is owned by a wholly-owned subsidiary of AWRA. The current approved customer rate is US$40.08 per month. The facility has a capacity of 445,000 gallons per day. The facility operates under a Certificate of Convenience and Necessity and is regulated by Texas Commission on Environmental Quality. The facility is currently finalizing the rate case with the Texas Commission on Environmental Quality to justify the current rate. The facility discharges to the nearby Mud Creek. WOODMARK FACILITY The Woodmark Facility was formed in 1990 to serve a small subdivision under construction near the City of Tyler, Texas, approximately 90 miles east of Dallas, Texas. The facility currently serves 1,000 connected customers with a capacity of 250,000 gallons/day. The facility experienced growth of approximately 15% in 2005 and is considering plans to expand its plant capacity in 2006. The Woodmark Facility is owned by a wholly-owned subsidiary of AWRA. The Woodmark Facility completed a rate case with the Texas Commission of Environmental Quality in 2005. The facility requested an increase from US$32.60 monthly to approximately US$44.00 monthly. The approved rates were increased to US$40.00 monthly. The facility operates under a -67- Certificate of Convenience and Necessity and is regulated by the Texas Commission on Environmental Quality. The facility discharges to the nearby Mud Creek. LITCHFIELD FACILITY The Litchfield Facility is a water distribution and wastewater reclamation facility located in the West Valley of Maricopa County, 15 miles west of Phoenix, Arizona whose service area includes sections of the Cities of Goodyear, Avondale and Litchfield Park, Arizona. According to the 2000 census data, Maricopa County is the fastest growing county in the United States. The Litchfieid Facility is owned by a wholly-owned subsidiary of AWRA. The facility presently serves approximately 13,500 water and 13,000 water reclamation customers with a capacity of 4.1 million gallons/day. During 2004, the facility experienced a 12% growth rate in the number of connections for both water and wastewater to the facility. The facility's water infrastructure includes a total of nine active wells and a 6.3 million gallon reservoir which provides water to the current customer base through a single pressure zone. In April 2002, the facility completed construction and commissioning of a 4.2 million gallon per day water reclamation facility. This facility now operates at 60% capacity and supplies Class "A+" reclaimed water to a number of local golf courses in the area and is considering plans to expand its plant capacity in 2007 with design to begin in the third quarter of 2006. The Litchfield Facility currently has outstanding indebtedness to the City of Goodyear in the amount of US$12.1 million in respect of which the City of Goodyear has acted as a conduit issuer of a like amount of Industrial Development Authority bonds. The bonds consist of two series, both fully amortizing over a 30 year term. The first series was issued in 1999, has a principal amount as of December 31, 2005 of US$4.7 million bearing interest at the rate of 5.87%. The second series was issued in 2000 with a principal amount as of December 31, 2005 of US$7.5 million and bearing interest at the rate of 6.71%. As partial security for these bonds, the facility is required to hold funds in a restricted, interest bearing, investment account. The balance of this account at December 31, 2005 was US$1.2 million. Approved water reclamation rates for the facility are US$27.20 residential and US$46.00 small commercial per month for sewer services. There are also approved rates for large commercial and special category customers (schools, resorts, multi-housing, etc.). The average water bill for residential customers is approximately US$19.25 per month. The facility operates under a Certificate of Convenience and Necessity and is regulated by the Arizona Corporation Commission. The facility operates under Arizona Department of Environmental Quality - Aquifer Protection Permits and Reuse Permits. FOX RIVER FACILITY The Fox River Facility is a water distribution and water reclamation facility located in LaSalle County, approximately 50 miles south-west of Chicago, Illinois, just outside the town of Sheridan, on the banks of the Fox River. The facility primarily serves the Fox River Resort, a timeshare oriented operation consisting of approximately 220 equivalent water distribution and reclamation connections. The facility is owned by a wholly-owned subsidiary of AWRA. Currently, only half of the available acreage in the area is developed and the water storage and water reclamation treatment plant can accommodate a doubling of demand without the need for major capital expenditure. The Fox River Facility serves one customer and is therefore not regulated by the Illinois Commerce Commission. AWRI is entitled to calculate rates based on a 12% return on investment for -68- both water and water reclamation, the same as rates are calculated and determined by the Texas Commission on Environmental Quality for the Texas facilities, plus an additional US$400,000. The Fox River Facility currently charges a flat rate of US$120.25 for water reclamation with no charges for water. The Fund is currently negotiating with Silverleaf Resorts Inc. to determine the rates for this service on a go forward basis. TIMBER CREEK FACILITY The Timber Creek Facility is a water distribution and water reclamation facility located in Jefferson County, approximately 50 miles south of St. Louis, Missouri, just outside the town of DeSoto, on the banks of Timber Creek. The facility primarily serves the Timber Creek Resort, consisting of approximately 30 equivalent water and water reclamation connections. The facility is owned by a wholly-owned subsidiary of AWRA. Currently approved water rates are US$3.00 minimum per month and US$3.02/1,000 gal consumption charge. The approved sewer rates are US$6.00 per connection and US$7.57 per 1,000 gal average usage. The Timber Creek Facility is regulated by the Missouri Public Service Commission, the state agency responsible for the regulation of private and investor-owned utilities. Environmental regulation is provided by the Missouri Department of Natural Resources and certain County authorities. The Fund is reviewing the allowable return on this facility and is in the process of initiating a rate case for this facility. It is anticipated that this process will be completed in 2007. HOLIDAY HILLS FACILITY The Holiday Hills Facility is a water distribution facility located in Taney County, Missouri, approximately 30 miles north of the Arkansas border, just outside the town of Branson. The facility primarily serves the Holiday Hills Resort and whole ownership condominiums, consisting of approximately 500 equivalent connections. The facility is owned by a wholly-owned subsidiary of AWRA. Currently approved water rates are US$3.00 minimum per month and a US$3.02 per 1,000 gal consumption charge. The Holiday Hills Facility is regulated by the Missouri Public Service Commission while environmental regulation is provided by the Missouri Public Service Commission and certain County authorities. The Fund is reviewing the allowable return on this facility and is in the process of initiating a rate case for this facility. It is anticipated that this process will be completed in 2007. OZARK MOUNTAIN FACILITY The Ozark Mountain Facility is a water distribution and water reclamation facility located in Stone County, approximately 30 miles west of Branson, Missouri, just outside Kimberling City, on the sloping shores of Table Rock Lake. The facility primarily serves the Ozark Mountain Resort and whole ownership condominiums, consisting of approximately 250 equivalent connections. The facility is owned by a wholly-owned subsidiary of AWRA. Currently approved water rates are US$3.00 minimum per month and a US$3.02 per 1,000 gal consumption charge. The approved water reclamation rates are US$6.00 per connection and US$7.57 per 1,000 gal average usage. The Ozark Mountain Facility is regulated by the Missouri Public Service Commission while environmental regulation is provided by the Missouri Department of Natural Resources and certain -69- County authorities. The Fund is reviewing the allowable return on this facility and is in the process of initiating a rate case for this facility. It is anticipated that this process will be completed in 2007. HOLLY RANCH FACILITY The Holly Ranch Facility is a water distribution and water reclamation facility located in Wood County, approximately 70 miles east of Dallas, Texas, just outside the town of Big Sandy. The facility primarily serves the Holly Lake Resort. The facility has a high component of single family homes (1,580) and approximately 130 condominium and timeshare units with approximately 1,800 equivalent connections. The facility is owned by a wholly-owned subsidiary of AWRA. The area is situated around a small captive lake and features amenities such as golf courses, trails and pools. It has historically grown at a rate of just over 3.5% annually, with limited marketing efforts. Currently approved water rates are US$21.36 minimum per month and US$1.94 per 1,000 gal consumption charge. The approved sewer rates are US$68.39 per connection and US$5.05 per 1,000 gal average usage. The facility operates under Texas Commission on Environmental Quality approved Certificate of Convenience and Necessity for water, and a permit for wastewater and is regulated by the Texas Commission on Environmental Quality. The facility discharges to Warren Swamp and then to Big Sandy Creek. BIG EDDY FACILITY The Big Eddy Facility is a water distribution and water reclamation facility located in Smith County, approximately 90 miles east of Dallas, Texas, just outside the town of Flint, on the shores of Lake Palestine. The facility primarily serves the Villages Resort with approximately 600 equivalent connections. The facility is owned by a wholly-owned subsidiary of AWRA. The area has become a recreational destination for boaters and other water sport enthusiasts. Currently approved water rates are US$21.36 minimum per month and US$1.94 per 1,000 gal consumption charge. The approved sewer rates are US$68.39 per connection and US$5.05 per 1,000 gal average usage. The facility operates under the same Certificate of Convenience and Necessity as the Holly Ranch Facility and a separate permit for wastewater and is regulated by the Texas Commission on Environmental Quality. The facility discharges via surface irrigation on 50 acres of land near the intersection of State Highway 155 and Farm-to-Market Road 2661 in Smith County, Texas. PINEY SHORES FACILITY The Piney Shores Facility is a water distribution and water reclamation facility located in Montgomery County, approximately 35 miles north of Houston, Texas, just outside the town of Conroe, on the shores of Lake Conroe. Lake Conroe is the principal fresh water body to Houston. The facility primarily serves the Piney Shores Resort with approximately 200 equivalent connections. The facility is owned by a wholly-owned subsidiary of AWRA. Currently approved water rates are US$21.36 minimum per month and US$1.94 per 1,000 gal consumption charge. The approved sewer rates are US$68.39 per connection and US$5.05 per 1,000 gal average usage. The facility operates under the same Certificate of Convenience and Necessity as the Holly Ranch -70- Facility and a separate permit for wastewater and is regulated by the Texas Commission on Environmental Quality. The facility discharges to an unnamed tributary to Lake Conroe. HILL COUNTRY FACILITY The Hill Country Facility is a water distribution and water reclamation facility located in Comel County, equidistant between San Antonio and Austin, Texas, in the Hill Country recreational area, on the shores of Canyon Lake. The facility primarily serves the HILL Country Resort with approximately 300 equivalent connections. The facility is owned by a wholly-owned subsidiary of AWRA. Currently approved water rates are US$21.36 minimum per month and US$1.94 per 1,000 gal consumption charge. The approved sewer rates are US$68.39 per connection and US$5.05 per 1,000 gal average usage. The facility operates under the same Certificate of Convenience and Necessity as the Holly Ranch Facility and is regulated by the Texas Commission on Environmental Quality. This facility uses lift stations that send effluent to the Guadalupe-Blanco River Authority for treatment as it does not have a wastewater permit. RIO RICO FACILITY The Rio Rico Facility is a water distribution and water reclamation facility located in Santa Cruz County, Arizona approximately 60 miles south of Tucson, Arizona. The facility serves approximately 5,400 water and 1,800 water reclamation sewer connections in the community of Rio Rico, Arizona. The facility is owned by AWRA. Currently approved water rates for a standard water meter are US$9.65 minimum charge and a three tiered commodity rate structure of US$1.44 per thousand for 0 to 4,000 gallons consumption, US$1.70 per thousand gallons for 5,000 to 10,000 gallons, and US$1.90 per thousand gallons for consumption greater than 10,000 gallons. Sewer rates vary with water meter size. The approved sewer rate for a typical dwelling unit is US$59.20. The facility has separate water and water reclamation Certificates of Convenience and Necessity and is regulated by the Arizona Corporation Commission. Wastewater is conveyed via the Rio Rico collection system to the Nogales Wastewater Treatment plant for treatment and effluent disposal. DECLARATION OF TRUST The Fund was created on September 8, 1997 pursuant to the Declaration of Trust with a view to the completion of an initial public offering of its Trust Units and the acquisition of direct or indirect equity interests in certain of the Fund Businesses. The following is a summary of certain provisions of the Declaration of Trust. For a complete description of the Trust Units and the Declaration of Trust, reference should be made to the Declaration of Trust. SOLE UNDERTAKING The Declaration of Trust provides that, notwithstanding any other provision thereof, the only undertaking of the Fund is (a) the investing of its funds in property (other than real property or an interest in real property), (b) the acquiring, holding, maintaining, improving, leasing or managing of any real -71- property (or an interest in real property) that is capital property of the Fund, or (c) any combination of the activities in (a) and (b). TRUSTEES The Trustees are entitled to compensation for services rendered to the Fund in their capacity as Trustees. Compensation has been established at $24,000 per year plus $1,500 for each meeting attended in person and $750 for each meeting attended by telephone per Trustee. As well, the Chairperson of each of the Trustees, the Audit Committee and the Corporate Governance Committee are entitled to receive additional remuneration from the Fund in the amount of $5,000 per year. The Declaration of Trust provides that, subject to the terms and conditions of the Declaration of Trust, the Trustees may, in respect of the trust assets and the business and affairs of the Fund, exercise any and all rights, powers and privileges that could be exercised by a legal and beneficial owner thereof. The number of Trustees will be not less than one nor more than seven. The Declaration of Trust prohibits non-residents of Canada (as that term is defined in the Tax Act), among others, from being Trustees. The Trustees are responsible for, among other things: (i) acting for, voting on behalf of and representing the Fund as a shareholder of Algonquin Holdco, an indirect shareholder and noteholder of Algonquin Canada, a unitholder of Algonquin Power Trust and a noteholder of Algonquin America; (ii) maintaining records and providing reports to Unitholders; (iii) supervising the activities and managing the investments and affairs of the Fund; and (iv) effecting payments of Distributable Cash from the Fund to Unitholders. A Trustee may resign upon written notice to the Fund and may be removed by a majority of the votes cast at a meeting of Unitholders and the vacancy created by such removal may be filled at the same meeting, failing which it may be filled by the Trustees. A quorum of the Trustees, being one Trustee at any time there is only one Trustee duly appointed or two Trustees at any time there are two or more Trustees duly appointed, may fill a vacancy in the Trustees, except a vacancy resulting from an increase in the number of Trustees or from a failure of the Unitholders to elect the required number of Trustees. In the absence of a quorum of the Trustees, or if the vacancy has arisen from a failure of the Unitholders to elect the minimum number of Trustees, the Trustees will forthwith call a special meeting of Unitholders to fill the vacancy. If the Trustees fail to call such meeting or if there are no Trustees then in office, any Unitholder may call the meeting. The Trustees may, between annual meetings of Unitholders, appoint up to two additional Trustees to serve until the next annual meeting of Unitholders. The Declaration of Trust provides that the Trustees will act honestly and in good faith with a view to the best interests of the Fund and in connection therewith will exercise the degree of care, diligence and skill that a reasonably prudent person would exercise in comparable circumstances. The Declaration of Trust provides that the Trustees will be entitled to indemnification from the Fund in respect of the performance of their duties under the Declaration of Trust in the absence of a breach of their duties and standard of care. The Declaration of Trust states that the duties and standard of care of the Trustees provided in the Declaration of Trust are intended to be similar to, and not greater than, those imposed on a director of a corporation governed by the Business Corporations Act. TRUST UNITS An unlimited number of Trust Units may be issued pursuant to the Declaration of Trust. Each Trust Unit is transferable and represents an equal undivided beneficial interest in any distribution from the Fund, whether of net income, net realized capital gains or other amounts, and in any net assets of the Fund -72- in the event of the termination or winding-up of the Fund. All Trust Units will rank among themselves equally and rateably without discrimination, preference or priority. Trust Units are not subject to future calls or assessments except that future offerings of Trust Units may be issuable for consideration payable in installments, in which case the Fund may take security over any such Trust Units, and each Trust Unit entitles the holder thereof to one vote for each whole Trust Unit held at all meetings of Unitholders. Except as set out under Declaration of Trust -- Redemption Right" below, the Trust Units have no conversion, retraction, redemption or pre-emptive rights. Additional Trust Units may be issued in the future. ISSUANCE OF TRUST UNITS The Declaration of Trust provides that Trust Units may be issued at the times, to the persons, for the consideration and on the terms and conditions that the Trustees determine. Trust Units may be issued in satisfaction of any non-cash distribution of the Fund to Unitholders on a pro rata basis. The Declaration of Trust also provides that immediately after any pro rata distribution of Trust Units to Unitholders in satisfaction of any non-cash distribution, the number of outstanding Trust Units will be consolidated such that each Unitholder will hold after the consolidation the same number of Trust Units as the Unitholder held before the non-cash distribution. In this case, each certificate representing a number of Trust Units prior to the non-cash distribution is deemed to represent the same number of Trust Units after the non-cash distribution and the consolidation. RESTRICTIONS ON DEBT The Declaration of Trust precludes the Fund from incurring indebtedness for borrowed money absent the passage of an Extraordinary Resolution, except in connection with the acquisition of additional facilities, provided certain criteria are met, and except for amounts in respect of previous acquisitions of facilities and amounts outstanding up to $1.5 million incurred for capital expenditures and operations related purposes for facilities in which the Fund has an interest. DISTRIBUTIONS See discussion in "Distribution Policy" below. REDEMPTION RIGHT Trust Units are redeemable at any time at the option of the holders thereof upon delivery to the Fund of the certificate or certificates representing such Trust Units, accompanied by a duly completed and properly executed notice requesting redemption. Upon receipt of the redemption request by the Fund, all rights of the holders with respect to the Trust Units tendered for redemption will cease and the holder thereof will only be entitled to receive a price per Trust Unit ("CASH REDEMPTION PRICE") equal to the lesser of: (i) 95% of the "market price" of the Trust Units on the principal market on which the Trust Units are quoted for trading during the ten trading day period commencing immediately after the date on which the Trust Units were tendered to the Fund for redemption (the "REDEMPTION DATE"); and (ii) the "closing market price" on the principal market on which the Trust Units are quoted for trading on the Redemption Date. For the purposes of this calculation, "market price" will be an amount equal to the weighted average trading price of the Trust Units for each of the trading days on which there was a closing price, provided that if the applicable exchange or market cannot provide a weighted average trading price, but only provides the highest and lowest prices of the Trust Units traded on a particular day, the "market price" will be an amount equal to the simple average of the average of the highest and lowest prices for -73- each of the trading days on which there was a trade; and provided further that if there was trading on the applicable exchange or market for fewer than five of the ten trading days, the "market price" will be the simple average of the following prices established for each of the ten trading days: (i) the average of the last bid and last ask prices of the Trust Units for each day on which there was no trading, (ii) the weighted average trading price of the Trust Units for each day that there was trading if the exchange or market provides a weighted average trading price; and (iii) the average of the highest and lowest prices of The Trust Units for each day that there was trading, if the market provides only the highest and lowest prices of Trust Units traded on a particular day. The "closing market price" will be: (i) an amount equal to the closing price of the Trust Units if there was a trade on the date; (ii) an amount equal to the average of the highest and lowest prices of Trust Units if there was trading and the exchange or other market provides only the highest and lowest prices of Trust Units traded on a particular day; or (iii) the average of the last bid and ask prices of the Trust Units if there was no trading on the date. The aggregate Cash Redemption Price payable by the Fund in respect of any Trust Units tendered for redemption during any calendar month will be satisfied by way of a cash payment on the last day of the following month, provided that the entitlement of Unitholders to receive such cash payment upon the redemption of their Trust Units is subject to the limitations that: (i) the total amount payable by the Fund in respect of such Trust Units and all other Trust Units tendered for redemption in the same calendar month will not exceed $250,000 (provided that such limitation may be waived at the discretion of the Trustees); (ii) at the time such Trust Units are tendered for redemption, the outstanding Trust Units will be listed for trading on the Toronto Stock Exchange or traded or quoted on any other market which the Trustees consider, in their sole discretion, provides representative fair market value prices for the Trust Units; and (iii) the normal trading of Trust Units is not suspended or halted on any stock exchange on which the Trust Units are listed for trading (or, if not listed on a stock exchange, on any market on which the Trust Units are quoted for trading) on the Redemption Date or for more than five trading days during the ten day trading period commencing immediately after the Redemption Date. If a Unitholder is not entitled to receive cash upon the redemption of Trust Units as a result of the foregoing limitations, then the redemption price for such Trust Units will be the fair market value thereof as determined by the Trustees, taking into account any taxes payable by the Fund arising from such redemption. The redemption price will, subject to any applicable regulatory approvals, be paid and satisfied by way of a pro rata distribution in specie of an interest in Fund Assets. No fractional shares, notes (based on increments of $100) or other securities, if any, will be distributed and, where the number of shares, notes and/or other securities, if any, to be received by a Unitholder includes a fraction, such number will be rounded to the next lowest whole number. MEETINGS OF UNITHOLDERS The Declaration of Trust provides that Unitholders may pass resolutions that bind the Trustees or the Fund only with respect to: the appointment or removal of Trustees (except filling casual vacancies); the appointment or removal of the auditors of the Fund; the approval of amendments to the Declaration of Trust (except as described under "Declaration of Trust - Amendments to the Declaration of Trust"); the appointment of an inspector; the sale of all or substantially all of the assets of the Fund (other than as part of an internal reorganization); and the termination of the Fund. Such resolutions must be passed by Extraordinary Resolution, except for the appointment or removal of Trustees or auditors of the Fund, which requires the approval of a majority of votes cast at a meeting of Unitholders. Meetings of Unitholders will be called and held annually for the election of Trustees and the appointment of auditors of the Fund. A special meeting of Unitholders may be called at any time by the Trustees and must be convened if requisitioned by the holders of not less than 10% of the Trust Units then outstanding (not -74- including Units beneficially owned by the Manager) by written requisition. A requisition must state in reasonable detail the business proposed to be transacted at such meeting. Unitholders may attend and vote at all meetings of Unitholders either in person or by proxy and a proxyholder need not be a Unitholder. Two individuals present in person or represented by proxy constitute a quorum for the transaction of business at all such meetings. The Declaration of Trust contains provisions as to the notice required and other procedures with respect to the calling and holding of meetings of Unitholders. EXERCISE OF VOTING RIGHTS ATTACHED TO ALGONQUIN CANADA SHARES The Declaration of Trust provides that the Fund will not authorize, either by agreement or by voting the Algonquin Canada Shares: (a) any amendment to the articles of Algonquin Canada or its subsidiaries to change or remove any restriction on the business of Algonquin Canada or its subsidiaries or change the authorized share capital or change or amend the rights, privileges, restrictions and conditions attaching to any class of shares of Algonquin Canada or its subsidiaries, as applicable; (b) any sale, lease or other disposition of all or substantially all of the property and assets of Algonquin Canada, except in the ordinary course of business; (c) any issue of shares in the capital of Algonquin Canada or its subsidiaries other than to the Fund, Algonquin Power Trust or any one or more of their wholly-owned subsidiaries, as applicable; (d) any amalgamation or other merger of Algonquin Canada or its subsidiaries with any other corporation, except with one or more wholly-owned subsidiaries of the Fund, Algonquin Power Trust or any one or more of their respective wholly-owned subsidiaries; or (e) any amendment to any unanimous shareholders' agreement entered into in respect of Algonquin Canada or its subsidiaries, or except as part of an internal reorganization of the Fund's assets including, without limitation, Algonquin Power Trust or any one or more wholly-owned subsidiaries of the Fund or Algonquin Power Trust or any one or more trusts of which the Fund is, directly or indirectly, the sole beneficiary. LIMITATION ON NON-RESIDENT OWNERSHIP In order for the Fund to maintain its status as a mutual fund trust under the Tax Act, the Fund must not be established or maintained primarily for the benefit of non-residents of Canada within the meaning of the Tax Act. Accordingly, the Declaration of Trust provides that at no time may non-residents be the beneficial owners of a majority of the Trust Units. If the Trustees or the transfer agent become aware that the beneficial owners of 49% of the Trust Units then outstanding are or may be non-residents or that such a situation is imminent, the Trustees or the transfer agent may make a public announcement thereof and will not accept a subscription for Trust Units from, or issue or register a transfer of Trust Units to, a person unless the person provides a declaration that the beneficial owner is not a non-resident. If, notwithstanding the foregoing, the Trustees or the transfer agent determine that a majority of the Trust Units are held by non-residents, the transfer agent may, or the Trustees may cause -75- the transfer agent to, send a notice to non-resident Unitholders, chosen in inverse order to the order of acquisition or registration or in such other manner as the Trustees or the transfer agent may consider equitable and practicable, requiring them to sell their Trust Units or a portion thereof within a specified period of not less than 60 days. If the Unitholders receiving such notice have not sold the specified number of Trust Units or provided the transfer agent with satisfactory evidence that the beneficial owners are not non-resident within such period, the transfer agent may on behalf of such Unitholder, sell such Trust Units and, in the interim, will suspend the voting and distribution rights attached to such Trust Units. Upon such sale, the affected holders will cease to be holders of Trust Units and their rights will be limited to receiving the net proceeds of sale upon surrender of the certificates representing such Trust Units. AMENDMENTS TO THE DECLARATION OF TRUST The Declaration of Trust may be amended or altered from time to time by Extraordinary Resolution. The Trustees may, without the approval of Unitholders, authorize certain amendments to the Declaration of Trust, including amendments: (a) for the purpose of ensuring continuing compliance with the applicable laws, regulations, requirements or policies of any governmental authority having jurisdiction over the Trustees or the Fund; (b) which, in the opinion of the Trustees, provide additional protection for the Unitholders; (c) to remove any conflicts or inconsistencies in the Declaration of Trust or to make corrections that are, in the opinion of the Trustees, necessary or desirable and not materially prejudicial to the rights of Unitholders; or (d) which, in the opinion of the Trustees, are necessary or desirable as a result of changes in or in the administration or interpretation of taxation laws. TERMINATION OF THE FUND The Fund has been established for a term ending 21 years after the date of the death of the last surviving issue of Her Majesty, Queen Elizabeth II, alive on September 8, 1997. The Declaration of Trust requires the Trustees to commence to wind-up the affairs of the Fund not more than two years prior to the end of the term of the Fund. In addition, at any time prior to the expiry of the term of the Fund, Unitholders may pass an Extraordinary Resolution to terminate the Fund, following which the Trustees are obligated to commence to wind-up the affairs of the Fund. TAKE-OVER BIDS The Declaration of Trust contains provisions to the effect that if a take-over bid is made for Trust Units and not less than 90% of the Trust Units (other than Trust Units held at the date of the take-over bid by or on behalf of the offeror or associates or affiliates of the offeror) are taken up and paid for by the offeror, the offeror will be entitled to acquire the Trust Units held by Unitholders who did not accept the offer on the terms offered by the offeror. -76- REPORTING TO UNITHOLDERS The Fund will furnish to the Unitholders such financial statements (including quarterly and annual financial statements) and other reports as are from time to time required by applicable law, including prescribed forms needed for the completion of Unitholders' tax returns under the Tax Act and equivalent provincial legislation. Each of the Fund Businesses controlled by the Fund has undertaken to provide the Fund with: (i) a report of any material change that occurs in its affairs in form and content that it would file with applicable regulatory authorities if it were a reporting issuer; and (ii) all financial statements that it would be required to file with applicable regulatory authorities if it were a reporting issuer under applicable securities laws. All such reports and statements will be provided to the Fund in a timely manner so as to permit the Fund to comply with the continuous disclosure requirements relating to reports of material changes in its affairs and the delivery of financial statements as required under applicable securities laws. Prior to each meeting of Unitholders, the Fund will provide Unitholders with information similar to that required to be provided to shareholders of an Ontario public company, along with notice of such meeting. GOVERNANCE, MANAGEMENT AND OPERATIONS MANAGEMENT AGREEMENT Algonquin Canada, Algonquin Holdco and Algonquin Power Trust (collectively, "ALGONQUIN") and the Manager are parties to the Management Agreement, under which the Manager provides management services (the "MANAGEMENT SERVICES") for the Fund Businesses. The Management Services provided include advice and consultation concerning business planning, support, guidance and policy making and general management services. Senior officers of the Manager also act as senior officers of the Fund's related entities. Specific functions performed by the Manager include: (i) managing accounting and financial services; (ii) assisting in the preparation of financial statements; (iii) negotiating and communicating with third parties with respect to contractual and other matters; (iv) arranging external professional and non-professional services; (v) assisting in providing human resources; and (vi) advising on acquisitions and sales of subsidiaries and/or businesses. In exercising its powers and discharging its duties under the Management Agreement, the Manager is required to exercise the degree of care, diligence and skill that a reasonable, prudent advisor or manager having responsibility for management of a similar business would exercise in comparable circumstances. The Manager is compensated for its services as follows: (i) the Manager is paid an annual fee of $661,308 per calendar year payable in quarterly instalments of $165,327, adjusted annually for changes in the Canadian consumer price index (the "ANNUAL FEE"); (ii) the Manager is paid incentive fees based on 25% of Distributable Cash per Trust Unit in excess of $0.92 per annum; and (iii) the Manager is reimbursed for its costs and expenses incurred in the performance of the Management Services. The Manager is not entitled to any acquisition-based incentive fees. For the fiscal period ended December 31, 2005, the Fund, directly or indirectly, paid to the Manager a total of $0.8 million, including the Annual Fee, benefits expenses and reimbursement of out-of-pocket expenses incurred in connection with its duties under the Management Agreement. No incentive fees were paid to the Manager in 2005. -77- The Management Agreement's term expires on December 31, 2012 and on expiry of the initial term, is renewable for rolling five year terms. Algonquin or the Manager may terminate the Management Agreement immediately in the event of the insolvency or receivership of the other party or in the case of default by the other party in a material obligation under the Management Agreement which is not remedied within thirty (30) days, other than a failure of performance which results from an event of force majeure. In addition, Algonquin may terminate the Management Agreement on thirty (30) days notice to the Manager if there is a substantial deterioration in the businesses of Algonquin and the Unitholders approve the termination by extraordinary resolution or there is a change of control of the Manager, other than a change of control to which the Fund consents. The Manager may terminate the Management Agreement at any time on twelve (12) months' notice. The Manager holds special voting shares of Algonquin Canada and Algonquin America which confer upon the Manager the right to elect two of the three directors of Algonquin Canada and all of the directors of Algonquin America. These shares carry no other right to vote and no material economic benefit and may be purchased by the Fund, or Algonquin Canada or Algonquin America, as applicable, at their issue price upon termination or expiry of the Management Agreement. The Management Agreement contains provisions to regulate any conflicts of interest which may arise and provides for indemnification by the Manager of Algonquin in certain circumstances. The Management Agreement may be assigned by the Manager only with the consent of Algonquin. The head office of the Manager is located at 2845 Bristol Circle, Oakville, Ontario L6H 7H7. OPERATIONS SUPERVISORY AGREEMENT Algonquin and Power Systems are parties to the Operation Supervisory Agreement, pursuant to which Power Systems provides certain operations related services which are beyond the scope of the operations and maintenance services agreements which have been entered into between the entities which own the various facilities and Power Systems. Specific functions include: (i) planning of capital repairs; (ii) compliance monitoring for environmental permits; and (iii) administration of power purchase agreements. It contains similar provisions regarding standard of care and conflicts of interest as the Management Agreement. Power Systems does not receive any payment of fees in connection with its services under the Operations Supervisory Agreement and is now paid on a cost reimbursement basis only. For the fiscal period ended December 31, 2005, the Fund, directly or indirectly, paid to Power Systems a total of $13.9 million, which amounts relate solely to expenses for which Power Systems was reimbursed pursuant to the amended Operations Supervisory Agreement. The Operations Supervisory Agreement is coterminous with the Management Agreement. The head office of Power Systems is located at 2845 Bristol Circle, Oakville, Ontario L6H 7H7. ADMINISTRATION AGREEMENT The Manager administers the Fund pursuant to the Administration Agreement entered into between the Fund and the Manager under which it is responsible for the administration and management of the affairs of the Fund. Specific functions include, among other things: (i) preparing all returns, filings and documents; (ii) providing advice with respect to the Fund's obligations as a reporting issuer; (iii) providing investor relations services; and (iv) providing audit, accounting, engineering, legal, insurance -78- and other professional services. The Manager is reimbursed for its reasonable out-of-pocket expenses incurred in administering the Fund. These expenses are included in the $0.8 million, including reimbursable expenses, paid to the Manager under the Management Agreement for the fiscal period ended December 31, 2005. The Administration Agreement is coterminous with the Management Agreement. DIRECT OPERATIONS AGREEMENTS Direct operations and maintenance services are generally comprised of those services necessary for a facility to continue to operate under typical circumstances. Such services include the provision of direct operating labour, management of available water/fuel resources, monitoring and reporting on facility performance, performance of scheduled maintenance tasks and completion of minor repairs as required. Power Systems has entered into agreements with Fund entities which own generating facilities to provide such services. The Fund, directly or indirectly, paid to Power Systems an aggregate amount of approximately $13.9 million during 2005, which amount was paid on a cost reimbursement basis pursuant to the amended Operations Supervisory Agreement and the direct operations agreements. In addition, the entities which own the water distribution and wastewater treatment facilities to provide similar services paid AWS an aggregate amount totaling approximately $5.5 million for services during 2005, also on a cost reimbursement basis. CONTINGENCY REPAIR AND CAPITAL IMPROVEMENT PROJECTS Power Systems also manages the contingency repair and capital improvement projects for the owners of certain generating facilities. The annual repair and maintenance expenditures during 2005 were approximately $8.1 million, which amount was paid to Power Systems on a cost reimbursement basis and is included in the $13.9 million paid to Power Systems under the Operations Supervisory Agreement and the direct operations agreements referred to above. GOVERNANCE AGREEMENT Pursuant to the Governance Agreement, the Manager is entitled to appoint two directors to Algonquin Holdco's and Algonquin Canada's board of directors, with the Fund being entitled to appoint one director. Although there is currently one trustee of Algonquin Power Trust, the Manager also has the right to increase the number of trustees to three and appoint two of the trustees. The articles of Algonquin Canada and Algonquin Holdco provide that the number of directors is fixed at three. The Governance Agreement will remain in force for so long as the Management Agreement remains in force and provides that the Fund will not vote for any amendment to Algonquin Canada's or Algonquin Holdco's articles or Algonquin Power Trust's declaration of trust, including an amendment with respect to the number of directors, without the Manager's approval. The Governance Agreement further provides that the Fund will comply with the Manager's instructions with respect to the appointment, removal and replacement of the Manager's nominees to the board of directors of Algonquin Canada and Algonquin Holdco (or trustee of Algonquin Power Trust, if applicable). Notwithstanding the foregoing, the Fund will be entitled to remove the Manager's nominees as directors of Algonquin Canada and Algonquin Holdco (or trustee of Algonquin Power Trust, if applicable) or amend Algonquin Canada's or Algonquin Holdco's articles or Algonquin Power Trust's declaration of trust, if: (a) Algonquin Canada, Algonquin Holdco or Algonquin Power Trust does not comply with or prevents the implementation of their distribution policy; -79- (b) any of the Fund Businesses does not comply with or prevent the implementation of its distribution policy; (c) any amendment is made to the partnership agreement in respect of any of the Fund Businesses which are partnerships without the consent of the Fund; (d) there is a change of control of the Manager (other than a change of control to which the Fund consents); (e) other than in the ordinary course of business and without the prior written consent of the Fund, any of the Fund Businesses undertakes a material change in its business, incurs any material debt or issues any securities other than to another such entity or the Fund; or (f) the Management Agreement expires or is terminated. TRUST UNIT AND LOAN CAPITAL OF THE FUND TRUST UNIT CAPITAL OF THE FUND The Fund presently has 69,691,592 Trust Units outstanding. See "Declaration of Trust" for a description of the rights, attributes, privileges and conditions attaching to the Trust Units. LOAN CAPITAL OF THE FUND LINE OF CREDIT The Fund has available a line of credit (the "CREDIT LINE") provided by a syndicate of Canadian banks in the maximum principal amount of $145.0 million, which was renewed by the Fund on August 30, 2005. The Credit Line provides for a general operating facility of $20.0 million, provisions of letters of guarantee of approximately $45.0 million and the balance for acquisition funding purposes. On March 3, 2006, the Fund reached an agreement with its lenders to temporarily increase the Credit Line to $175.0 million. As of December 31, 2005, the Fund had approximately $69.3 million outstanding under the Credit Line for acquisition purposes. In addition, the Fund has used the Credit Line to post (i) a letter of credit in the approximate amount of US$19.5 million in respect of bond liabilities assumed in connection with the acquisition of the Sanger Facility, (ii) a $1 million letter of credit to the Minister of the Environment (Alberta) pursuant to the Use of Works Agreement in respect of the Dickson Dam Facility; (iii) letters of credit for the EFW Facility totaling $4.5 million, (iv) letter of credit to Manitoba Hydro in respect of the St. Leon Facility totaling $0.8 million, (v) letter of credit to Niagara Mohawk in respect of the LFG Facilities totaling US$0.9 million, (vi) letter of credit to the main contractor in respect of the construction of the St. Leon Facility totaling $14.6 million, and (vii) letter of credit to the municipal governments in respect of the installation of additional steam generation and transmission assets required for the sale of steam from the EFW Facility totaling $0.1 million. No funds were drawn on the Credit Line for general operating purposes. As security for repayment of such line of credit, the Fund has, among other things, provided a fixed and floating charge over all Fund Businesses and pledged the shares of certain Fund entities to the banking syndicate. As a requirement of the Credit Line, the Fund has to maintain certain financial covenants. The Fund is in material compliance with the terms of the agreements governing the Credit Line and no waiver of any breach has occurred thereunder. -80- Interest While the Fund maintains a credit rating of triple B plus ('BBB+'), any amounts outstanding under the Credit Line bears interest at a rate equal to the banker's acceptance or London Interbank Offered Rate (LIBOR) plus a margin of 1.125% with no additional margins. Interest is payable monthly. The unused portion of the Credit Line attracts an annual standby fee equal to 0.30% payable quarterly. These rates will change should the credit rating of the Fund change. Redemption The credit agreement in respect of the Credit Line stipulates that the amount outstanding under the Credit Line is due and payable on maturity (August 30, 2007). FUND DEBENTURES The Fund issued the Fund Debentures under and pursuant to the provisions of the Trust Indenture. The Fund Debentures are limited in the aggregate principal amount of $85,000,000, which amount is currently outstanding. The Fund may, however, from time to time, without the consent of the holders of the Fund Debentures, issue additional debentures. For a complete description of the Fund Debentures, reference should be made to the Trust Indenture. Conversion Privilege The Fund Debentures are convertible at the holder's option into fully paid, non-assessable and freely-tradeable Trust Units at any time prior to 5:00 p.m. (Toronto time) on the earlier of July 31, 2011 (the "MATURITY DATE") and the business day immediately preceding the date specified by the Fund for redemption of the Fund Debentures, at a conversion price of $10.65 per Trust Unit (the "CONVERSION PRICE") being a ratio of approximately 93.8967 Trust Units per $1,000 principal amount of Fund Debentures. The Fund Debentures bear interest from the date of issue at 6.65% per annum, which will be payable semi-annually on July 31 and January 31 in each year, commencing on January 31, 2005 (each, an "INTEREST PAYMENT DATE"). No adjustment will be made for distributions on Trust Units issuable upon conversion or for interest accrued on Fund Debentures surrendered for conversion; however, holders converting their Fund Debentures are entitled to receive, in addition to the applicable number of Trust Units, accrued and unpaid interest in respect thereof for the period up to the date of conversion from the latest Interest Payment Date. Notwithstanding the foregoing, no Fund Debentures may be converted on any Interest Payment Date and during the five business days preceding January 31 and July 31 in each year, as the registers of the Debenture Trustee are closed during such periods. The Trust Indenture provides for the adjustment of the Conversion Price in certain events including: (a) the subdivision or consolidation of the outstanding Trust Units; (b) the distribution of Trust Units to holders of Trust Units by way of distribution or otherwise other than an issue of securities to holders of Trust Units who have elected to receive distributions in securities of the Fund in lieu of receiving cash distributions paid in the ordinary course; (c) the issuance of options, rights or warrants to holders of Trust Units entitling them to acquire Trust Units or other securities convertible into Trust Units at less than 95% of the then Current Market Price (as defined below under "Fund Debentures -- Payment upon Redemption or Maturity") of the Trust Units; and (d) the distribution to all holders of Trust Units of any securities or assets (other than cash distributions and equivalent distributions in securities paid in lieu of cash -81- distributions in the ordinary course). There will be no adjustment of the Conversion Price in respect of any event described in (b), (c) or (d) above if, subject to prior regulatory approval, the holders of the Fund Debentures are allowed to participate as though they had converted their Fund Debentures prior to the applicable record date or effective date. The Fund will not be required to make adjustments in the Conversion Price unless the cumulative effect of such adjustments would change the Conversion Price by at least 1%. In the case of any reclassification or change (other than a change resulting only from consolidation or subdivision) of the Trust Units or in case of any amalgamation, consolidation or merger of the Fund with or into any other entity, or in the case of any sale, transfer or other disposition of the properties and assets of the Fund as, or substantially as, an entirety to any other entity, the terms of the conversion privilege shall be adjusted so that each Fund Debenture shall, after such reclassification, change, amalgamation, consolidation, merger or sale, be exercisable for the kind and amount of securities or property of the Fund, or such continuing, successor or purchaser entity, as the case may be, which the holder thereof would have been entitled to receive as a result of such reclassification, change, amalgamation, consolidation, merger or sale if on the effective date thereof it had been the holder of the number of Trust Units into which the Fund Debenture was convertible prior to the effective date of such reclassification, change, amalgamation, consolidation, merger or sale. No fractional Trust Units will be issued on any conversion of the Fund Debentures, but in lieu thereof, the Fund shall satisfy such fractional interest by a cash payment equal to the Current Market Price of such fractional interest. Redemption and Purchase The Fund Debentures may not be redeemed by the Fund on or before July 31, 2007 (except in the case of a change of control). Thereafter, but prior to July 31, 2009, the Fund Debentures may be redeemed at the option of the Fund, in whole at any time or in part from time to time, on not more than 60 days' and not less than 30 days' prior notice, at a redemption price equal to the principal amount thereof plus accrued and unpaid interest, provided that the weighted-average trading price of the Trust Units on the TSX for the 20 consecutive trading days ending five trading days preceding the date on which notice of redemption is given exceeds 125% of the Conversion Price. On or after July 31, 2009 and prior to the Maturity Date, the Fund Debentures may be redeemed by the Fund, in whole or in part from time to time, on not more than 60 days' and not less than 30 days' prior notice, at a redemption price equal to the principal amount thereof plus accrued and unpaid interest. The Fund will have the right to purchase Fund Debentures in the market, by tender or by private contract subject to regulatory requirements; provided, however, that if an Event of Default (as defined below) has occurred and is continuing, the Fund will not have the right to purchase the Fund Debentures by private contract. In the case of redemption of less than all of the Fund Debentures, the Fund Debentures to be redeemed will be selected by the Debenture Trustee on a pro rata basis or in such other manner as the Debenture Trustee deems equitable, subject to the consent of the TSX. -82- Payment upon Redemption or Maturity On redemption or on the Maturity Date, the Fund will repay the indebtedness represented by the Fund Debentures by paying to the Debenture Trustee in lawful money of Canada an amount equal to the principal amount of the outstanding Fund Debentures, together with accrued and unpaid interest thereon. The Fund may, at its option, on not more than 60 days' and not less than 40 days' prior notice and subject to any required regulatory approvals, unless an Event of Default (as defined below) has occurred and is continuing, elect to satisfy its obligation to repay, in whole or in part, the principal amount of the Fund Debentures which are to be redeemed or which have matured by issuing and delivering freely tradeable Trust Units to the holders of the Fund Debentures. The number of Trust Units to be issued will be determined by dividing the principal amount of the Fund Debentures which are to be redeemed by 95% of the Current Market Price of the Trust Units on the date fixed for redemption or the maturity date, as the case may be. No fractional Trust Units will be issued to holders of Fund Debentures but in lieu thereof the Fund shall satisfy such fractional interest by a cash payment equal to the Current Market Price of such fractional interest. The term "CURRENT MARKET PRICE" is defined in the Trust Indenture to mean the weighted average trading price of the Trust Units on the TSX for the 20 consecutive trading days ending on the fifth trading day preceding the date of the applicable event. Unit Interest Payment Election Unless an Event of Default (as defined below) has occurred and is continuing, the Fund may elect, from time to time, subject to applicable regulatory approval, to issue and deliver freely-tradeable Trust Units to its agent for sale in order to raise funds to satisfy the Fund's obligations to pay interest on the Fund Debentures in accordance with the Trust Indenture (the "UNIT INTEREST PAYMENT ELECTION") in which event holders of the Fund Debentures will be entitled to receive a cash payment equal to the interest payable from the proceeds of the sale of such Trust Units by the agent. The Trust Indenture provides that upon such election, the agent shall (i) accept delivery of Trust Units from the Fund, (ii) accept bids with respect to, and consummate sales of, such Trust Units, each as the Fund shall direct in its absolute discretion, (iii) invest the proceeds of such sales in short-term Canadian government obligations which mature prior to the applicable Interest Payment Date and deliver proceeds to holders of Fund Debentures sufficient to satisfy the Fund's interest payment obligations; and (iv) perform any other action necessarily incidental thereto. The amount received by a holder in respect of interest will not be affected by whether or not the Fund elects to utilize the Unit Interest Payment Election. Neither the Fund's making of the Unit Interest Payment Election nor the consummation of sales of Trust Units pursuant thereto will (a) result in the holders of Fund Debentures not being entitled to receive on the applicable Interest Payment Date cash in an aggregate amount equal to the interest payable on such Interest Payment Date, or (b) entitle such holders to receive any Trust Units in satisfaction of the interest payable on the applicable interest payment date. Cancellation All Fund Debentures converted, redeemed or purchased as aforesaid will be cancelled and may not be reissued or resold. -83- Subordination The payment of the principal of, and interest on, the Fund Debentures is subordinated in right of payment, in the circumstances referred to below and more particularly as set forth in the Trust Indenture, to the prior payment in full of all Senior Indebtedness of the Fund. "SENIOR INDEBTEDNESS" of the Fund is defined in the Trust Indenture as all indebtedness of the Fund, other than the Fund Debentures, (whether outstanding as at the date of the Indenture or thereafter created, incurred, assumed or guaranteed), and including, for greater certainty, claims of trade creditors of the Fund, which by the terms of the instrument creating or evidencing the indebtedness, is not expressed to be pari passu with, or subordinate in right of payment to, the Fund Debentures. The Trust Indenture provides that in the event of any insolvency or bankruptcy proceedings, or any receivership, liquidation or reorganization in connection with or as a result of an insolvency or bankruptcy proceeding or other similar proceedings relative to the Fund, or to its property or assets, or in the event of any proceedings for voluntary liquidation, dissolution or other winding up of the Fund, whether or not involving insolvency or bankruptcy, or any marshalling of the assets and liabilities of the Fund, all creditors under any Senior Indebtedness will receive payment in full before the holders of Fund Debentures will be entitled to receive any payment or distribution of any kind or character, whether in cash, property or securities, which may be payable or deliverable in any such event in respect of any of the Fund Debentures or any unpaid interest accrued thereon. In addition to the foregoing, pursuant to the terms of the Trust Indenture, neither the Debenture Trustee for, nor the holders of, the Fund Debentures are entitled to demand or otherwise attempt to enforce in any manner, institute proceedings for the collection of, or institute any proceedings against the Fund, including, without limitation, by way of any bankruptcy, insolvency or similar proceedings or any proceeding for the appointment of a receiver, liquidator, trustee or other similar official (it being understood and agreed that the Debenture Trustee and/or the holders of the Fund Debentures are permitted to take any steps necessary to preserve the claims of the holders of Fund Debentures in any such proceeding and any steps necessary to prevent the extinguishment or other termination of a claim or potential claim as a result of the expiry of a limitation period), or receive any payment or benefit in any manner whatsoever on account of indebtedness represented by the Fund Debentures other than as set forth in the Trust Indenture at any time when (i) an event of default (howsoever designated) has occurred and is continuing under the Credit Line, or (ii) an event of default (howsoever designated) has occurred under any other Senior Indebtedness and is continuing and, in each case, notice of such event of default has been given by or on behalf of the lender or lenders party to such Senior Indebtedness to the Fund or an affiliate thereof that is the borrower pursuant to such Senior Indebtedness (the "SENIOR INDEBTEDNESS POSTPONEMENT PROVISIONS"). The Fund Debentures are also subordinate to claims of creditors of the Fund. Priority over Trust Unit Distributions The Declaration of Trust provides that certain expenses and liabilities of the Fund must be deducted in calculating the amount to be distributed to Unitholders. Accordingly, the funds required to satisfy the interest payable on the Fund Debentures, as well as the amount payable upon redemption or maturity of the Fund Debentures or upon an Event of Default (as defined below), will be deducted and withheld from the amounts that would otherwise be available for payment as distributions to Unitholders. -84- Put Right upon a Change of Control Upon the occurrence of a change of control of the Fund involving the acquisition of voting control or direction over 66 2/3% or more of the outstanding Trust Units by any person or group of persons acting jointly or in concert (a "CHANGE OF CONTROL"), each holder of Fund Debentures may require the Fund to purchase, on the date which is 30 days following the giving of notice of the Change of Control as set out below (the "PUT DATE"), the whole or any part of such holder's Fund Debentures at a price equal to 101% of the principal amount thereof (the "PUT PRICE") plus accrued and unpaid interest to the Put Date. If 90% or more in the aggregate principal amount of the Fund Debentures outstanding on the date of the giving of notice of the Change of Control have been tendered for purchase on the Put Date, the Fund will have the right to redeem all the remaining Fund Debentures on such date at the Put Price, together with accrued and unpaid interest to such date. Notice of such redemption must be given to the Debenture Trustee prior to the Put Date and as soon as possible thereafter, by the Debenture Trustee to the holders of the Fund Debentures not tendered for purchase. The principal on the Fund Debentures will be payable in lawful money of Canada or, at the option of the Fund and subject to applicable regulatory approval, by payment of Fund Units to satisfy, in whole or in part, its obligation to repay the principal amount of the Fund Debentures. The Trust Indenture contains notification provisions to the effect that: (a) the Fund will promptly give written notice to the Debenture Trustee of the occurrence of a Change of Control and the Debenture Trustee will thereafter give to the holders of Fund Debentures a notice of the Change of Control, the repayment right of the holders of Fund Debentures and the right of the Fund to redeem untendered Fund Debentures under certain circumstances; and (b) a holder of Fund Debentures, to exercise the right to require the Fund to purchase its Fund Debentures, must deliver to the Debenture Trustee, not less than five business days prior to the Put Date, written notice of the holder's exercise of such right, together with a duly endorsed form of transfer. The Fund will comply with the requirements of Canadian securities laws and regulations to the extent such laws and regulations are applicable in connection with the repurchase of the Fund Debentures in the event of a Change of Control. Modification The rights of the holders of the Fund Debentures as well as any other series of debentures that may be issued under the Trust Indenture may be modified in accordance with the terms of the Trust Indenture. For that purpose, among others, the Trust Indenture contains certain provisions which will make binding on all holders of Fund Debentures resolutions passed at meetings of the holders of Fund Debentures by votes cast thereat by holders of not less than 66 2/3% of the principal amount of the then outstanding Fund Debentures present at the meeting or represented by proxy, or rendered by instruments in writing signed by the holders of not less than 66 2/3% of the principal amount of the then outstanding Fund Debentures. In certain cases, the modification will, instead of or in addition to, require assent by the holders of the required percentage of Fund Debentures of each particularly affected series. Under the Trust Indenture, the Debenture Trustee has the right to make certain amendments to the Trust Indenture in its discretion, without the consent of the holders of Fund Debentures. -85- Events of Default The Trust Indenture provides that an event of default ("EVENT OF DEFAULT") in respect of the Fund Debentures will occur if certain events described in the Trust Indenture occur, including if any one or more of the following described events has occurred and is continuing with respect to the Fund Debentures: (i) failure for 15 days to pay interest on the Fund Debentures when due; (ii) failure to pay principal or premium, if any, on the Fund Debentures, whether at maturity, upon redemption, by declaration or otherwise; or (iii) certain events of bankruptcy, insolvency or reorganization of the Fund under bankruptcy or insolvency laws. Subject to the Senior Indebtedness Postponement Provisions, if an Event of Default has occurred and is continuing, the Debenture Trustee may, in its discretion, and shall, upon the request of holders of not less than 25% in principal amount of the then outstanding Fund Debentures, declare the principal of (and premium, if any) and interest on all outstanding Fund Debentures to be immediately due and payable. Offers for Debentures The Trust Indenture contains provisions to the effect that if an offer is made for the Fund Debentures which is a take-over bid for Fund Debentures within the meaning of the Securities Act (Ontario) and not less than 90% of the Fund Debentures (other than Fund Debentures held at the date of the take-over bid by or on behalf of the offeror or associates or affiliates of the offeror) are taken up and paid for by the offeror, the offeror will be entitled to acquire the Fund Debentures held by holders of Fund Debentures who did not accept the offer on the terms offered by the offeror. Limitation on Non-Resident Ownership At no time may non-residents of Canada be the beneficial owners of a majority of the outstanding Trust Units (on a fully-diluted basis). The Fund may require declarations as to the jurisdictions in which beneficial owners of Fund Debentures are resident. If the Fund becomes aware that the beneficial owners of 49% of the Trust Units then outstanding (on a fully-diluted basis) are, or may be, non-residents, or that such a situation is imminent, the Fund may make a public announcement thereof and shall cause the Debenture Trustee or the transfer agent and registrar of the Trust Units (the "TRANSFER AGENT") not to register a transfer of Fund Debentures or Trust Units to a person unless the person provides a declaration that the person is not a non-resident. If, notwithstanding the foregoing, the Fund determines that a majority of the outstanding Trust Units (on a fully-diluted basis) are held by non-residents, the Fund may send a notice to non-resident holders of Fund Debentures or Trust Units, chosen in inverse order to the order of acquisition or registration of the Fund Debentures and Trust Units or in such manner as the Fund may consider equitable and practicable, requiring them to sell their Fund Debentures or Trust Units or a portion thereof within a specified period of not less than 60 days. If the holders of Fund Debentures or Unitholders receiving such notice have not sold the specified number of Fund Debentures or Trust Units or provided the Fund with satisfactory evidence that they are not non-residents within such period, the Fund or an agent appointed for this purpose may on behalf of such Fund Debenture holder or Unitholder sell such Fund Debentures or Trust Units, as the case may be, and, in the interim, shall suspend the rights attached to such Fund Debentures or Trust Units. Upon such sale, the affected holders shall cease to be holders of Fund Debentures or Trust Units, as the case may be, and their rights shall be limited to receiving the net proceeds of sale upon surrender of such Fund Debentures or Trust Units. -86- Interest The Fund Debentures bear interest from the date of issue at 6.65% per annum, which will be payable semi-annually on July 31 and January 31 in each year, commencing on January 31, 2005. The first payment includes accrued and unpaid interest for the period from the closing of the offering to January 31, 2005. Interest will be payable based on a 365-day year. At the option of the Fund, subject to applicable law, the Fund may deliver Trust Units to its agent who shall sell such Trust Units on behalf of the Fund in order to raise funds to satisfy all or any part of the Fund's obligations to pay interest on the Fund Debentures, but in any event, the holders of Fund Debentures shall be entitled to receive cash payments equal to the interest otherwise payable on the Fund Debentures. Priority of Debt The Fund Debentures will be direct obligations of the Fund and will not be secured by any mortgage, pledge, hypothec or other charge and will be subordinated to other liabilities of the Fund. The Trust Indenture does not restrict the Fund from incurring additional indebtedness for borrowed money or from mortgaging, pledging or charging its assets to secure any indebtedness. THE INDEPENDENT POWER GENERATION INDUSTRY As mentioned above, the Fund is primarily engaged indirectly in the business of generating and marketing electrical energy within the independent power generation industry. GENERAL Hydroelectric A hydroelectric generating facility consists of a number of components, including a dam, headrace canal or penstock, intake structure, electromechanical equipment consisting of a turbine(s), a generator(s), draft tube and tailrace canal. In addition, there are electrical switchgear and controls equipment which are necessary to interconnect the facility with the receiving electrical grid system. A dam structure is required to create or increase the natural elevation difference between the upstream reservoir and the downstream tailrace (referred to as "HEAD"), as well as to provide sufficient depth within the reservoir for an intake. Dam structures are also used to create an upstream reservoir which allows water to be stored within a headpond. Virtually all dam structures used for hydroelectric generation purposes have spillways for discharging water which is surplus to the demand of the generating station. A spillway dam can be either an overtopping section of the dam (uncontrolled spillway) or an opening within the dam itself (sluiceway). Sluiceway structures must be equipped with a mechanism for blocking the opening(s) during periods when the hydroelectric generating facility can adequately handle the river flow. This can be accomplished using a variety of methods ranging from simple wooden logs (referred to as stoplogs) to automatically controlled and sophisticated steel gates. Water flows are conveyed from the upstream reservoir to the generating equipment via a penstock or headrace canal. A penstock is a pipeline capable of operating under pressure, and is normally constructed of steel or other suitable materials. A headrace canal is a channel which conveys water from the reservoir to the intake in a hydraulically efficient manner. The intake structure is a water intake located at the entrance to a penstock or at the end of a headrace canal. The purpose of the intake structure is to collect water from the upstream reservoir. Intake -87- structures are normally equipped with steel or plastic screens (referred to as trashracks) which prevent debris and ice found in the reservoir from entering into the turbine equipment. Intake structures must be adequately submerged to prevent the entertainment of air into the water passages. The electromechanical equipment consists of the turbine(s) and generator(s) used to transform the hydraulic energy into electrical energy. A turbine is a series of blades which rotate a shaft as a result of water flowing over or through the blades. A variety of turbines are used depending on the site. The generator is connected to the turbine (sometimes using a gearbox) and converts mechanical energy into electrical energy. The electromechanical equipment is typically contained within a powerhouse building. The purpose of the powerhouse is to provide a solid structural foundation for the equipment and protect the equipment from the environment. The water which has flowed through the hydraulic turbine(s) is discharged back to the natural watercourse through a draft tube and tailrace. The purpose of these two components is to return the flows back to the environment in a "hydraulically smooth" fashion. The electrical equipment consists of switchgear, controls, a transformer substation and frequently a transmission line. The purpose of the electrical equipment is to transform the electrical energy produced by the generator into a form which is acceptable to the receiving electrical grid. This usually involves increasing the voltage and controlling the electrical frequency. A transmission line is often required to interconnect a facility with the grid. The majority of hydroelectric generating facilities are also equipped with remote monitoring equipment, which allows the facility to be monitored and operated from a remote location. Energy from Waste In North America and elsewhere, the combination of increasing population and stricter environmental regulations has imposed increasing limitations upon the development of new municipal landfills and on the expansion of existing landfills. To reduce the total tonnage of municipal waste being directed to landfills and to extract greater value from existing landfills, considerable effort is being directed toward the establishment of energy from waste facilities. The establishment of energy from waste facilities is now a licenced process in certain states of the United States, Canadian provinces and in other countries. Cogeneration Cogeneration is the simultaneous production of electricity and thermal energy such as hot water or steam from a single fuel source. Often natural gas is used to produce both electricity and steam. The steam produced is normally required by an associated or nearby commercial facility, while the electricity generated is sold to a utility or used within the facility. Cogeneration provides facilities with greater efficiency, greater reliability and increased process flexibility than conventional generation methods. Examples of industries using cogeneration facilities include food processing, pulp and paper and chemical plants. Where both electrical and thermal energy are generated separately, typically one third to one half of the fuel's energy content is converted into useful energy output such as steam or electricity. The remainder is wasted energy which escapes as unused heat. By producing electricity and steam simultaneously, cogeneration uses a higher proportion of the fuel's energy content. Depending on the degree of steam and/or useful heat utilization, 55% to 80% of the fuel's energy content is converted into -88- useful energy output, which produces significant fuel savings over conventional arrangements. Cogeneration compared to conventional processes also has environmental benefits as it results in burning less fuel and producing less carbon dioxide. Furthermore, in cogeneration facilities which use fuels such as natural gas or oil, sulphur dioxide and nitrous oxide emissions are greatly reduced compared to other technologies and fuels. Landfill Gas Generation Many landfill sites produce gas which can be burned to produce energy. Typically, an underground pipe system is installed and the gas produced is compressed and the pressurized gas is then piped off to engines or turbines to be burned to generate electricity. Wind Power Generation The energy of the wind can be harnessed for the production of electricity through the use of wind turbines. A wind energy system transforms the kinetic energy of wind into electrical energy that can be delivered to the electricity distribution system for use by energy consumers. CANADA In Canada, the provinces have legislative authority over the supply of energy. In the past, die majority of the electrical supply within the Canadian provinces was provided by large Crown corporations such as Ontario Hydro and Hydro-Quebec or smaller, investor owned utilities. These large utilities have been primarily responsible for the generation, transmission and distribution of electricity. In the mid-1980's, however, the rapid growth of projected energy demand, projections of dramatic increases in energy rates and advances in new generation technology led provincial governments to develop policies to encourage independent power generation. These policies were meant to encourage larger utilities to purchase power from independent power producers pursuant to long term power purchase agreements which would supply power to the provincial power grid in parallel to the utilities' own generation. In the late 1980's and early 1990's, British Columbia, Alberta, Ontario, Quebec, Nova Scotia and Newfoundland established programs to actively seek independently produced power. By the late 1990's, many of the large utilities started the process of restructuring the energy market. To date, British Columbia, Alberta, and Ontario have made progress on restructuring and introducing competition into the energy market. ALBERTA Electrical power generators in Alberta are regulated by the Electric Utilities Act (the "EU ACT"). The EU Act permits the development of a competitive marketplace for electricity in Alberta. The EU Act also created the Alberta Power Pool through which all electrical power must be traded in Alberta. -89- The EU Act was amended to separate generation, transmission and distribution of electrical power in Alberta for regulatory purposes. The amendments to the EU Act and corresponding regulations in 2000 created the Alberta Balancing Pool. The amended legislation provides that the relevant utility is to purchase power at the prices set out in the power purchase agreement entered into pursuant to the Small Power Act and sell the power into the Power Pool. All revenues associated with the sale of such power into the Power Pool are to be paid into the Balancing Pool and all costs associated with such power purchase agreements are to be paid out of the Balancing Pool. The effect of the amendments is to render a utility that is a party to such a power purchase agreement a flow through for the rights and obligations under the power purchase agreement. ONTARIO In the mid-1980's, the majority of energy produced in Ontario was the responsibility of Ontario Hydro. In 1987 however, the provincial utility and the provincial government developed policies and programs to encourage the addition of new generation by independent power generators. Over 90 of these independent generators or non-utility generators entered into long-term power purchase agreements with Ontario Hydro. These projects represent over 1,225 megawatts of energy from a variety of fuels, such as water, natural gas and wood wastes. The Energy Competition Act, 1998 (the "ENERGY ACT"), passed in 1998, restructured Ontario Hydro and separated it into a number of new, successor companies such as Ontario Power Generation Inc. and OEFC, among others. The regulatory framework for wholesale and retail competition has been developed by the Ontario government through the Ontario Energy Board (the "OEB"). While transitional issues such as pricing and metering continue to be considered by the OEB, full competition in the wholesale and retail electricity market commenced on May 1, 2002. Immediately following the opening of the Province's wholesale and retail energy market, in July, August and September of 2002, Ontario experienced dramatic increases in the wholesale price of electricity and charges for imported power. This was primarily due to a sharp increase in demand for electricity and lower than expected sources of electrical generation. In response to growing public concerns with respect to the unexpected high costs of electricity, the Government of Ontario passed the Electricity Pricing, Conservation and Supply Act, 2002 on December 9, 2002 which included a price freeze of 4.3 cents per kilowatt hour for the electricity market until May 1, 2006 for low volume and other designated consumers. On August 23, 2004, at the request of the Minister of Energy, the OEB launched a consultation process to develop a new electricity price plan that would provide stable and predictable electricity pricing, encourage conservation and ensure that the price consumers pay for electricity better reflected the price paid to generators. Under the new price plan which was announced on March 11, 2005 and came into effect on April 1, 2005, eligible consumers paid 5.0 cents per kilowatt hour for the first 750 kW-hr they used each month, and 5.8 cents per kW-hr for electricity used per month over this amount. Starting November 1, 2005, the price threshold - the amount of electricity that is charged at the lower price - changes twice a year for residential consumers. The price threshold will be 1,000 kW-hr per month in the winter (November 1st to April 30th) and 600 kW-hr per month in the summer (May 1st to October 31st). Current prices are in effect until April 30, 2006. After that, if needed, prices may change every six months based on an updated OEB forecast and any accumulated differences between the amount that consumers paid for electricity and the amount paid to generators in the previous price-setting period. The restructuring of Ontario Hydro and the Ontario energy market and the current decisions of -90- the Ontario Government has not had a material impact on the long term purchase agreement for each generating facility located in Ontario in which the Fund has an interest. OEFC now holds all rights, obligations and liabilities under such power purchase contracts. This Ontario government agency will continue to purchase the energy generated by the Ontario facilities in which the Fund has an interest pursuant to the existing contracts. The Fund has also received a licence to generate from the OEB as required by the Energy Act. MANITOBA Prior to Manitoba Hydro negotiating the power purchase agreement with St. Leon LP and St. Leon GP in respect of the wind energy project to be constructed near St. Leon, Manitoba, Manitoba did not have independent wind power generation facilities in service. In the past, Manitoba Hydro had been exclusively responsible for the production of electricity in the Province. Manitoba Hydro is a net exporter of electricity, mainly to Ontario and certain states of the United States. To date, the Province has been able to utilize its large hydro resources to satisfy internal and export requirements. In 2002, the Manitoba government developed a strategy on climate change to meet or exceed targets established under the Kyoto Protocol to the United Nations Framework Convention on Climate Change, The Manitoba strategy is based on recommendations from the Climate Change Task Force through the Climate Change Action Plan. The plan supports numerous clean energy programs within the provincial government and municipalities as well as within business, outside agencies, academic institutions and the public. The Manitoba government and Manitoba Hydro, have independently undertaken studies to determine the potential of wind power generation in Manitoba. As a result of such studies, Manitoba Hydro has advised it plans to have approximately 1000 MW of wind power capacity (inclusive of the generating capacity represented by the Facility), to be constructed, using in part, independent power producers by 2010. NEWFOUNDLAND In anticipation of an increase in electricity demand in the Province of Newfoundland, Newfoundland and Labrador Hydro began seeking generating capacity from independent power producers in 1990. In April 1990, a new policy was developed stating that Newfoundland and Labrador Hydro was prepared to relinquish its franchise rights to private developers on any hydroelectric project up to ten megawatts or greater under certain conditions. By 1992, however, the energy demand forecast for the province changed significantly and the utility indicated that it would limit the number of private generators that could sell power to the utility pursuant to long-term power purchase agreements. In April 1992, the utility issued a request for proposals from private generators for a total of 50 megawatts of new generation. In December 1993, Newfoundland and Labrador Hydro announced that it would issue power purchase agreements to four small hydroelectric projects located on the island of Newfoundland totaling 38 megawatts. The utility also announced that it would purchase electricity from these facilities commencing on October 1, 1998. In 1998, the provincial government announced a moratorium on the development of small hydroelectric projects in Newfoundland. The government announced a review of environmental issues associated with such development and a review of the need for additional generation capacity. The government cancelled two of the four facilities that were proceeding to construction. The Rattle Brook and Star Lake facilities were the two facilities completed and commissioned in 1998. -91- QUEBEC In September 1990, the Quebec government adopted a policy allowing private power producers to build, operate and manage hydroelectric generating facilities with a capacity of less than 25 megawatts, as well as the development of larger cogeneration. facilities. The program set out the terms and conditions of long term waterpower leases with the Quebec government and power purchase agreements with Hydro-Quebec which would apply to all private power producers. Between 1991 and 1993, Hydro-Quebec negotiated and signed agreements with private producers for the purchase of a total of 474 megawatts from hydroelectric generating facilities, wind powered facilities and cogeneration plants fuelled by biomass and natural gas. In July, 2001, the Regie de l'energie of Quebec approved a call for tenders for new generation by Hydro- Quebec. On November 26, 2002, the Quebec government announced that two sites were selected for development as a result of the call for proposals. At that time, the Quebec government also announced that there would be no new dams built for small hydroelectric projects. UNITED STATES The power generation industry in the United States is regulated by FERC under the PURPA legislation. FERC, pursuant to the PURPA legislation, mandates the development of policies by state utility commissions and utilities themselves that enable private producers to build power facilities. The key policy issue was the development of long term power purchase agreements with fixed, long-term power purchase rates. The long-term rates were based on projections of the utilities' Avoided Costs. Today, due to market forces and economic changes, many of these long-term agreements are priced far above current market rates. While these higher costs are burdensome to the utilities, most have recognized these costs as Stranded Costs. In 1992, FERC was empowered to open up the wholesale electric marketplace to competition. Order 888 issued by FERC established the rules associated with wholesale market competition. It is projected by FERC and others that the United States and Canada will evolve to the point where the generating component of electricity will be open to competition and no longer be subject to price regulation. On February 2, 2006, PURPA issued revised rules, Revised Regulations Governing Small Power Production and Cogeneration Facilities, Order No. 671, 114 FERC 61,102 (2006). Further regulations were also issued to clarify the regulations and will become effective on April 17, 2006. Currently the Fund, as well as many industry stakeholders, is evaluating the affect of the revisions to the industry. Based on an initial review of the revised rules, the key regulations that could impact the Fund are: (a)Any type of Qualifying Facility that exists but has never filed a self-certification (or obtained an order certifying it as a Qualifying Facility) must file a self-certification (or petition for an order) within 60 days of Order No. 671. This filing requirement was added to Section 292.207 and now forms part of the general requirements that must be met in order to be eligible to be classified as a Qualifying Facility. (b)Any cogeneration Qualifying Facility, any small power production Qualifying Facility less than 30 megawatts, and any geothermal small power production Qualifying Facility, is now subject to rate regulation under Section 205 and 206 of the Federal Power Act. However, sales of energy or capacity made by Qualifying Facilities 20 megawatts or smaller, or made pursuant to a contract executed on or before March 4, 2006, or made pursuant to a state regulatory authority's implementation of PURPA are exempt from scrutiny under sections 205 and 206. If this exception does not apply, then these Qualifying Facilities must make a rate filing under section 205 of the Federal Power Act in order to be eligible to sell -92- electricity. Rate filings were required to be made on or before the effective date of Order 671, which was March 4, 2006. CALIFORNIA The California Legislature passed Assembly Bill 1890 ("AB 1890") in 1996 to restructure the electricity industry. The State restructuring law dramatically changed the market system that was in place for more than eighty years. The intent of the restructuring was to ensure a transition to a more competitive electricity market by creating a new market that provided competitive low-cost and reliable electric service. While municipal utilities were not required to participate in the restructured market, customers of investor-owned electric utilities were free to choose their electricity provider. The market was controlled by the Power Exchange, which was to provide market services and control, and the Independent System Operator, which was given control over the transmission grid. The restructured electricity industry took form in early 1998 and the new market appeared to be off to a good start. Initially, as expected, electricity prices tracked closely the marginal cost of power production. Ultimately, however, many implementation problems developed, which eventually elevated to an "energy crisis" in 2000. Problems that began to appear were extremely high costs of electricity, decreased reliability, very high profits by generators and large debts incurred by utilities. Customers of the investor-owned utilities had their rates frozen as part of the overall legislative design and did not see the high wholesale costs reflected in their utility bills. Because of the rate freeze, utilities could not pass these expenses on to their customers, leaving utilities, such as Pacific Gas and Electric Company, with negative balances in their revenue accounts. Pacific Gas and Electric Company ultimately declared bankruptcy on April 6, 2001. The California Legislature addressed the crisis by implementing a number of changes to restructure the electricity market. A key component of the changes was to ensure that there was and is an adequate supply of electricity to meet market demands. In September 2002, Pacific Gas and Electric Company filed a Plan of Reorganization which the company stated would allow it to emerge from Chapter 11 protection. On June 19, 2003, federal bankruptcy court announced the settlement agreement between PG&E and the California Public Utility Commission's staff. In December 2003, the California Public Utility Commission approved the settlement agreement and the bankruptcy court confirmed the Plan of Reorganization. Connecticut Connecticut Light and Power Company is part of the North East Utilities System which is located in the New England Power Pool ("NEPOOL"). ISO New England Inc. was established as a not-for-profit, private corporation on July 1, 1997 following its approval by the FERC. The organization immediately assumed responsibility for managing the New England region's electric bulk power generation and transmission systems and administering the region's open access transmission tariff. Located in Holyoke, Massachusetts, ISO New England Inc. was formed by transferring staff and equipment from the NEPOOL. Since May 1, 1999, ISO New England Inc. has also administered the wholesale electricity marketplace for the region. Six electricity products are bought and sold by market participants on an Internet-based market system. NEPOOL was formed in 1971 and is a voluntary association of electric utilities in New England who established a single regional network to direct the operations of the major generating and transmission (bulk power system) facilities in the region. NEPOOL built a state-of-the-art Control Center -93- to centrally dispatch the bulk power system using the most economic generating and transmission equipment available at any given time to match the electric load of the region. This approach netted millions of dollars in savings for NEPOOL utilities and their customers, while increasing the overall reliability of the bulk power system. NEPOOL will continue to exist as the entity representing not only traditional electric utilities but also companies that will participate in the emerging competitive wholesale electricity marketplace. ISO New England Inc. has a services contract with NEPOOL to operate the bulk power system and to administer the wholesale marketplace. MINNESOTA In 1974, the Minnesota legislature created the outlines of the current regulatory structure in Minnesota. Eight utilities were granted exclusive service territories and were given a monopoly on the provision of electricity within those territories. No electricity may be sold to customers within a utility's territory other than by that utility, except in certain limited circumstances. In exchange for this monopoly, each utility assumed the obligation to serve all customers within its service territory and to provide quality service at just and reasonable rates. The utility is permitted to recover reasonable and prudent expenses associated with its provision of service plus a reasonable return on its investments made to serve customers. Some consider this to be a "regulatory compact." The underlying rationale for this compact has both a legal and an economic component. Regulators and the Minnesota legislature have taken several steps in recent years to introduce competitive aspects into the Minnesota regulatory structure. These include: (1) encouraging non-utility generation, (2) authorizing utilities to offer competitive rates, and (3) instituting competitive bidding for new generation capacity. In 1990, the legislature enacted legislation allowing some utilities in certain cases to lower their rates for large industrial customers. The statute, passed in order to allow utilities to respond to potential competition (and thus keep large customers from leaving the utility's service grid), provides that within its own assigned service territory, the utility, at its discretion and using its best judgment at the time, may offer a competitive rate to a customer subject to effective competition. In 1993, the legislature authorized the Minnesota Public Utility Commission to allow competitive bidding for generation resources identified as needed by a utility's integrated resource plan. Each utility is required to develop a set of resource options that a utility could use to meet the service needs of its customers over a forecast period, including an explanation of the supply and demand circumstances under which, and the extent to which, each resource option would be used to meet those service needs. During the Minnesota legislature's 2001 session, the Minnesota Renewable Energy Objectives was enacted as a statute. The objectives require each electric utility to "make a good faith effort to generate or procure electricity generated by an eligible energy technology" so that: (1) commencing in 2005, at least one percent of the electric utility's total retail electric sales is generated by eligible energy technologies; (2) the amount provided under clause (1) is increased by one percent of the utility's total retail electric sales each year until 2015; and (3) ten percent of the electric energy provided to retail customers in Minnesota is generated by eligible energy technologies." NEW HAMPSHIRE New Hampshire has one large, investor-owned utility, Public Service Company of New Hampshire, which is a subsidiary of Northeast Utilities, as well as a number of smaller regional utilities. -94- With the passing of PURPA in 1978, the New Hampshire legislature passed the Limited Electrical Energy Producers Act which directed the NHPUC to encourage the State's utilities to purchase independently produced power from a variety of sources. The State legislature also granted the NHPUC authority to set long term rates for renewable energy sources and beginning in 1984, the PSNH issued power purchase agreements with long term fixed power purchase rates that helped stimulate the development of small hydroelectric generating facilities. While these rates were based on PSNH's own projected energy costs at that time, the contracted rates are now well above today's market rates for electricity. The NHPUC also issued rate orders to utilities such as PSNH to purchase electricity from certain power producers at stipulated power purchase rates. In March 2002, PSNH approached all the existing holders of power purchase agreements and rate orders with an offer to buy down or buy out the existing contracts that contained over market power purchase rates. By the end of the year, PSNH either bought out or bought down twelve contracts or rate orders. NEW JERSEY In the late 197O's, with an energy crisis emerging, the federal government enacted the Public Utility Regulatory Policies Act. This government legislation was intended to encourage private power producers to develop generating facilities using renewable energy (for example, small hydro). Under the new PURPA regulation, the Federal Energy Regulatory Commission was allowed to implement its own directives to ensure utilities purchase energy under long term contracts produced by a Qualifying Facility. In 1981 and 1983, the New Jersey Board of Public Utilities ordered the PURPA be executed, which in turn authorized State utilities and Qualifying Facilities to negotiate long term contracts. In 1992, the federal Energy Policy Act was passed, which brought competition to the wholesale electric marketplace. This legislation bestowed upon FERC the authorization to ensure fair competition, more specifically open access, non-discriminatory transmission and access to information in the wholesale marketplace. In the early 1990s, as a result of the new bulk energy market, the New Jersey Board of Public Utilities challenged in court the validity of the long-term contracts with independent power producers. The intention was to necessitate the buy-out of uneconomical independent power producer contracts. However, in 1995, the legal dispute was overruled by the United States Court of Appeals for the Third Circuit. The basis of the decision was that the New Jersey Board of Public Utilities disobeyed the FERC and PURPA regulations. Further changes to the New Jersey energy marketplace have taken place over the last few years. In February 1999, the State of New Jersey enacted the Electric Discount and Energy Competition Act. This regulation encourages competition in the energy markets, including electricity generation, in New Jersey. On August 1, 1999, New Jersey finally deregulated the electric and gas utility business throughout the State. NEW YORK STATE Following the implementation of PURPA in 1978, New York State aggressively pursued the development of independent power production. There are currently over 300 independent power facilities now in operation in New York State and independent power producers have added more than 6,000 megawatts of new electric generating capacity. -95- TENNESSEE While some states have advanced toward deregulation of electricity, Tennessee's unique relationship with the Tennessee Valley Authority ("TVA") prevents most similar actions. TVA's status as a federal utility means that Congress must act before substantial further changes in the provision of electric power can occur in Tennessee. While the electric utility industry in Tennessee developed almost exclusively around the Tennessee Valley Authority, the electric industry outside of Tennessee developed a vertically integrated structure in which each utility owned its own generation, transmission and distribution facilities. In anticipation of increased customer demands, these electric utilities invested in additional generating capacity. In April 1996, FERC issued Order 888 requiring all public distribution utilities that own, operate or control interstate transmission services to file tariffs offering to others the same services that they provide to themselves. It also sets conditions under which a utility may seek recovery of stranded costs. Although Order 888 does not require corporate unbundling or divestiture, it does require the structural separation of utilities' transmission services from their power marketing functions. Because TVA is not currently under FERC jurisdiction, it is not required to adhere to FERC mandates, such as Order 888, except on a voluntary basis. While Tennessee has continually monitored the issue of electricity deregulation, it was one of the last states to officially consider it. Passage of Public Chapter 531 in 1997 marked the first official step toward electricity deregulation in Tennessee. This legislation established a Special Joint Committee to study the issues of electricity deregulation and its impact on Tennessee. VERMONT Following the implementation of PURPA in 1978, the State of Vermont agreed to encourage the development of independent power production. The electrical distribution system of the State is comprised of approximately 26 small, local utilities and for efficiency it was determined that one purchaser, die Vermont Electrical Exchange, Inc., should act as purchasing agent for all State utilities. Consequently, Vermont Electrical Exchange, Inc. has entered into a number of contracts with private producers under which it purchases power from these independent power producers and, in turn, delivers such power to member utilities. COMPETITION AND GREEN POWER PRICING Unlike electricity generated by fossil fuels such as natural gas and coal which are subject to potentially dramatic and unexpected price swings due to disruptions in supply or abnormal changes in demand, the supply of hydroelectric power is not subject to commodity fuel price volatility or risk. In addition, the generation of hydroelectric power does not involve significant ongoing capital and operating costs to ensure strict compliance with environmental regulations, which is a significant advantage over power generated by burning waste or utilizing landfill gases. Deregulation has increased demand for privately generated power from a variety of sources including fossil fuels, waste, wind and water. Taking into account capital costs, wind power is generally more expensive than traditional forms of generated power. Fossil fuels are harmful to the environment; and waste burning power generation requires producers to abide by stringent and costly environmental regulations. With deregulation and opening of competition in the electricity marketplace, there will be an increase in the opportunity for the energy customer to choose the type of generation producing the -96- electricity. Over 30 utilities in the United States now offer their customers Green Power at a premium price. Green Power is electricity generated from renewable energy sources that do not contribute to greenhouse gas emissions. Green Power includes technologies such as small hydroelectric (generally defined as facilities of less than 20 megawatts in capacity), bioenergy, landfill gas, wind and photovoltaic. The US Department of Energy has suggested that in a competitive marketplace, utilities and energy marketers will utilize Green Power pricing to strengthen their image with their customers and build customer loyalty. Further, the Department has found that most utility customers want their utilities to pursue environmentally benign options for generating electricity and some customers are willing to pay extra to receive power generated by renewable resources. The Department believes that as deregulation and open competition evolve, the Green Power approach will help offset the relatively higher costs of renewable power compared to less costly gas-fired generation. In April 1997, Natural Resources Canada announced that, as part of the federal Green Power Procurement program, the federal government entered into an agreement to purchase up to 13,100 megawatt hours per year of Green Power from a utility to supply electricity to buildings owned by Natural Resources Canada and Environment Canada. Further, at that time, the Minister of the Environment announced that Environment Canada would be greening up to 20 per cent of its nation-wide electrical consumption before 2010 to assist the growth of the Green Power sector while reducing the greenhouse gas emissions caused by the Department's use of electricity. Recently, international environmental agreements such as the Kyoto Protocol on Climate Change have set targets for the reduction of greenhouse gas emissions. The Canadian government has announced its intention to implement the Kyoto Protocol with some changes. The United States, at both the federal and state government levels, has announced various programs and targets to reduce greenhouse gas emissions. Though programs and policies are evolving at all government levels, the trading of greenhouse gas credits created by renewable energy projects is seen as part of the eventual solution. WATER SERVICES INDUSTRY THE GLOBAL WATER SERVICES MARKET The global market for water supply and treatment equipment and services has been growing rapidly over the last decade and currently constitutes over a third of the global market for environmental products and services. The trend to market pricing for water services, combined with the growing privatization of water and wastewater utilities, has generated an opportunity for private capital to participate in water services markets. The opportunity is enhanced by increasingly stringent enforcement of environmental regulations, worldwide consolidation of the water industry and the proliferation of e-business. The United States, Western Europe and Japan represent over 80 percent of the total market for water services and equipment. These markets are generally mature with an average growth of approximately 3 to 4 percent consistent with the growth in population. The largest participants in serving the global water and wastewater industry are based in the United States, France, Britain, Japan and Germany. UNITED STATES WATER SERVICES INDUSTRY The ownership of water assets and the provision of water and wastewater services around the world, including the United States, remain primarily concentrated in the public sector, typically at the municipal or community level. Rates charged by such utilities are determined in the discretion of the municipality on the premise that such services are provided at cost. -97- Notwithstanding the foregoing, approximately 55 million Americans living in smaller communities are served by approximately 60,000 privately owned and operated water utilities and 5,500 privately owned wastewater reclamation and treatment utilities. Rates charged by these utilities are determined by state or county regulators; rates are established to provide sufficient revenues to generate after-tax equity returns of approximately 10 to 12%. In the continental United States, water supplies and resources for approximately one-third of the landmass are considered endangered. The southwest United States is particularly susceptible to the effects of groundwater and surface-water withdrawals, precipitation lost through evaporation, lack of industrial water recycling and extremes of temperatures. The connection between the water delivery and wastewater collection and reclamation industries is becoming closer with the advent of stronger re-use regulations and continuing evolution in water rights. The industry and regulators appear now to agree that high quality reclaimed water from wastewater treatment and potable groundwater credits should be considered interchangeable. In many jurisdictions in the United States, reclaimed water is being recharged by wastewater treatment utilities into the ground aquifers and then subsequently withdrawn and re-introduced into the potable water systems by water delivery utilities. The wastewater treatment utilities are awarded credits for such recharge and the water delivery utilities utilize such credits in respect of pumping and delivering water to customers. The global market for water and wastewater services and equipment is large and growing. There are a large number of private water and wastewater companies in the United States and a large concentration of these utilities is located in the high growth areas of the arid southern States. It is estimated that investment of between $25 US billion and $40 billion will be required in the industry over the next 20 years in capital improvements and new infrastructure. Under the regulations governing private investor owned utilities, rates will be established to ensure investors of such capital earn a market return. Generally, private and investor owned water and sewer providers in the United States operate as geographic monopolies in the areas in which they serve. A water or sewer company is provided an area defined by, and often referred to as, a Certificate of Convenience and Necessity. A Certificate of Convenience and Necessity is typically granted by a state agency, which also serves as a regulating entity for the water or sewer service provider. Such agencies are charged with ensuring that water and sewer services are provided at reasonable rates to the company's customers. The agency must balance the interests of the rate payers as well as companies and their shareholders. Rates are approved by the agency to provide the water or sewer company the opportunity, but not the guarantee, to earn a reasonable return on its investment after recovering its prudently incurred expenses. ARIZONA While the majority of water and sewer customers are served by large municipalities, there are numerous private and investor-owned companies providing service. The Arizona Corporation Commission is the regulatory authority with jurisdiction over private water and sewer companies as well as investor-owned utilities. Municipal water and sewer systems are regulated by the city or town council and do not fall under the jurisdiction of the Arizona Corporation Commission. Similarly, water improvement districts are governed by the county in which they operate. Environmental regulation and compliance is provided by the Arizona Department of Environmental Quality and various County agencies. -98- ILLINOIS The Illinois Commerce Commission currently regulates 33 water, 5 sewer, and 14 combination water and sewer investor-owned utilities serving a population of nearly 1.15 million people. Environmental regulatory authority is provided by the Illinois Environmental Protection Agency. MISSOURI The Missouri Public Service Commission is the state agency responsible for the regulation of private and investor-owned utilities. The Missouri Public Service Commission regulates approximately 126 water and sewer companies. Environmental regulation is provided by the Missouri Department of Natural Resources and certain County authorities. TEXAS The Texas Commission on Environmental Quality is the agency that provides regulatory oversight of private and investor-owned water and sewer utilities. Texas Commission on Environmental Quality also has the responsibility of implementing, monitoring, and enforcing environmental regulations, such as those stemming from the Clean Water Act and the Safe Drinking Water Act, for all water and sewer service providers, including those owned and operated by municipalities. OTHER CONSIDERATIONS COMPETITION The Fund competes for infrastructure project acquisitions with individuals, corporations and institutions (both Canadian and foreign) which are seeking or may seek infrastructure project investments similar to those desired by the Fund. Availability of investment funds and an increase in interest in infrastructure project investments may increase competition for infrastructure investments, thereby increasing purchase prices. Many of these investors have greater financial resources than those of the Fund or operate according to more flexible conditions. The Fund will access public markets to finance infrastructure project acquisitions if funds are not immediately available. In addition, the Fund believes that the Manager in its role as administrator and manager provides the Fund with a competitive advantage with its experience in identifying strategic investment opportunities. Significant deregulation and opening of competition is occurring in the electricity marketplace. The Fund is in a strong competitive position since, for new generation, small hydroelectric is the lowest cost producer, after industrial co-generation, in relation to total costs and is the lowest cost producer with respect to variable production costs. Reference is made to "The Independent Power Generation Industry - Competition and Green Power Pricing". ENVIRONMENTAL MATTERS The Facilities encompass operations which require adherence to environmental standards imposed by regulatory bodies through licences, permits, policies and legislation. Failure to operate the Facilities in strict compliance with these regulatory standards may expose the Facilities to claims, cleanup costs and loss of operating licences and permits. The Manager has an environmental management program including environmental policies and -99- procedures that involve long term environmental monitoring programs, reporting, government liaison and the development and implementation of emergency action plans as related to environmental matters. Environmental protection requirements did not have a significant financial or operational effect on the Fund's capital expenditures, earnings and competitive position for the twelve months ended December 31, 2005. Further, such requirements are not expected to have a significant impact in future years, although, management of the Fund expects that more stringent environmental standards will continue to be implemented by various governmental agencies. Following the release of hydraulic fluid at the Franklin Facility in 2005 (See "Other Developments in Fiscal 2005" and "The Developments - New England Developments - Franklin Facility"), the Fund took a number of steps to minimize the potential for such releases in the future, including extensive repairs to the facility turbine, increased training for local plant personnel at all hydroelectric facilities, and the strengthening of corporate level oversight of environmental compliance at all of its operations. EMPLOYEES Algonquin Canada currently has 28 employees who are involved in the operation of the hydroelectric facilities and an additional 49 employees through its subsidiaries are involved in the operations of the cogeneration and landfill gas facilities. Algonquin Power Trust (including its subsidiaries) currently has 26 employees who are involved in the management of the Fund and a further 59 employees involved in the operations of the EFW Facility. In addition, the Manager, Power Systems and AWS currently have approximately 150 employees. Labour relations have been stable to date and there has not been any disruption in operations as a result of labour disputes with employees. With the exception of 45 employees at the EFW Facility, these employees are non-unionized. FOREIGN OPERATIONS For 2005, 72.9% of the gross revenue of the Fund was generated in the United States. As at March 31, 2006, the Fund has interests in 58 facilities located in the United States, including 15 water distribution and wastewater treatment facilities. Currency fluctuations may affect the cash flow which the Fund will realize from its operations, as certain of the Fund Businesses sell electricity in the United States and receive proceeds from such sales in US dollars. Such Fund Businesses also incur costs in US dollars. INTELLECTUAL PROPERTY The "Algonquin" name and trademark and related marks and designs are licenced to the Fund by Algonquin Power under a non-exclusive, royalty-free trademark licence agreement dated December 23, 1997 between Algonquin Power and the Fund. Subject to the terms of the licence agreement, this licence will remain in effect for as long as the Management Agreement is in effect. The Fund, by using the "Algonquin" name, has the benefit of the goodwill and recognition associated with Algonquin Power and its affiliates' use of the "Algonquin" name in the energy sector for the past nine years. SEASONALITY Based on the type of power purchase agreements in place at all of the facilities in which the Fund has an interest, the revenue generated by the facilities is proportional to the amount of electrical energy generated. In addition, the amount of energy generated at the hydroelectric facilities is dependent upon -100- available water flows. Accordingly, the Fund's revenues are affected by low and high water flow caused by seasonal rains and melts, with the result that revenues are higher in the spring and fall and are lower in the summer and winter. Engineering studies have been undertaken to assess the amount of energy which can be expected to be generated from each facility on an average annual basis. Furthermore, the majority of the facilities have significant operating histories with which to compare the theoretical estimates in the engineering studies. Due to geographic diversity of the facilities, the variability of total revenues is minimized. CUSTOMERS The Fund Businesses derive their revenues from the sale of electricity to large utilities. For the twelve months ended December 31, 2005, the Fund Businesses' revenues were derived as follows: Connecticut Light and Power - approximately 19%; OEFC - approximately 6%; Hydro Quebec - approximately 10%; Pacific Gas and Electric 8%; regulated water distribution and reclamation facilities-16%; and others - approximately 41%. ECONOMIC DEPENDENCE The largest customer on a percentage basis is Connecticut Light and Power Company which totalled 19% in revenues in the year ended December 31, 2005; however, this customer's contribution to Distributable Cash was a significantly lower percentage of total Distributable Cash (12%) for the year ended December 31, 2005. Otherwise, the Fund does not believe it is substantially dependant on any single contractual agreement or set of related agreements either for the sale of a major part of its products and services or for the purchase of a major part of its requirements for goods, services or raw materials or any franchise or licence or other agreement to use a patent formula, trade secret, process or trade-name upon which its business depends. SOCIAL OR ENVIRONMENTAL POLICIES The Fund has safety and environmental compliance policies in place. These policies have been communicated with staff, and have been incorporated into the Fund's Safety Mission Statement and Employee manual. The Fund's Safety Mission Statement is to; 1. uphold Public Safety at all facilities under Algonquin management. 2. uphold Employee Safety in the work-place. 3. uphold Environmental Compliance. 4. uphold Regulatory Compliance. 5. maintain Employee Job Satisfaction. 6. foster Open Communication To Achieve Company Guidelines. 7. ensure Long Term Integrity of Client's Assets. 8. maximize Client Revenue on facilities under Algonquin management. The Fund has an Environmental, Health and Safety Group that reports independently to the Executive Director - Environmental Compliance and Safety (this position reports to the Trustees). This -101- group is responsible for developing environmental and safety policies, developing and delivering environmental and safety training, conducting internal audits of environmental and safety performance, and arranging for third party environmental and safety audits. SELECTED FINANCIAL INFORMATION The following sets out certain selected financial information for the Fund: THREE THREE MONTHS THREE MONTHS THREE MONTHS MONTHS ENDED ENDED YEAR ENDED ENDED MARCH ENDED JUNE SEPTEMBER 30, DECEMBER 31, DECEMBER 31, 2003 30, 2003 2003 2003 31, 2003 ------------ ----------- ------------- ------------ ---------- (millions of dollars, except for per Trust Unit amounts) Operating Revenue 27.6 42.2 38.1 39.7 147.6 Total Expenses 18.3 22.2 31.4 29.1 101.1 Interest Expense 2.1 3.1 3.2 3.2 11.6 Income Taxes 1.9 (3.0) (5.0) 1.7 (4.4) Net Earnings/(Loss) 6.5 21.5 10.0 6.4 44.5 Net Earnings/(Loss) 0.10 0.32 0.15 0.09 0.66 per Trust Unit Total Assets 828.7 829.0 822,157 820.3 820.3 Total Long Term Debt 185.7 178.6 177,784 185.4 185.4 Distributions per Trust 0.23 0.23 0.23 0.23 0.92 Unit THREE THREE MONTHS THREE MONTHS THREE MONTHS MONTHS ENDED ENDED YEAR ENDED ENDED MARCH ENDED JUNE SEPTEMBER 30, DECEMBER 31, DECEMBER 31, 2004 30, 2004 2004 2004 31, 2004 ------------ ----------- ------------- ------------ ---------- (millions of dollars, except for per Trust Unit amounts) Operating Revenue 37.2 41.9 40.7 40.7 160.5 Total Expenses 33.3 35.6 26.7 35.6 131.2 Interest Expense 2.7 2.7 3.3 3.7 12.4 Income Taxes (0.6) 0.5 0.6 1.8 2.3 Net Eamings/(Loss) 3.3 8.1 11.5 (0.1) 22.8 Net Earnings/(Loss) 0.05 0.12 0.16 0.00 0.33 per Trust Unit Total Assets 812.5 809.0 834.2 824.8 824.8 Total Long Term Debt 186.4 189.7 214.6 226.2 226.2 Distributions per Trust 0.23 0.23 0.23 0.23 0.92 Unit -102- THREE THREE MONTHS THREE MONTHS THREE MONTHS MONTHS ENDED ENDED YEAR ENDED ENDED MARCH ENDED JUNE SEPTEMBER 30, DECEMBER 31, DECEMBER 31, 2005 30, 2005 2005 2005 31, 2005 ------------ ---------- ------------- ------------ ---------- (millions of dollars, except for per Trust Unit amounts) Operating Revenue 40.6 45.0 42.8 50.9 179.3 Total Expenses 35.5 36.6 33.1 41.2 146.4 Interest Expense 3.9 4.0 4.1 4.4 16.4 Income Taxes 1.1 2.4 (1.2) 0.3 2.6 Net Earnings/(Loss) 1.8 1.6 9.5 8.9 21.8 Net Earnings/(Loss) 0.03 0.02 0.14 0.12 0.31 per Trust Unit Total Assets 813.1 822.1 838.2 823.8 823.8 Total Long Term Debt 235.6 261.8 286.8 271.5 271.5 Distributions per Trust 0.23 0.23 0.23 0.23 0.92 Unit DISTRIBUTION POLICY The following outlines the distribution policy of the Fund as contained in the Declaration of Trust, including any restrictions on the ability to make distributions. The amount of Distributable Cash to be distributed annually per Trust Unit will be equal to a pro rata share of all cash amounts which are received by the Fund including, without limitation, interest, dividends, royalties, lease payments, distributions from trusts, proceeds from the disposition of securities including any proceeds of redemption of shares or trust units, return of capital and repayment of indebtedness and all cash amounts received by the Fund in respect of any prior year to the extent not previously distributed (excluding all amounts required to satisfy the redemption of Units and which have become payable in cash by the Fund in respect of the year, and the amount (if any) by which Net Income for the year is negative), less any amount or amounts which the Trustees may reasonably consider to be necessary to provide for the payment of any costs, expenses or obligations which have been incurred in the course of the activities and operations of the Fund (including, for greater certainty, administrative expenses of the Fund and amounts required for the business and operation of the Fund and, in particular, amounts required to pay the deferred portion of the purchase price for any assets acquired by the Fund, directly or indirectly) and to provide for the payment of any tax liability of the Fund or its subsidiary entities. Where the Trustees determine that the Fund does not have available cash in an amount sufficient to make payment of the full amount of any distribution which has been declared to be payable on the due date for such payment, the payment may, at the option of the Trustees, include the pro rata issuance of additional Units, or fractions of Units, if necessary, having a value equal to the difference between the amount of such distribution and the amount of cash which has been determined by the Trustees to be available for the payment of such distribution. Such additional Trust Units will be issued pursuant to exemptions under applicable securities laws, discretionary exemptions granted by applicable securities regulatory authorities or a prospectus or similar filing. In addition, the Trustees may declare to be payable and make distributions to the Unitholders, from time to time, out of Net Income of the Fund, Net Realized Capital Gains of the Fund, the capital of the Fund or otherwise, in any year, in such amount or amounts, and on such dates as the Trustees may determine. Having regard to the present intention of the Trustees to allocate, distribute and make payable to Unitholders all of the Net Income of the Fund, Net Realized Capital Gains of the Fund and any other applicable amounts for each taxation year so that the -103- Fund will not have any liability for tax under Part I of the Income Tax Act in any such year, the amount, if any, by which the Net Income of the Fund and Net Realized Capital Gains of the Fund for each taxation year exceed the aggregate of: (i) such part of the taxable capital gains of the Fund for the year required to be retained by the Fund to maximize its capital gains refund for such year, but only if the Trustees have passed a resolution that this is to apply to the Fund for that year by the end of the year; and (ii) any amount that became payable by the Fund during the year to Unitholders on the Trust Units (other than amounts that became payable to Unitholders on the redemption of their Trust Units), shall without any further actions on the part of the Trustees, be due and payable at the end of the year to Unitholders of record as at that time. The Fund includes in its monthly distributions cash dividends, distributions or returns of capital, if any, received from Fund Businesses. Monthly distributions are due and payable to Unitholders of record on the last day of each month and are expected to be paid on or before 45 days thereafter without interest or penalty. Revenues from the hydroelectric facilities operated by the Fund Businesses are higher in the spring due to the spring run-off and in the fall due to higher levels of rainfall and, as a result, distributions of Distributable Cash are typically greater during the months ending in the spring and the fall. In an effort to assist in the equalization of distributions throughout the year, funds have been set aside to be used at the discretion of the Trustees to help compensate for seasonal fluctuations in waterflows. The Trustees declared and made monthly distributions totaling $64.1 million during 2005. Distributions of $62.4 million and $63.4 million were made in 2003 and 2004 respectively. The amount of distributions is dependent on a number of factors. See "Risk Factors" below. The Fund does not currently anticipate any change to its distribution policy. MANAGEMENT'S DISCUSSION AND ANALYSIS Management's discussion and analysis of financial condition and results of operations of the Fund as at and for the periods ended December 31, 2005 and 2004, as set forth on pages 12 - 33 of the Fund's Annual Report for fiscal 2005, is hereby incorporated by reference in its entirety. The Fund's Annual Report for fiscal 2005 is accessible at http://www.sedar.com. CANADIAN FEDERAL INCOME TAX CONSIDERATIONS In the opinion of Blake, Cassels & Graydon LLP, counsel to the Fund, the following summary describes the principal Canadian federal income tax considerations pursuant to the Tax Act and the regulations thereunder generally applicable to a Unitholder who acquires Trust Units and who, for purposes of the Tax Act, is resident in Canada, holds the Trust Units as capital property and deals at arm's length with the Fund, Algonquin Power and the Manager and is not affiliated with the Fund, Algonquin Power or the Manager. Generally, Trust Units will be considered to be capital property to a Unitholder provided the Unitholder does not hold the Trust Units in the course of carrying on a business and has not acquired them in one or more transactions considered to be an adventure in the nature of trade. Certain Unitholders who might not otherwise be considered to hold their Trust Units as capital property may, in certain circumstances, be entitled to have them treated as capital property by making the election permitted by subsection 39(4) of the Tax Act. This summary is not applicable to a Unitholder that is a "financial institution" for purposes of the mark-to-market rules, to a Unitholder an interest in which is a "tax shelter investment" or to any such Unitholder that is a "specified financial institution", all within the meaning of the Tax Act. Any such Unitholder should consult its own tax advisor with respect to an investment in Trust Units. This summary is based upon the provisions of the Tax Act and the Income Tax Regulations (the "REGULATIONS") in force as of the date hereof, all specific proposals to amend the Tax Act or the Regulations that have been publicly announced by the Minister of Finance prior to the date hereof (the -104- "PROPOSED AMENDMENTS"), certificates of the Fund and Algonquin Power as to certain factual matters and Counsel's understanding of the administrative policies and assessing practices of the Canada Revenue Agency ("CRA") made publicly available prior to the date hereof. This summary is also based on the assumption that the Fund will at all times comply with the Declaration of Trust. On October 31, 2003, The Department of Finance released, for public consultation, draft proposed amendments (the "OCTOBER 31 PROPOSALS") to the Tax Act that would require, for taxation years commencing after 2004, that there be a reasonable expectation of profit from a business or property for a tax payer to realize a loss from such business or property, and that makes it clear that a profit for this purpose does not include capital gains. This summary does not take into account the effect of the October 31 Proposals on a Unitholder or the Fund. On February 23, 2005, the Minister of Finance announced that the Department of Finance has developed an alternative to the October 31 Proposals which will be released for comment in the near future. This summary is not exhaustive of all possible Canadian federal income tax consequences and, except for the Proposed Amendments, does not take into account or anticipate any changes in the law or in the administrative or assessing policies of CRA, whether by legislative, governmental or judicial action, nor does it take into account provincial, territorial or foreign tax considerations, which may differ significantly from those discussed herein. No assurance can be given that the Proposed Amendments will be enacted as currently proposed or at all. This summary is of a general nature only and is not intended to be legal or tax advice to any prospective purchaser of Trust Units or any Unitholder. Consequently, prospective purchasers and Unitholders should consult their own tax advisors with respect to their particular circumstances. STATUS OF THE FUND This summary assumes that the Fund qualifies and will continue to qualify as a "mutual fund trust" as defined in the Tax Act. In order to so qualify, Trust Units representing at least 95% of the fair market value of all Trust Units of the Fund must have conditions attached thereto that include conditions requiring the Fund to accept, at the demand of the holder thereof and at prices determined and payable in accordance with the conditions, the surrender of the Trust Units, or fractions or parts thereof, that are fully paid. In addition, there must at all times be at least 150 Unitholders of the Fund each of whom owns not less than one "block" of Trust Units having a fair market value of not less than $500. A "block" of Trust Units means 100 Trust Units if the fair market value of one Trust Unit is less than $25. Further, the undertaking of the Fund must be restricted to the investing of its funds in property (other than real property or an interest in real property), the acquiring, holding, maintaining, improving, leasing or managing of any real property (or an interest in real property) that is capital property of the Fund, or a combination of these activities. The Fund will be deemed not to be a mutual fund trust if it can reasonably be considered that the Fund, having regard to all the circumstances, was established or is maintained primarily for the benefit of non-resident persons. On September 16, 2004, the Minister of Finance released certain proposals that a trust such as the Fund, would lose its status as a mutual fund trust under the Tax Act if, at any time, the aggregate fair market value of all of its issued and outstanding units held by one or more non-resident persons and/or by partnerships which are not Canadian partnerships under the Tax Act, is more than 50% of the aggregate fair market value of all issued and outstanding units of the trust, unless no more than 10% (based on fair market value) of the trust's property at any time is taxable Canadian property and certain other types of specified property. These proposals did not provide any means of rectifying the loss of mutual fund trust status. On December 6, 2004, the Minister of Finance suspended implementation of these proposals pending further consultation with the private sector. -105- While Counsel cannot provide an opinion on matters of fact such as the foregoing, Counsel understands that the Fund intends, and this summary assumes, that at all relevant times these and other applicable requirements will be satisfied and that the Fund is not established nor will it be maintained primarily for the benefit of non-resident persons and that more than 50% of the Units will not at any time be owned by non-residents of Canada or partnerships (other than partnerships all of the partners of which are residents of Canada (for purposes of the Tax Act)), so that the Fund qualifies and will continue to qualify as a mutual fund trust at all relevant times. In the event the Fund does not qualify as a mutual fund trust, the income tax considerations would in some respects be materially different from those described below. The Fund has been registered by CRA as a registered investment for purposes of the Tax Act. TAXATION OF THE FUND The Fund is subject to taxation in each taxation year on its taxable income for the year, including net realized taxable capital gains, less the portion thereof that is paid or payable in the year to Unitholders and which is deducted by the Fund in computing its income for purposes of the Tax Act. An amount will be considered to be payable to a Unitholder in a taxation year if it is paid in the year by the Fund or the Unitholder is entitled in that year to enforce payment of the amount. The taxation year of the Fund is the calendar year. The Fund will generally be entitled to deduct its expenses incurred to earn such income provided such expenses are reasonable and otherwise deductible, and it will be entitled to claim capital cost allowance with respect to its undepreciated capital cost in any facility equipment held by the Fund, subject to the provisions of the Tax Act in that regard. The Fund will be limited to claiming as a deduction in respect of capital cost allowance relating to "leasing property" and "specified energy property", within the meaning of the Tax Act, an amount equal to the Fund's income from such property. The Fund may deduct in computing its income for a year a portion of the reasonable expenses of the issue of Trust Units paid by the Fund from the proceeds of the public offerings of its Units. Such portion of issue expenses deductible by the Fund in a taxation year is determined pursuant to the Tax Act and is generally equal to that portion of 20% of the total issue expenses that the number of days in the Fund's taxation year is of 365 days, to the extent that the issue expenses were not otherwise deductible in a preceding year. Under the Declaration of Trust, an amount equal to all of the income of the Fund for each year (determined without reference to paragraph 82(1)(b) and subsection 104(6) of the Tax Act), together with the taxable and non-taxable portion of any capital gains realized by the Fund in the year, (excluding income and capital gains which may be realized by the Fund upon a distribution in specie of the Fund Assets in connection with a redemption of a Trust Unit) net of the Fund's deductions and expenses, will be payable in the year to the holders of the Trust Units by way of cash distributions, subject to the exceptions described below. Under the Declaration of Trust, cash of the Fund may be used to finance cash redemptions of Trust Units and accordingly such cash so utilized will not be payable to holders of the Trust Units by way of cash distributions but rather may be payable in the form of additional Trust Units ("REINVESTED TRUST UNITS"). A distribution by the Fund to a Unitholder of a portion of the assets of the Fund upon a redemption of Trust Units will be treated as a disposition thereof by the Fund for proceeds equal to their fair market value (determined, in the case of an interest in the debt obligations held by the Fund, without taking into account any accrued interest) and will give rise to income (or loss) and/or a capital gain (or a capital loss) to the Fund to the extent that the fair market value of the Fund Assets so distributed (less any -106- accrued interest) exceeds (or is exceeded by) the cost amount to the Fund of the respective portion of the Fund Assets immediately prior to the distribution. In addition, the Fund will be required to include in its income any interest that had accrued on any of the Fund Notes and other accrued but unpaid income, if any, in respect of the Fund Assets so disposed of up to the date of distribution to the extent not otherwise included in its income for the year of disposition or a previous year. On a redemption of Trust Units, income and capital gains arising in the Fund attributable to an in specie distribution of Fund Assets and certain income of the Fund will be payable to the redeeming Unitholder, with the result that the taxable portion of such gains and such income should generally be taxable to the redeeming Unitholder and not the Fund. Nevertheless, the Declaration of Trust provides that cash of the Fund which is required to satisfy any tax liabilities on the part of the Fund will not be payable to the Unitholders. For purposes of the Tax Act, the Fund generally intends to deduct in computing its income such amount as will be sufficient to ensure that the Fund will not be liable for income tax under Part I of the Tax Act except to the extent that the Fund expects to receive a "capital gains refund" determined under the Tax Act based on redemptions of Trust Units during the year. Counsel has been advised by the Fund that the Fund does not expect that it will be liable for any material amount of tax under Part I of the Tax Act and that the Fund does not expect to be adversely affected by the October 31 Proposals. However, Counsel can provide no opinion in this regard. TAXATION OF THE UNITHOLDERS A Unitholder will generally be required to include in computing income for a particular taxation year the Unitholder's portion of the income of the Fund for a taxation year, including net realized taxable capital gains, that is paid or payable to the Unitholder in that particular year, notwithstanding that any such amount may be payable in Reinvested Trust Units. Provided that appropriate designations are made by the Fund, such portions of its net taxable capital gains, taxable dividends from taxable Canadian corporations and foreign source income as are paid or payable to a Unitholder will effectively retain their character and be treated as such in the hands of the Unitholder for the purposes of the Tax Act. Accordingly, such amounts will generally be taken into account in determining the Unitholder's foreign tax credits and, in the case of a Unitholder that is an individual, the Unitholder's entitlement to the dividend tax credit. Such amounts will also be taken into account in determining the Unitholder's liability, if any, for alternative minimum tax under the Tax Act. Any amount in excess of the income of the Fund that is paid or payable by the Fund to a Unitholder in a year should not generally be included in the Unitholder's income for the year. However, where such an amount is paid or becomes payable to a Unitholder, other than as proceeds of disposition or deemed disposition of Trust Units or any part thereof, the amount will generally reduce the adjusted cost base of the Trust Units held by such Unitholder, except to the extent that the amount represents the Unitholder's share of the non-taxable portion of the net realized capital gains of the Fund for the year, the taxable portion of which was designated by the Fund in respect of the Unitholder. To the extent that the adjusted cost base of a Trust Unit would otherwise be less than zero in any taxation year of a Unitholder, the negative amount will be deemed to be a capital gain realized by the Unitholder in such taxation year from the disposition of the Trust Unit and the amount of such capital gain will be added to the adjusted cost base of die Trust Unit. The adjusted cost base of a Trust Unit to a Unitholder will include all amounts paid or payable by the Unitholder for the Trust Unit, with certain adjustments. Trust Units issued to a Unitholder in lieu of a cash distribution of income (including net capital gains) will have a cost equal to the amount of such income and this cost will be averaged with the adjusted cost base of all other Trust Units held as capital property in accordance with the detailed provisions of the Tax Act in that regard. -107- Upon the disposition or deemed disposition by a Unitholder of a Trust Unit, whether on redemption or otherwise, the Unitholder will generally realize a capital gain (or a capital loss) equal to the amount by which the proceeds of disposition (excluding any amount payable by the Fund which represents an amount that must otherwise be included in the Unitholder's income as described above) are greater (or less) than the aggregate of the Unitholder's adjusted cost base of the Trust Unit and any reasonable costs of disposition. Where Trust Units are redeemed and any Fund Assets are distributed in specie to the Unitholder, the proceeds of disposition to the Unitholder of the Trust Units will be equal to the fair market value of the Fund Assets so distributed (excluding any income or gain realized by the Fund on the disposition of such Fund Assets to the Unitholder). One-half of any capital gain realized by a Unitholder on the disposition of a Trust Unit and the amount of any net taxable capital gains designated by the Fund in respect of a Unitholder will be included in the Unitholder's income under the Tax Act in the taxation year in which the disposition occurs or in respect of which a net taxable capital gains designation is made by the Fund. Subject to certain specific rules in the Tax Act, one-half of any capital loss realized on the disposition of a Trust Unit may be deducted against one-half of any capital gains realized by the Unitholder in the year of disposition, in the three preceding taxation years or in any subsequent taxation years. Capital losses realized on a disposition of Trust Units by a Unitholder that is a corporation may be reduced by the amount of taxable dividends designated to the Unitholder in accordance with the detailed rules in the Tax Act in that regard. The cost amount to a Unitholder, immediately after a redemption of Trust Units of the Unitholder, of any Fund Assets distributed to the Unitholder by the Fund upon such redemption or upon the termination of the Fund, will be equal to the fair market value of such Fund Assets at the time of the distribution. The redeeming Unitholder will be required to include in income interest on any Fund Note acquired (including interest that had accrued prior to the date of the acquisition of the interest in the Fund Note by the Unitholder) in accordance with the provisions of the Tax Act. To the extent that the Unitholder is required to include in income any interest that had accrued prior to the date of the acquisition of the Fund Notes by the Unitholder, an offsetting deduction may be available and to the extent of such deduction the adjusted cost base of the Fund Notes will be reduced. Taxable capital gains realized by a Unitholder that is an individual may give rise to alternative minimum tax, depending on the Unitholder's circumstances. Holders are advised to consult their own tax advisors prior to exercising their redemption rights. TAX EXEMPT UNITHOLDERS The Trust Units will generally be qualified investments for trusts ("PLANS") governed by registered retirement savings plans ("RRSPs"), registered retirement income funds ("RRIFs"), deferred profit sharing plans ("DPSPs") and registered education savings plans ("RESPs") under the Tax Act, subject however to the specific provisions of any particular Plan and the Fund maintaining its status as a mutual fund trust or continuing to be a registered investment under the Tax Act. The Trust Units will not be prohibited investments for registered pension plans, subject to the qualifications set out under the heading "Eligibility For Investment". The Plans will generally not be liable for tax in respect of any distributions received from the Fund or any capital gains realized on the disposition of any Trust Units. Where a Plan receives Fund Assets as a result of a redemption of Trust Units, such Fund Assets will likely not be qualified investments under the Tax Act for the Plans and could give rise to adverse consequences to the Plans (and, in the case of RRSPs or RRIFs, to the annuitants thereunder) including, in the case of RESPs, revocation of such Plans. Accordingly, Plans that own Trust Units should consult their own tax advisors before deciding to exercise the redemption rights thereunder. -108- If the Fund ceases to qualify as a mutual found trust and the Fund's registration as a registered investment under the Tax Act is revoked, the Trust Units will cease to be qualified investments under the Tax Act for Plans which could give rise to adverse consequences to the Plans (and in the case of RRSPs and RRIFs to the annuitants thereunder) including, in the case of RESPs, revocation of the registration of such Plans. On March 23, 2004, the Minister of Finance (Canada) proposed amendments to the Tax Act to restrict direct and indirect holdings by "designated taxpayers" which are trusts governed by a registered pension plan, certain tax exempt registered pension plan corporations and the Canada Pension Plan Investment Board of "restricted investment property" including units and debt of certain "business income trusts" (as defined in the proposals). On May 18, 2004, the Minister of Finance (Canada) announced that the proposals announced on March 23, 2004 to limit investment by pension plans in business income trusts would be suspended to allow for further consultations following which legislative proposals would be issued. On September 8, 2005, a consultation paper was released and on November 23, 2005, the then Minister of Finance announced a proposal to enhance the dividend gross-up and tax credit available in respect of eligible dividends paid to eligible shareholders and the end of the consultation process. ELIGIBILITY FOR INVESTMENT In the opinion of Blake, Cassels & Graydon LLP, as at the date hereof, eligibility of the Trust Units for investment by purchasers to whom the following statutes apply is, in certain cases, governed by criteria which such purchasers are required to establish as policies or guidelines pursuant to the applicable statute (and, where applicable, the regulations thereunder) and is subject to compliance with the prudent investment standards and general investment provisions provided therein: Insurance Companies Act (Canada) Trust and Loan Companies Act (Canada) Pension Benefits Standards Act, 1985 (Canada) an Act respecting insurance (Quebec) (in respect of insurers other than guarantee fund corporations, mutual associations and professional corporations) an Act respecting trust companies and savings companies (Quebec) (for a trust company investing its own funds and deposits it receives and a savings company (as defined therein) investing its funds) Supplemental Pension Plans Act (Quebec) Pension Benefits Act (Ontario) Loan and Trust Corporations Act (Ontario) Alberta Heritage Savings Trust Act (Alberta) Loan and Trust Corporations Act (Alberta) Employment Pension Plans Act (Alberta) Insurance Act (Alberta) Financial Institutions Act (British Columbia) Pension Benefit Standards Act (British Columbia) Pension Benefits Act (New Brunswick) Pension Benefits Act, 1992 (Saskatchewan) The Pension Benefits Act (Manitoba) Subject to the assumptions, limitations and restrictions described under "Canadian Federal Income Tax Considerations" being met, and to the provisions of any particular plan, in the opinion of such Counsel, as at the date hereof, the Trust Units will also be qualified investments for trusts governed by RRSPs, RRIFs, DPSPs and RESPs. -109- On March 23, 2004, the Minister of Finance Canada proposed amendments to the Tax Act to restrict direct and indirect investment by "designated taxpayers", which includes trusts governed by registered pension plans in "restricted investment property", including "business income trusts". On November 23, 2005, the then Minister of Finance announced a proposal to enhance the dividend gross-up and tax credit available in respect of eligible dividends paid to eligible shareholders and the end of the consultation process. See "Canadian Federal Income Tax Considerations - Tax Exempt Unitholders". RATINGS The Trust Units of the Fund have been rated "SR-2/Stable" under the income fund stability and sustainability rating system established by Standard & Poor's ("S&P"). The rating system managed by S&P is intended to rank the stability of an income fund's cash distribution stream on the basis of volatility and sustainability. The scale utilized by S&P runs from SR-1 (Highest) to SR-7 (Very Low). A rating of 'SR-1' signifies the highest level of expected sustainability and the lowest level of expected variability in a fund's distribution stream relative to other rated Canadian income funds. Conversely, a rating of 'SR-7 indicates the highest degree of expected variability and the lowest degree of expected sustainability in distributions. Funds rated 'SR-2' are considered by S&P to have a very high level of cash distribution stability relative to other rated Canadian income funds. The Fund also carries a triple B plus ('BBB+') long term corporate credit rating from S&P in addition to a triple B plus ('BBB+') credit rating on its secured bank loan facility. The bank loan rating changed from a prior rating of A minus ('A-') based on operating risk and new projects that the Fund has taken on. S&P's issue credit rating is a current opinion of the creditworthiness of an obligor with respect to a specific financial obligation, a specific class of financial obligations, or a specific financial program (such as medium-term note programs and commercial paper programs). The rating takes into consideration the creditworthiness of guarantors, insurers, or other forms of credit enhancement on the obligation, as well as the currency in which the obligation is denominated. Long-term credit ratings are divided into several categories ranging from 'AAA', reflecting the strongest credit quality, to 'D' reflecting the lowest. Long-term ratings from 'AA' to 'CCC' may be modified by the addition of a plus or minus sign to show relative standing within the major rating categories. According to S&P, an obligation rated 'BBB' exhibits adequate protection parameters. However, adverse economic conditions or changing circumstances are more likely to lead to a weakened capacity of the obligor to meet its financial commitment on the obligation. The addition of the plus reflects the relative standing of the Fund within the 'BBB' rating category. Investors should be advised that the ratings provided by S&P are not recommendations to buy, sell or hold Trust Units and are subject to revision or withdrawal at any time by S&P. -110- MARKET FOR SECURITIES TRADING PRICE AND VOLUME Trust Units The Trust Units have been listed and posted for trading on the Toronto Stock Exchange ("TSX") since December 23, 1997 under the symbol "APF.UN". The following table sets forth the high and low-closing prices and the aggregate volume of trading of the Trust Units on the periods indicated (as quoted by the TSX): TRADING OF TRUST UNITS ON THE TORONTO STOCK EXCHANGE ----------------------------- PERIOD HIGH LOW VOLUME - ----------------------------------------------- ----- ----- --------- ($) ($) 2003 January 9.48 9.10 4,034,368 February 9.43 8.72 5,477,755 March 8.95 8.40 2,726,973 April 8.93 8.50 2,593,937 May 9.39 8.60 3,727,622 June 9.60 8.90 6,072,826 July 9.93 9.26 4,798,176 August 9.95 9.65 4,047,767 September 9.86 9.25 3,878,249 October 9.89 9.35 2,895,400 November 10.05 9.40 2,810,810 December 10.88 9.95 2,747,798 2004 January 10.80 10.21 120,942 February 11.30 10.33 264,709 March 11.24 10.22 146,856 April 10.52 9.05 174,171 May 9.50 9.01 120,278 June 9.60 9.01 111,794 July 9.58 9.13 99,701 August 9.49 9.30 117,549 September 9.89 9.25 146,385 October 10.43 9.60 175,113 November 10.34 9.70 167,273 December 10.75 10.14 86,601 2005 January 10.68 10.32 138,735 February 10.69 20.26 199,435 March 10.33 9.07 193,435 April 10.04 9.30 121,795 May 10.20 9.55 124,295 June 10.52 9.95 117,204 July 10.78 10.25 152,670 -111- TRADING OF TRUST UNITS ON THE TORONTO STOCK EXCHANGE ----------------------------- PERIOD HIGH LOW VOLUME - ------------------------------------------------ ------ ------ ------- ($) ($) August 10.61 9.86 126,095 September 10.42 9.76 150,652 October 10.10 9.15 177,425 November 10.46 9.20 169,363 December 10.62 10.12 153,375 Debentures The Fund Debentures have been listed and posted for trading on the Toronto Stock Exchange ("TSX") since July 20, 2004 under the symbol "APF.DB". The following table sets forth the high and low closing prices and the aggregate volume of trading of the Fund Debentures on the periods indicated (as quoted by the TSX): TRADING OF DEBENTURES ON THE TORONTO STOCK EXCHANGE ---------------------------- PERIOD HIGH LOW VOLUME - ------------------------------------------------- ------ ------ ------- $ $ $100 2004 July 20-July 31 100.45 99.00 108,210 August 102.75 100.00 66,010 September 108.00 101.60 29,320 October 106.00 102.60 17,290 November 107.99 102.60 17,190 December 107.00 103.35 14,110 2005 January 107.00 104.50 8,720 February 107.00 103.53 25,670 March 104.50 100.25 31,330 April 105.00 102.00 20,840 May 104.50 102.10 15,250 June 106.53 103.10 6,750 July 106.00 103.51 8,050 August 108.00 103.75 5,260 September 109.53 105.50 10,130 October 108.00 100.53 12,080 November 106.50 102.00 16,160 December 106.53 103.00 8,320 -112- TRUSTEES AND OFFICER OF THE FUND The following table sets forth certain information with respect to the Trustees and the sole officer of the Fund. NAME AND SERVED AS NUMBER OF UNITS MUNICIPALITY OF TRUSTEE OR BENEFICIALLY RESIDENCE PRINCIPAL OCCUPATION OFFICER FROM OWNED - ------------------------ ---------------------------------- ----------------- --------------- CHRISTOPHER J. BALL Executive Vice President, Trustee since 2,000 Toronto, Ontario, Corpfinance International Limited October 22, 2002 Canada (financial services) KENNETH MOORE Managing Partner, NewPoint Trustee since 6,000 Toronto, Ontario, Canada Capital Partners Inc. (investment December 18, 1998 banking) GEORGE L. STEEVES Principal, True North Energy Trustee since 5,718(1) Aurora, Ontario, Canada (1169417 Ontario Inc.) (energy September 8, 1997 consulting firm) PETER KAMPIAN Chief Financial Officer, Algonquin Officer since 500 Cambridge, Ontario, Power Management Inc., January 2002(2) Canada Algonquin Power Systems Inc., Algonquin Power Trust and Algonquin Power Income Fund (1) Mr. Steeves' directly owns 2,804 Units and Mr. Steeves' spouse owns 2,914 Units. Mr. Steeves exercises control and direction over the Units owned by his spouse. (2) Prior to becoming an officer of Algonquin Power Trust and Algonquin Power Income Fund in January 2002, Mr. Kampian had been Chief Financial Officer of the Manager since July 1999. Each of the Trustees will serve as a Trustee of the Fund until the next annual meeting of Unitholders or until his successor is elected in accordance with the Declaration of Trust. Each of the Trustees has held their principal occupations for more than five years, other than Mr. Steeves who was from January 2001 to April 2002 a division manager of Earthtech Canada Inc. (engineering firm) and prior to January 2001, the president of Gumming Cockburn Limited (engineering firm). The Fund does not have an executive committee of the Trustees. -113- AUDIT COMMITTEE AUDIT COMMITTEE CHARTER Attached as Schedule "B" to the Annual Information Form is the charter for the Fund's audit committee (the "AUDIT COMMITTEE"). COMPOSITION OF THE AUDIT COMMITTEE Members of the Audit Committee are Christopher J. Ball, Kenneth Moore and George L. Steeves. Each member of the Audit Committee is independent and financially literate. RELEVANT EDUCATION AND EXPERIENCE The following is a description of the education and experience, apart from their roles as Trustees of the Fund, of each member of the Audit Committee that is relevant to the performance of his responsibilities as a member of the Audit Committee. Mr. Ball has extensive financial experience, with over 30 years of domestic and international lending experience. He is Executive Vice-President of Corpfinance International Limited, a privately owned long-term debt and securitization financier. Mr. Ball was formerly a Vice-President at Standard Chartered Bank of Canada with responsibilities for the Canadian branch operation. Prior to that, Mr. Ball held numerous positions with Canadian Imperial Bank of Commerce, including credit function responsibilities. Mr. Ball is the Chair of the Audit Committee. Mr. Moore also has extensive financial experience. He is the Managing Partner of NewPoint Capital Partners Inc., a boutique financial advisory firm focused on mergers and acquisitions. He was formerly a Vice-President at a Canadian Chartered Bank. Mr Moore holds a Chartered Financial Analyst designation. Mr. Steeves received a Bachelor and Masters of Engineering from Carleton University. Mr. Steeves is the former president of Cumming Cockburn Limited and has extensive financial experience in acting as a Chairman, director and/or audit committee member of public and private companies, including the Fund, Borealis Hydroelectric Holdings Inc. and KMS. Mr. Steeves is currently enrolled in the Directors College (McMaster University and the Conference Board) and is working towards obtaining certification as a "Chartered Director". PRE-APPROVAL POLICIES AND PROCEDURES All non-audit services proposed to be provided by the Fund's auditors must be approved by the Trustees prior to the auditors providing such services. -114- EXTERNAL AUDITOR SERVICE FEES For the financial year ended December 31, 2005 and December 31, 2004, KPMG LLP charged the following fees to the Fund: SERVICES 2005 FEES ($) 2004 FEES ($) - -------- ------------- ------------- Audit 215,000 190,500 Audit-Related(1) 191,540 196,500 Tax Fees(2) 281,600 211,000 All Other Fees(3) Nil Nil NOTES: (1) For assurance and related services that are reasonably related to the performance of the audit or review of the Fund's financial statements and not reported under Audit Fees, including prospectus advice, accounting advice, French translation services and audits of Algonquin Sanger Power LLC, Litchfield Park Service Company and the Long Sault Partnership. (2) For tax compliance, advice and planning services. DIRECTORS AND EXECUTIVE OFFICERS OF THE MANAGER AND POWER SYSTEMS The following sets out certain information with respect to the directors and executive officers of the Manager and Power Systems. Unless otherwise indicated, the directors and officers have been in their principal occupations for more than five years. NAME AND MUNICIPALITY OF RESIDENCE OFFICE PRINCIPAL OCCUPATION - ------------------------ ----------------------------------- ---------------------------- CHRISTOPHER K. Chief Executive Officer and Principal of Algonquin Power JARRATT Director of the Manager and Oakville, Ontario Director of Power Systems IAN E. ROBERTSON Vice-President and Director of the Principal of Algonquin Power Oakville, Ontario Manager and Director of Power Systems JOHN M.H. HUXLEY(1) Vice-President and Director of the Principal of Algonquin Power Toronto, Ontario Manager and Director of Power Systems -115- NAME AND MUNICIPALITY OF RESIDENCE OFFICE PRINCIPAL OCCUPATION - ------------------------ ----------------------------------- ---------------------------- DAVID C. KERR Vice-President, Secretary and Principal of Algonquin Power Toronto, Ontario Director of the Manager and Secretary and Director of Power Systems PETER KAMPIAN Chief Financial Officer of the Chief Financial Officer of Cambridge, Ontario Manager and of Power Systems Algonquin Power Income Fund ROBERT DODDS President of Power Systems Employee of Algonquin Power Mississauga, Ontario Trust NOTES: (1) Mr. John Huxley, a Vice-President and director of the Manager has been on a medical leave of absence since October 2003. Approximately 81,450 of the Trust Units are beneficially owned, directly or indirectly, by the directors and senior officers of the Manager, as a group. LEGAL PROCEEDINGS Except as otherwise described elsewhere in this annual information form and as described below, there are no legal proceedings to which the Fund is a party or to which its property is subject. INTEREST OF MANAGEMENT AND OTHERS IN MATERIAL TRANSACTIONS Except as disclosed elsewhere in this annual information form, the Manager has no material interest, direct or indirect, in any transaction occurring within the three most recently completed financial or during the current financial year that has materially affected or will materially affect the Fund. TRANSFER AGENTS AND REGISTRARS The transfer agent and registrar for the Trust Units is CIBC Mellon Trust Company, at its offices in Toronto, Montreal, Vancouver, Calgary, Halifax and Winnipeg. MATERIAL CONTRACTS Except as disclosed elsewhere in this annual information form, no contracts which could reasonably be regarded as material to the Fund have been entered into within the most recently completed financial year. LEGAL MATTERS -l16- Certain legal matters in connection with the preparation of this annual information form have been passed upon on behalf of the Fund and the Manager by Blake, Cassels & Graydon LLP. As of the date hereof, the partners and associates of Blake, Cassels & Graydon LLP own less than 1% of the issued and outstanding Trust Units of the Funds. RISK FACTORS THE FOLLOWING ARE CERTAIN ADDITIONAL RISK FACTORS RELATING TO THE BUSINESS OF THE FUND. THE FOLLOWING INFORMATION IS A SUMMARY ONLY OF CERTAIN RISK FACTORS AND IS QUALIFIED IN ITS ENTIRETY BY REFERENCE TO, AND MUST BE READ IN CONJUNCTION WITH, THE DETAILED INFORMATION APPEARING ELSEWHERE IN THIS ANNUAL INFORMATION FORM AND THE DOCUMENTS INCORPORATED BY REFERENCE HEREIN. REGULATORY CLIMATE AND PERMITS Profitability of the Fund Businesses will be in part dependent upon the continuation of a favourable regulatory climate with respect to the continuing operations and the future growth and development of the independent power production industry as a whole and, in particular, with respect to the hydroelectric power segment of the industry. Should the regulatory regime be modified in a manner which adversely affects the treatment of such facilities, including increases in taxes and permit fees, Distributable Cash may be adversely affected. The operation of infrastructure facilities is highly regulated. For example, in the case of hydroelectric generating facilities, water rights are generally owned by government and government agencies reserve the right to control water levels. The failure to obtain all necessary licences or permits, including renewals thereof or modifications thereto, may adversely affect Distributable Cash. In the United States, FERC issues licences for the construction, operation and maintenance of generating facilities. Facilities are required to be licenced or have valid exemptions from FERC. Failure to maintain such licences, including amendments or modifications thereto, may result in the owner being unable to operate the licenced facility and could adversely affect Distributable Cash. The US facilities obtain certain benefits and exemptions because of their Qualifying Facility status ("QF STATUS") under PURPA. If any facility were to lose its QF Status, the facility would no longer be entitled to the exemptions and benefits thereof. Loss of QF Status may also require the facility to cease selling electricity at the rates set forth in the existing power purchase agreements to the extent they exceed current short run Avoided Costs. Under certain circumstances, loss of QF Status on a retroactive basis could lead to, among other things, claims by the utility customers for a refund of payments previously made. The Fund's water and wastewater facilities are subject to rate setting by State regulatory authorities. Rates charged by the Fund's facilities may be reviewed and altered by the State regulatory authorities from time to time. These facilities are also subject to State and Federal permits, discharge parameters and other environmental requirements. Discharge and treatment requirements may change from time to time. DEPENDENCE UPON FUND BUSINESSES The Fund is entirely dependent upon the operations and assets of the Fund Businesses. Accordingly, distributions to Unitholders are dependent upon the ability of each of the Fund Businesses to pay principal and interest on the notes issued by it and to declare and pay dividends or distributions. -117- The profitability of the Fund Businesses may be affected by expiry of the present long-term power purchase agreements to which certain of the Fund Businesses are a party. GROWTH CAPITAL REQUIREMENTS The Fund's water and wastewater utilities may be located within areas of United States experiencing high growth. These utilities may have an obligation to service new residential, commercial and industrial customers. Accordingly, the Fund may have an obligation to expand its infrastructure and facilities to accommodate this growth. The Fund may have a requirement to access capital to undertake this construction obligation. ENVIRONMENTAL AND SAFETY CONSIDERATIONS The facilities encompass operations which require adherence to environmental and safety standards imposed by regulatory bodies. Failure to operate the facilities in strict compliance with these regulatory standards may expose the facilities to claims and clean-up costs. EXCHANGE RATES Currency fluctuations may affect the cash flow which the Fund will realize from its operations, as certain of the Fund Businesses sell electricity in the United States and receive proceeds from such sales in US dollars. Such Fund Businesses also incur costs in US dollars. CREDIT LINE The Fund has available the Credit Line provided by a syndicate of Canadian banks in the maximum principal amount of $145.0 million. The Credit Line was increased to $175.0 million on a short term basis in early 2006. The facility is to be utilized in respect of the acquisition of generating or infrastructure facilities by the Fund which meet the Fund's acquisition guidelines, letters of credit required in respect of acquired facilities and working capital requirements. As security for repayment of such line of credit, the Fund has, among other things, pledged the shares of certain Fund entities. As of December 31, 2005, the Fund had approximately $69.3 million outstanding under the Credit Line. In addition, the Fund has posted certain letters of credit totaling $45.0 million as security for obligations of Fund businesses. The terms of the Credit Line require the Fund to pay a standby charge of 0.3% on the unused portion of the revolving credit facility and maintain certain financial covenants. The facility is secured by, among other things, a fixed and floating charge over all the entities owned by the Fund. If the Credit Line goes into default, or is not renewed or refinanced when due, there is a risk that the lenders could exercise their security. If the Credit Line is not renewed or refinanced on reasonable terms, distributions to unitholders may be impaired. LOAN DEFAULTS The cash flows from several of the facilities are subordinated to senior debt. There is a risk that any particular loan may go into default if there is a breach in complying with such covenants and obligations resulting in the lender realizing on its security and, indirectly, causing the Fund to lose its investment in such facility. LABOUR RELATIONS While labour relations have been stable to date and there have not been any disruptions in operations as a result of labour disputes with employees, the maintenance of a productive and efficient -118- labour environment cannot be assured. With the exception of the EFW Facility, employees of the Fund Businesses and their material subcontractors are non-unionized. The EFW Facility is unionized and a new collective bargaining agreement was finalized in 2005. In the event of a strike or lock-out, the ability of Fund Businesses to generate Distributable Cash may be impaired. TAX RELATED RISKS There can be no assurance that income tax laws and the tax treatment of mutual fund trusts will not be changed in a manner which adversely affects Unitholders. In addition, adverse tax consequences may arise to Unitholders and to the Fund in the event that the Fund ceases to qualify as a "mutual fund trust" under the Tax Act, including potential liability for Part XII.2 taxes under the Tax Act. On September 16, 2004, the Minister of Finance released certain proposals that a trust, such as the Fund, would lose its status as a mutual fund trust under the Tax Act if, at any time, the aggregate fair market value of all of its issued and outstanding units held by one or more non-resident persons and/or by partnerships which are not Canadian partnerships under the Tax Act, is more than 50% of the aggregate fair market value of all issued and outstanding units of the trust, unless no more than 10% (based on fair market value) of the trust's property at any time is taxable Canadian property and certain other types of specified property. These proposals did not provide any means of rectifying the loss of mutual fund trust status. On December 6, 2004, the Minister of Finance suspended implementation of these proposals pending further consultation with the private sector. Although the Fund is of the view that all expenses being claimed by the Fund are reasonable and that the cost amount of the Fund's depreciable properties have been correctly determined, there can be no assurance that CRA will agree. If CRA successfully challenges the deductibility of such expenses or the correctness of such cost amounts, the return to Unitholders may be adversely affected. The October 31 Proposals could offset the Fund's ability to deduct its expenses, although the Fund does not expect to be adversely affected by the October 31 Proposals (see also "Canadian Federal Income Tax Considerations"). DEPENDENCE UPON KEY CUSTOMERS The customers that currently purchase power from the facilities are large utilities. If, for any reason, such customers were unable to fulfill their contractual obligations under the power purchase agreements, Distributable Cash would decline. RELIANCE ON THE MANAGER AND POWER SYSTEMS AND POTENTIAL CONFLICTS OF INTEREST Unitholders will be dependent upon the Manager for the administration of the Fund and upon the Manager and Power Systems for the management and operation of the facilities. There may be situations in which conflicts of interest may arise between the Manager, Power Systems and their respective officers and directors in relation to the interests of the Fund. The Manager and its affiliated entities may engage in activities similar to the activities of the Fund. The Manager or affiliated entities may acquire, own, manage and administer other facilities in the independent power production industry and, in particular, in the hydroelectric power segment of the industry. Provisions in business corporations act legislation provides certain procedures to be followed by directors and officers and remedies available against them where such procedures are not followed in the event of conflicts of interest. In addition, the Management Agreement provides that to the extent there is a conflict of interest which is not required to be dealt with by a board of directors or trustees, the resolution of the conflict by the Manager shall be fair and reasonable to the Fund Businesses. -119- CLIMATE Based on the type of power purchase agreements in place at all of the facilities in which the Fund has an interest, the revenue generated by the facilities is proportional to the amount of electrical energy generated. In addition, the amount of energy generated at the hydroelectric generating facilities is dependent upon available water flows. Accordingly, revenues will be significantly affected by low and high water flows within the watercourses on which the facilities are located. Engineering studies have been undertaken to assess the amount of energy which can be expected to be generated from each facility on an average annual basis. Furthermore, the majority of the facilities have significant operating histories with which to compare the theoretical estimates determined in the engineering studies. However, there can be no assurance that the historical water availability will remain unchanged or that no material hydro logic event will impact the hydrologic conditions which exist within a watercourse. It is, however, anticipated that due to the geographic diversity of the facilities, variability of total revenues will be minimized. Severe flooding may damage the hydroelectric generating facilities. Insurance may partially reduce this risk. EQUIPMENT FAILURE There is a risk of equipment failure due to wear and tear, design error or operator error, among other things, which could adversely affect revenues and Distributable Cash. Regular maintenance programs, insurance and maintenance funds partially mitigate this risk. COMMODITY PRICES Distributable Cash will, in part, depend upon prices to be paid for energy purchased by customers. Such commodity pricing will vary over time. Over the long term, unexpected fluctuations in such pricing may impact upon Distributable Cash. The facilities which are primarily impacted by changes in the price of natural gas are the Cogeneration Facilities. However, most of the power purchase agreements at these facilities include variable components based on the market price of natural gas, reducing the impact of an increase in the price of natural gas on the Distributable Cash generated by the facility. INVESTMENT ELIGIBILITY The Fund will endeavor to ensure that the Trust Units continue to be qualified investments for trusts governed by RRSPs, RRIFs, DPSPs (collectively, the "PLANS") On September 16, 2004, the Minister of Finance released certain proposals that a trust such as the Fund, would lose its status as a mutual fund trust under the Tax Act if, at any time, the aggregate fair market value of all of its issued and outstanding units held by one or more non-resident persons and/or by partnerships which are not Canadian partnerships under the Tax Act, is more than 50% of the aggregate fair market value of all issued and outstanding units of the trust, unless no more man 10% (based on fair market value) of the trust's property at any time is taxable Canadian property and certain other types of specified property. These proposals did not provide any means of rectifying the loss of mutual fund trust status. On December 6, 2004, the Minister of Finance suspended implementation of these proposals pending further consultation with the private sector. If the Fund ceases to qualify as a mutual fund trust and its registration as a registered investment under the Tax Act is revoked, the Trust Units will cease to be qualified investments for Plans and RESPs. It is also possible that the Fund may distribute Fund Assets on a redemption of Trust Units and that such -120- Fund Assets are not qualified Investments or Plans (See also "Canadian Federal Income Tax Considerations"). Where, at the end of any month, a Plan or RESP holds Trust Units or Fund Assets that are not qualified investments, the Plan or RESP may become liable to pay a penalty tax in respect of that month equal to 1% of the fair market value of the Trust Units or Fund Assets, as the case may be, at the time such property was acquired by the Plan. Certain other adverse tax consequences could also arise for a Plan or RESP or an annuitant or subscriber thereunder if the Plan or RESP acquires or holds Trust Units or Fund Assets and such property is not a qualified investment. One of the ways in which the Fund could cease to qualify as a mutual fund trust would be if non-residents of Canada ("NON-RESIDENTS") within the meaning of the Tax Act were to become the beneficial owners of a majority of the Trust Units. DELAYS IN DISTRIBUTIONS Payments by Algonquin Canada and Algonquin Power Trust to the Fund may be delayed by restrictions imposed by lenders, disruptions in service, recovery by the Manager of its expenses or the establishment of reserves for expenses. NATURE OF TRUST UNITS The Trust Units are dissimilar to conventional debt instruments in that there is no principal amount owing directly to Unitholders. The Trust Units do not represent a traditional investment and should not be viewed by investors as shares of Algonquin Canada or its subsidiaries or trust units Algonquin Power Trust. Each Trust Unit represents an equal undivided beneficial interest in the Fund. The Fund's sole assets will be the Fund Assets and other permitted investments. INAPPLICABILITY OF CERTAIN CORPORATE LAW RIGHTS AND REMEDIES Unitholder rights and responsibilities, although similar, are not necessarily the same as those of shareholders. Unlike a shareholder in a corporation, a unitholder in an income trust does not have the right to bring "oppressive or derivative actions" against the trustees or the management company. This type of action is used by minority equity shareholders to argue against actions by management that may be against the interests of minority shareholders. While the courts can intercede to remedy the situation on behalf of a shareholder, they would not have the same ability in the case of a trust. In addition, while income trusts resemble corporate entities in several ways, they fall under a different code of law with different requirements for corporate governance. As well, unlike directors and officers of a corporation who have a duty to act in the best interests of the shareholders, trustees may be individually indemnified by the income trust in respect to the discharge of their duties, or they may delegate many of their responsibilities to management to avoid potential liability. The Declaration of Trust imposes duties on the Trustees similar to those applicable to directors of a corporation. INAPPLICABILITY OF INSOLVENCY AND RESTRUCTURING LEGISLATION -121- The principal Canadian statutes that have traditionally been used for purposes of financial restructuring are the Bankruptcy and Insolvency Act (the "BIA"), and the Companies' Creditors Arrangement Act (the "CCAA"). Under the BIA, a trust cannot be a "debtor" or an "insolvent person" as a trust is not a "person" as defined in the BIA. Similarly, a trust is not a "company" or a "body corporate" and thus cannot be a "debtor company" within the meaning of the CCAA. The question arises as to how a financially distressed income trust would achieve financial restructuring, given the existing state of Canadian insolvency legislation. Because of the legal status of an income trust, existing bankruptcy and insolvency law would not apply. NEGATIVE IMPACTS ON CASH DISTRIBUTIONS The structure of an income trust is designed to maximize the cash distributions from a set of revenue-generating assets, with these distributions made on a periodic basis either monthly or quarterly. Cash distributions are maximized because income trusts distribute all available earnings to investors, whereas corporations distribute dividends on a discretionary basis. One of the defining features of an income trust structure is for the trust to hold a significant amount of unsecured, subordinated debt. The Fund currently holds approximately $90 million in project-specific debt. The maximization of cash distributions can be negatively impacted if this debt is replaced by new debt that has less favourable terms. In addition, cash distributions may be restricted if the Fund fails to maintain certain covenants under the Credit Line. If the Fund fails to meet its obligations under the Credit Line, creditors may have the power to suspend cash distributions to Unitholders of the Fund. UNCERTAIN TRUST UNIT MARKET The Fund cannot predict at what price the Trust Units will continue to trade and there can be no assurance that an active trading market in the Trust Units will be sustained. Units of a publicly traded income fund will not necessarily trade at values determined solely by reference to the underlying value of its assets. One of the factors that may influence the market price of the Trust Units is the annual distribution on the Trust Units. An increase in market interest rates may lead purchasers of Trust Units to demand a higher annual distribution and this could adversely affect the market price of the Trust Units. In addition, the market price for the Trust Units may be affected by changes in general market conditions, fluctuations in the market for equity or debt securities and numerous other factors beyond the control of the Fund. There can be no assurance that the Fund will be in a position to redeem Trust Units when requested to do so. COMPLETION OF ACQUISITIONS In any additional offerings, the Manager intends to utilize the net proceeds from the additional offering to complete the acquisitions detailed in the prospectus, promptly following the closing of an additional offering. While Fund Businesses generally enter into agreements governing the purchase and sale of potential facility interests to be acquired, there can be no assurances that the vendors of such facility interests will close the transactions of purchase and sale. In the event the Manager is unsuccessful in completing any particular acquisition within 30 days from closing of an additional offering, the -122- Manager intends to utilize the portion of the net proceeds plus accrued interest thereon (i) firstly, to retire any indebtedness of the Fund or its Facilities then outstanding and (ii) secondly, the balance thereof shall be distributed pro-rata to Unitholders as a return of capital. LIABILITY OF UNITHOLDERS The Declaration of Trust provides that no Unitholder will be subject to any liability in connection with the Fund or its obligations and affairs. The Declaration of Trust also provides that the Trustees and the Fund will make all reasonable efforts to include as a specific term of any obligations or liabilities being incurred by the Fund or by the Trustees on behalf of the Fund a contractual provision to the effect that neither the Unitholders nor the Trustees have any personal liability or obligations in respect thereof. Personal liability may arise in respect of claims against the Fund that do not arise under contracts, including claims in tort, claims for taxes and possibly certain other statutory liabilities. The Manager believes that the possibility of any personal liability of this nature arising is unlikely. In addition, the Ontario government passed legislation to provide certainty to unitholders of publicly traded trusts that their exposure to claims against the trust will be limited to their investment. Bill 106, the Budget Measures Act, 2004 (No. 2) ("BILL 106"), which proposed the enactment of the Trust Beneficiaries' Liability Act, 2004 (the "TBLA"), received Royal Assent on December 16, 2004. Bill 106 was deemed to come in force as of January 1, 2004. The TBLA came into force on December 16, 2004, the date that Bill 106 received Royal Assent. The TBLA applies to unitholders of any trust that is a "reporting issuer" under the Securities Act (Ontario) if its declaration of trust selects Ontario as its governing law. The Fund satisfies such requirements. The TBLA provides that investors in a publicly traded trust are not liable, as beneficiaries of the trust, for any act, default, obligation or liability of the trust or any of its trustees. ADDITIONAL INFORMATION Additional information, including Trustees' remuneration and indebtedness, principal holders of Trust Units, options to purchase securities of the Fund and interests of insiders in material transactions, as applicable, is contained in the Fund's information circular dated March 23, 2006 for the annual meeting of Unitholders to be held on April 27, 2006. Additional financial information is provided in the Fund's financial statements for the year ended December 31, 2005. A copy of such documents may be obtained upon request from the Fund. The Fund will also provide to any person upon request to the Fund: (a) when Trust Units are in the course of a distribution pursuant to a short form prospectus or when a preliminary short form prospectus has been filed in respect of a distribution of Trust Units, (i) one copy of the Fund's Annual Information Form, together with one copy of any document, or the pertinent pages of any document, incorporated by reference in the Annual Information Form; (ii) one copy of the comparative financial statements of the Fund for its most recently completed financial year together with the accompanying report of the auditors and one copy of any interim financial statements of the Fund subsequent to the financial statements for its most recently completed financial year; -123- (iii) one copy of the Fund's information circular in respect of its most recent annual meeting of Unitholders that involved the election of Trustees or one copy of any annual filing prepared in lieu of that information circular, as appropriate; and (iv) one copy of any other documents that are incorporated by reference into the preliminary short form prospectus or the short form prospectus and are not required to be provided under (i) to (iii) above; or (b) at any other time, one copy of any other documents referred to in (a)(i), (ii) and (iii) above, provided the Fund may require the payment of a reasonable charge if the request is made by a person who is not a Unitholder. SCHEDULE A GLOSSARY In this Annual Information Form, unless the context otherwise requires: "ADMINISTRATION AGREEMENT" means the amended and restated administration agreement between the Manager and the Fund dated as of January 1, 2006, pursuant to which the Manager provides administrative services to the Fund; "ADVANCE PAYMENT ACCOUNT" means a provision in the power purchase agreements between Niagara Mohawk and Trafalgar in respect of the Kayuta Lake facility and the Adams facility which tracks the amounts paid to Trafalgar from these two facilities which is either above or below Niagara Mohawk's actual Avoided Costs. Payments to Trafalgar above the Avoided Costs results in a positive balance to the account and a payment below the Avoided Costs results in a negative balance to the account. At the end of the contract period, a positive balance results in Trafalgar owing Niagara Mohawk the balance and a negative balance results in Niagara Mohawk owing Trafalgar the balance; "AFFILIATE" means an affiliate within the meaning of the Securities Act (Ontario); "AIRSOURCE" means AirSource Power Income Fund I LP, a limited partnership formed under the laws of the province of Manitoba; "AIRSOURCE ACQUISITION DEBT FACILITY" means the amended and restated $4.9 million subordinated acquisition debt facility provided by Algonquin Power Operating Trust to AirSource; "ALGONQUIN" means, collectively, Algonquin Canada, Algonquin Holdco and Algonquin Power Trust; "ALGONQUIN AMERICA" means Algonquin Power Fund (America) Inc., a Delaware corporation wholly-owned by Algonquin Canada; "ALGONQUIN AMERICA HOLDCO" means Algonquin Power Fund (America) Holdco Inc., a Delaware corporation wholly-owned by Algonquin America; "ALGONQUIN CANADA" means Algonquin Power Fund (Canada) Inc., a Nova Scotia corporation wholly-owned by Algonquin Holdco; "ALGONQUIN CANADA SHARES" means common shares of Algonquin Canada; "ALGONQUIN HOLDCO" means Algonquin Holdco Inc., an Ontario corporation wholly-owned by the Fund; "ALGONQUIN LSR COMPANIES" means Algonquin Power (Long Sault) Corporation Inc., an Ontario corporation, and Energy Acquisition (Long Sault) Ltd., an Ontario corporation; "ALGONQUIN POWER" means Algonquin Power Corporation Inc., an Ontario corporation; "ALGONQUIN POWER (LONG SAULT) PARTNERSHIP" means the partnership formed between the Algonquin LSR Companies, which partnership owns a 50% undivided interest in the Long Sault Rapids Facility; "ALGONQUIN POWER OPERATING TRUST" means Algonquin Power Operating Trust (formerly Drayton Valley Power Income Fund), an unincorporated open-ended trust established under the laws of the Province of Alberta, the sole unitholder of which is Algonquin Power Trust; -2- "ALGONQUIN POWER TRUST" means the Algonquin Power Trust, an unincorporated open-ended trust established under the laws of Ontario and of which the Fund is the sole beneficiary; "ASHUELOT FACILITY" means the 900 kilowatt hydroelectric generating facility located on the Ashuelot River approximately 0.2 kilometres upstream of the highway bridge at Hinsdale, New Hampshire and which is owned by the HDI III Partnership; "ASSOCIATE" means an associate within the meaning of the Securities Act (Ontario); "AVERY DAM FACILITY" means the 260 kilowatt hydroelectric generating facility located on the Winnipesaukee River near the City of Laconia, New Hampshire and which is owned by the Avery Dam Partnership; "AVERY DAM PARTNERSHIP" means Avery Hydroelectric Associates, a New Hampshire limited partnership comprised of Algonquin America and Algonquin America Holdco, and which owns the Avery Dam Facility; "AVOIDED COSTS" means costs a utility does not incur to add new generating capacity to the system by purchasing electricity from an independent or parallel generator; "AWRA" means Algonquin Water Resources of America Inc., a Delaware corporation wholly-owned by Algonquin Canada; "AWRI" means Algonquin Water Resources of Illinois, LLC, a wholly-owned subsidiary of AWRA; "AWRM" means Algonquin Water Resources of Missouri LLC, a wholly-owned subsidiary of AWRA; "AWRT" means Algonquin Water Resources of Texas LLC, a wholly-owned subsidiary of AWRA; "AWS" means Algonquin Water Services LLC, formerly Newspring Water LLC, an Arizona limited liability company owned equally by Algonquin Power and Newspring Partnership (a partnership between Algonquin Power and the Fund) to manage and operate water distribution and wastewater treatment facilities in Arizona and Texas; "BALEFILL FACILITY" means the 3.8 MW landfill gas to electricity facility located in North Arlington, New Jersey, which is owned by MM Hackensack Energy LLC; "BEAVER FALLS FACILITY" means the 2,500 kilowatt hydroelectric generating facility located on the Beaver River near the City of Watertown, New York and which is owned by Algonquin Power (Beaver Falls) LLC; "BELLA VISTA FACILITY" means the wastewater treatment facility located in the Town of Sierra Vista Arizona, and which is owned by Bella Vista Water Company, Inc., an Arizona corporation wholly-owned by AWRA; "BELLETERRE FACILITY" means the 2,200 kilowatt hydroelectric generating facility located on the Winneway River, in the Municipality of Laforce, Quebec and which is owned by Algonquin Canada; "BIG EDDY FACILITY" means the wastewater treatment facility located in Flint, Texas and which is owned by AWRT, a Texas limited liability corporation which is wholly-owned by AWRA; -3- "BLACK MOUNTAIN FACILITY" means the wastewater treatment facility located in the residential portion of the Boulders Resort, located 10 miles north of Scottsdale, Arizona, in the Town of Carefree, Arizona and which is owned by Black Mountain Sewer Corporation, an Arizona corporation wholly-owned by AWRA; "BROOKLYN FACILITY" means a 23.8 MW biomass-fired electric generating facility located in Queen's County, Nova Scotia; "BTU" means the quantity of heat required at sea level to heat 454.3 grams of water from 60E to 61E Fahrenheit at a constant measure of one atmosphere; "BURNSVILLE FACILITY" means the 4.21 MW landfill gas to electricity facility located in Burnsville, Minnesota, which is owned by MM Burnsville Energy LLC; "BURT DAM FACILITY" means the 600 kilowatt hydroelectric generating facility located on the Eighteen Mile Creek in the Town of Newfane, New York and which is owned by the Burt Dam Partnership; "BURT DAM PARTNERSHIP" means Burt Dam Power Company, a New York general partnership comprised of Algonquin America and Algonquin America Holdco, and which owns the Burt Dam Facility; "BUSINESS CORPORATIONS ACT" means the Business Corporations Act (Ontario); "CAMPBELLFORD FACILITY" means a 4,000 kilowatt hydroelectric generating facility located at Lock No. 14 on the Trent-Severn Waterway approximately four kilometres north of Campbellford, Ontario and which is owned by Algonquin Power (Campbellford) Limited Partnership. "CAMPBELLFORD PARTNERSHIP" means Algonquin Power (Campbellford) Limited Partnership, an Ontario limited partnership which owns the Campbellford Facility and of which Algonquin Power Trust holds all of the Class B units as a limited partner, representing 50% of the equity of the partnership. "CDA" means Crossroads Developers Associates L.L.C., a New Jersey limited liability company; "CHAPAIS FACILITY" means an electricity generating facility which burns woodwaste and which is located in the Town of Chapais, Quebec; "CLEMENT DAM FACILITY" means the 2,400 kilowatt hydroelectric generating facility located on the Winnipesaukee River near the Town of Tilton, New Hampshire and which is owned by Clement Dam Hydroelectric, LLC, a New Hampshire limited liability company of which Algonquin America and Algonquin America Holdco are the sole members; "COCHRANE FACILITY" means the 35.8 MW combined cycle co-generation facility located in Cochrane, Ontario; "COGENERATION DEVELOPMENTS" means the Fund's indirect interests in the Sanger Facility, Windsor Locks Facility and Crossroads Facility; "COLTON FACILITY" means the 1.26 MW landfill gas to electricity facility located in Colton, San Bernadino County, California, which is owned by NM Colton Genco LLC; "CO-OWNERS" means Algonquin Power (Long Sault) Partnership, an Ontario partnership, and N-R Power Partnership, an Ontario partnership, the co-owners of the Long Sault Rapids Facility; -4- "COTE STE-CATHERINE FACILITY" means the 11.1 MW hydroelectric generating facility located at the Cote Ste-Catherine lock of the Lachine section of the St. Lawrence Seaway, and which is owned by Algonquin Power (Mont-Laurier) Limited Partnership; "CROSSROADS FACILITY" means the 10 MW cogeneration facility located in Mahwah, New Jersey and which is owned by KMS Crossroads Inc., a Delaware corporation, which is wholly-owned, indirectly, by KMS; "DEBENTURE TRUSTEE" means CIBC Mellon Trust Company; "DECLARATION OF TRUST" means the declaration of trust dated as of September 8, 1997, as amended, as the same may be further amended, supplemented or restated from time to time, pursuant to which the Fund was created; "DICKSON DAM FACILITY" means the 15 MW hydroelectric generating facility located on the Red Deer River at Dickson Dam, 20 kilometres west of the Town of Innisfail, Alberta and which is owned by Algonquin Power Operating Trust; "DISTRIBUTABLE CASH" means all cash amounts which are received by the Fund including, without limitation, interest, dividends, royalties, lease payments, distributions from trusts, proceeds from the disposition of securities including any proceeds of redemption of shares or trust units, return of capital and repayment of indebtedness and all cash amounts received by the Fund in respect of the year to the extent not previously distributed (excluding all amounts required to satisfy the redemption of Units and which have become payable in cash by the Fund in respect of the year, and the amount (if any) by which Net Income for the year is negative), less any amount or amounts which the Trustees may reasonably consider to be necessary to provide for the payment of any costs, expenses or obligations which have been incurred in the course of the activities and operations of the Fund (including, for greater certainty, administrative expenses of the Fund and amounts required for the business and operation of the Fund and, in particular, amounts required to pay the deferred portion of the purchase price for any assets acquired by the Fund, directly or indirectly) and to provide for the payment of any tax liability of the Fund or its subsidiary entities; "DONNACONA FACILITY" means the 4,800 kilowatt hydroelectric generating facility located on the lower portion of the Jacques Cartier River, near the Town of Donnacona, Quebec and which facility is owned by the Donnacona Partnership; "DONNACONA HOLDCO" means Donnacona Holdings Inc., an Ontario corporation wholly-owned by Algonquin Canada, and which owns a 0.01% interest in the Donnacona Partnership; "DONNACONA PARTNERSHIP" means Societe Hydro-Donnacona S.E.N.C., a Quebec general partnership comprised of Algonquin Canada holding a 99.99% interest and its wholly-owned subsidiary, Donnacona Holdco, holding a 0.01% interest; "EFW FACILITY" means the 10 MW energy from waste generating facility located in the Regional Municipality of Peel, Ontario and which is owned by APEW, a wholly-owned subsidiary of KMS; "EXTRAORDINARY RESOLUTION" means a resolution passed by a majority of not less than 66 2/3% of the votes cast, either in person or by proxy, at a meeting of Unitholders called for the purpose of approving such resolution, or approved in writing by the holders of not less than 66 2/3% of the Trust Units entitled to be voted on such resolution; "FACILITIES" means infrastructure facilities in which the Fund has an interest, directly or indirectly; -5- "FERC" means the United States Federal Energy Regulatory Commission; "FLYING CLOUD FACILITY" means the 4.89 MW landfill gas to electricity facility located in Eden Prairie, Minnesota, which is owned by Landfill Power LLC; "FOX RIVER FACILITY" means the wastewater treatment facility located in Sheridan, Illinois and which is owned by AWRT, a Texas limited liability corporation which is wholly-owned by AWRA; "FRANKLIN FACILITY" means the 1,820 kilowatt hydroelectric generating facility located on the Winnipesaukee River near the Town of Franklin, New Hampshire and which is owned by Franklin Power, LLC, a New Hampshire limited liability company wholly-owned by Algonquin America; "FRANKLIN NOTE" means the 11.05% senior, secured note due January 1, 2006 issued by Franklin Industrial Complex, Inc.; "FUND" means the Algonquin Power Income Fund, an unincorporated open-ended trust established under the laws of Ontario; "FUND ASSETS" means the shares of Algonquin Holdco, units of the Algonquin Power Trust, the Fund Notes, the Lease Payment Rights, the LSR Royalty Interests and any other securities or assets held directly or indirectly by the Fund from time to time; "FUND BUSINESSES" means the businesses carried on by Algonquin Holdco, Algonquin Canada, Algonquin Power Trust, Algonquin America, Algonquin America Holdco, Donnacona Holdco, the Donnacona Partnership, the Nicholls LSR Companies, the Algonquin LSR Companies, the Co-Owners, the HDI Partnership, the Glenford Partnership, the Rattle Brook Partnership, the Avery Dam Partnership, the Burt Dam Partnership, the Hadley Falls Partnership, the HDI III Partnership, the Hollow Dam Partnership, the Lakeport Corporation, the Moretown Partnership, Clement Dam Hydroelectric LLC, MTL Partnership, Gregg Falls Hydroelectric Associates Limited Partnership, Pembroke Hydro Associates Limited Partnership, SFR Hydro Corporation, Mine Falls Limited Partnership, Great Falls Hydroelectric Company Limited Partnership, Great Falls Energy, L.L.C., Tug Hill Energy, Inc., Worcester Hydro Company, Inc., Oswego Hydro Partners, L.P., CSI Oswego Corp., Oswego Energy Corp., Court Street Investments, Inc., Oswego Power Company, Inc., AWRA, Black Mountain Sewer Corporation, Gold Canyon Sewer Company, Algonquin Power Operating Trust, KMS, Algonquin Power Energy from Waste Inc. (formerly KMS Peel Inc.), KMS America, KMS Crossroads, Inc., Bella Vista Water Co., Inc., Franklin Power LLC, Algonquin Sanger Power, LLC., Algonquin Windsor Locks LLC, Litchfield Park Services Company, Tall Timbers Utility Company, Inc., Woodmark Utilities, Inc., Corporation D'Investissements Eoliennes Algonquin Power, Corporation D'Investissements Eoliennes St-Laurent Inc., Algonquin Power (Biogas) LLC, Algonquin Power - Cambrian Pacific Genco LLC, MM Tajiguas Energy LLC, MM Prima Deshecha Energy LLC, MM Nashville Energy LLC, MM Hackensack Energy LLC, Suncook Energy LLC, MM Burnsville Energy LLC, Minnesota Methane II, LLC, NM Milliken Genco LLC, NM Colton Genco LLC, NM Mid-Valley Genco LLC, NM San Timateo Genco LLC, MM San Bernardino Energy LLC, NEO-Montauk Genco LLC, Algonquin Power Systems (LFG) LLC, Algonquin Power (Beaver Falls), LLC, Landfill Power LLC, Rio Rico Utilities Inc., Algonquin Water Resources of Texas LLC, Algonquin Water Resources of Missouri LLC, Algonquin Water Resources of Illinois, LLC, Dyna Fibres Inc., Algonquin Power Acquisition Inc., Algonquin Energy Services Inc., Societe en Commandite Algonquin (Eoliennes), KMS Bakery Power Partners L.P., Algonquin Water Services LLC and any other business a subsidiary of the Fund may acquire or any other business carried on by a corporation, partnership or other entity, the shares, partnership interests or other equity interest, as the case may be, of which the Fund acquires; -6- "FUND DEBENTURES" means the 6.65% convertible unsecured subordinated debentures of the Fund due July 31, 2011 at a price of $1,000 per debenture; "FUND NOTES" means any notes issued by Algonquin Power Trust, Algonquin Canada, Algonquin Holdco and Algonquin America to the Fund, the LSR Subordinate Note and the Trafalgar Class B Note; "GIGAWATTS" or "GW" means 1,000 megawatts of electrical power; "GLENFORD FACILITY" means the 4,950 kilowatt hydroelectric generating facility located on the Ste-Anne River near the Village of Ste-Christine d'Auvergne, Quebec and which is owned by the Glenford Partnership; "GLENFORD MINORITY INC." means an Ontario corporation which is currently wholly-owned by Algonquin Power and which holds a 0.01% limited partnership interest in the cash distributions and income allocations from the Glenford Partnership; "GLENFORD PARTNERSHIP" means Societe en Commandite Chute Ford, a limited partnership formed under the laws of Quebec comprised of Algonquin Power and Glenford Minority Inc.; "GLENFORD SENIOR DEBT" means financing in the outstanding principal amount of approximately $5.5 million provided by Corpfinance International Limited to the Glenford Partnership; "GOLD CANYON FACILITY" means the wastewater treatment facility located in an industrial area of the Town of Gold Canyon, Arizona and which is owned by Gold Canyon Sewer Company, an Arizona corporation wholly-owned by AWRA; "GOVERNANCE AGREEMENT" means the amended and restated governance agreement dated as of January 1, 2006 between the Fund, the Manager and Algonquin dealing with the composition of the boards of directors of Algonquin Holdco and Algonquin Canada and other matters; "GREAT FALLS FACILITY" means a 10,950 kilowatt hydroelectric generating facility located on the Passaic River near the City of Paterson, New Jersey and which is owned by the Great Fails Partnership; "GREAT FALLS PARTNERSHIP" means Great Falls Hydroelectric Company Limited Partnership, a Maryland limited partnership which owns the Great Falls Facility of which Algonquin America and Great Falls Energy, L.L.C. are the partners; "GREGG FALLS FACILITY" means the 3,500 kilowatt hydroelectric generating facility located at the Piscataquog River near the Town of Goffstown, New Hampshire and which is owned by Gregg Falls Hydroelectric Associates Limited Partnership, a limited partnership between Algonquin America and Algonquin Holdco; "HADLEY FALLS FACILITY" means the 250 kilowatt hydroelectric generating facility located at the Hadley Falls Dam near the Town of Goffstown, New Hampshire and which is owned by the Hadley Falls Partnership; "HADLEY FALLS PARTNERSHIP" means Hadley Falls Associates, a New Hampshire limited partnership comprised of Algonquin America and Algonquin America Holdco, and which owns the Hadley Falls Facility; -7- "HDI PARTNERSHIP" means HDI Associates I, an Indiana general partnership comprised of Algonquin America and Algonquin America Holdco, which owns the Lochmere Facility and the Hopkinton Facility; "HDI III PARTNERSHIP" means HDI Associates III, a New Hampshire limited partnership comprised of Algonquin America and Algonquin America Holdco, and which owns the Lower Robertson Facility and the Ashuelot Facility; "HILL COUNTRY FACILITY" means the wastewater treatment facility located in New Braunfels, Texas and which is owned by AWRT, a Texas limited liability corporation which is wholly-owned by AWRA; "HOLLOW DAM FACILITY" means the 900 kilowatt hydroelectric generating facility located on the West Branch of the Oswegatchie River in the Town of Fowler, New York and which is owned by the Hollow Dam Partnership; "HOLLOW DAM PARTNERSHIP" means Hollow Dam Power Company, a New York general partnership comprised of Algonquin America and Algonquin America Holdco, and which owns the Hollow Dam Facility; "HOLLY LAKE FACILITY" means the wastewater treatment facility located in Big Sandy, Texas and which is owned by AWRT, a Texas limited liability corporation which is wholly-owned by AWRA; "HOPKINTON FACILITY" means the 250 kilowatt hydroelectric generating facility located on the Contoocook River in the Village of Contoocook, New Hampshire and which generating facility is owned by the HDI Partnership; "HYDRASKA FACILITY" means the 2,250 kilowatt hydroelectric generating facility located on the Yamaska River near the Town of Ste-Hyacinthe, Quebec and which is owned by Algonquin Power Trust; "JOLIET FACILITY" means the 3.2 MW landfill gas-fuel generating facility located in Joliet, Illinois and which is owned by KMS Joliet Power Partners, L.P., an Illinois limited partnership, and which was permanently closed on May 10, 2005; "KILOWATT HOUR" or "KW-HR" means an hour during which one kilowatt of electrical energy has been continuously produced; "KILOWATTS" or "KW" means 1,000 watts of electrical power; "KINGS FALLS FACILITY" means a 1,750 kilowatt hydroelectric generating facility located on the Deer River, near the Town of Copenhagen in Lewis County, New York which is owned by Tug Hill Energy, Inc.; "KINGSLAND FACILITY" means the 2.9 MW landfill gas to electricity facility located in North Arlington, New Jersey, which is owned by MM Hackensack Energy LLC; "KIRKLAND LAKE FACILITY" means a 102 MW combined cycle power co-generation facility located in Kirkland Lake, Ontario; "KMS" means KMS Power Income Fund, an unincorporated open-ended trust established under the laws of Alberta; "KMS AMERICA" means KMS America Inc., a Delaware corporation which is wholly-owned by Algonquin Energy from Waste Inc.; -8- "LAKEPORT CORPORATION" means Lakeport Hydroelectric Corporation, an S Corporation under United States law whose sole shareholder is Algonquin America, and which owns the Lakeport Facility; "LAKEPORT FACILITY" means the 600 kilowatt hydroelectric generating facility located on the Winnipesaukee River near the Town of Lakeport, New Hampshire and which is owned by the Lakeport Corporation; "LFG FACILITIES" means the 12 landfill gas powered generating stations in California, Tennessee, New Jersey. New Hampshire and Minnesota representing approximately 36 MW of installed capacity and which are owned by the Fund; "LITCHFIELD FACILITY" means the wastewater treatment facility located in Litchfield Park, Arizona and which is owned by Litchfield Park Service Company, an Arizona corporation which is wholly-owned by AWRA; "LOCHMERE FACILITY" means the 1,200 kilowatt hydroelectric generating facility located on the Winnipesaukee River, in the Village of Lochmere, New Hampshire and which facility is owned by the HDI Partnership; "LONG SAULT RAPIDS FACILITY" means the 18,000 kilowatt hydroelectric generating facility located on the Abitibi River, near the Town of Cochrane, Ontario and which facility is owned by the Co-Owners; "LOWER ROBERTSON FACILITY" means the 960 kilowatt hydroelectric generating facility located on the Ashuelot River approximately one kilometre upstream of the Highway bridge at Hinsdale, New Hampshire and which is owned by the HDI III Partnership; "LSR BRACE ROYALTY INTEREST" means the cash flows generated by the Long Sault Rapids Facility paid pursuant to an agreement dated November 1, 1989, as amended November 2, 1989, between N-R Power, Nirabro Industries Ltd., Mr. Tim Richardson and Mr. John Brace respecting certain payments to be paid for ten years commencing April 1, 1998, which obligation was assigned by N-R Power to the Co-Owners and which was acquired by the Fund on April 17, 1998; "LSR MCKENZIE ROYALTY INTEREST" means the cash flows generated by the Long Sault Rapids Facility paid pursuant to an agreement dated September 12, 1994 between N-R Power and Mr. Rodney S. McKenzie respecting payments of $150,000 per year payable in arrears for a period of 20 years commencing April 1, 1998, which obligation was assigned by N-R Power to the Co-Owners and which was acquired by the Fund on April 17, 1998; "LSR RICHARDSON ROYALTY INTEREST" means the cash flows generated by the Long Sault Rapids Facility paid pursuant to an agreement dated December 11, 1992 between N-R Power and Mr. Tim Richardson respecting payments of $83,333 per year payable in arrears for a period of six years commencing April 1, 1998, which obligation was assigned by N-R Power to the Co-Owners and which was acquired by the Fund on April 17, 1998; "LSR ROYALTY INTERESTS" means the LSR Brace Royalty Interest, the LSR McKenzie Royalty Interest and the LSR Richardson Royalty Interest, all acquired by the Fund on April 17, 1998; "LSR SUBORDINATE NOTE" means the 14.14% secured, subordinated note in the principal amount of $2,000,000 issued jointly and severally by Algonquin Power (Long Sault) Corporation Inc., Energy Acquisition (Long Sault) Ltd., Nicholls Holdings Inc. and Radtke Holdings Inc. and acquired by the Fund on April 17, 1998; -9- "MANAGEMENT AGREEMENT" means the amended and restated management agreement dated as of January 1, 2006 between the Manager and Algonquin pursuant to which the Manager or its delegate provides management services to the subsidiary entities of the Fund; "MANAGER" means Algonquin Power Management Inc., an Ontario corporation wholly-owned by the shareholders of Algonquin Power; "MANAGER'S INTEREST" means the special voting shares of Algonquin Canada and Algonquin America owned by the Manager entitling it to elect two of the three directors of Algonquin Canada and all of the directors of Algonquin America; "MEGAWATT" OR "MW" means 1,000,000 watts of electrical power; "MEGAWATT HOUR" or "MW-HR" means 1,000 kilowatt hours of electrical energy; "MID-VALLEY FACILITY" means the 2.52 MW landfill gas to electricity facility located in Fontana, San Bernadino County, California, which is owned by NM Mid Valley Genco LLC; "MILLIKEN FACILITY" means the 2.52 MW landfill gas to electricity facility located in Ontario, San Bernadino County, California, which is owned by NM Milliken Genco LLC; "MILTON FACILITY" means the 1,335 kilowatt hydroelectric generating facility located on the Salmon River on the Maine-New Hampshire border, approximately 70 km from Manchester, New Hampshire and which is owned by SFR Hydro Corporation; "MINE FALLS FACILITY" means the 3,000 kilowatt hydroelectric generating facility located on the Nashua River near the City of Nashua, New Hampshire and which is owned by the Mine Fails Limited Partnership; "MMBTU" means one million BTU's; "MONT LAURIER FACILITY" means the 2,725 kilowatt hydroelectric generating facility located on the Riviere-du-Lievre in the Town of Mont Laurier, Quebec and which is owned by the MTL Partnership; "MORETOWN FACILITY" means the 1,200 kilowatt hydroelectric generating facility located on the Mad River near the Town of Moretown, Vermont and which is owned by the Moretown Partnership; "MORETOWN PARTNERSHIP" means Moretown Hydro Energy Company, a Vermont partnership comprised of Algonquin America and Algonquin America Holdco, and which owns the Moretown Facility; "MTL PARTNERSHIP" means Algonquin Power (Mont-Laurier) Limited Partnership, a Quebec limited partnership between Algonquin Canada and Algonquin Power Trust; "NASHVILLE (BORDEAUX) FACILITY" means the 1.9 MW landfill gas to electricity facility located in Nashville, Tennessee, which is owned by MM Nashville Energy LLC; "NET INCOME OF THE FUND" or "NET INCOME" means for any taxation year of the Fund the net income of the Fund for the year computed in accordance with the provisions of the Tax Act, less the amounts of any non-capital losses of the Fund for prior years that are deductible in computing the Fund's taxable income for the year in accordance with the Tax Act; provided, however, that capital gains and capital losses shall be excluded and provided further that: (i) the portion of the Fund's income comprised of taxable -10- dividends received from corporations resident in Canada shall be calculated on the basis that the amount included in the Fund's income is the actual amount of the dividend received, excluding the gross-up adjustment provided in paragraph 82(1)(b) of the Tax Act; and (ii) no amount shall be deductible in respect of amounts paid or payable to Unitholders. Net Income of the Fund shall not include any income or capital gains, which are realized by the Fund, in accordance with the Tax Act, on a distribution of Fund Assets to a Unitholder pursuant to an in specie redemption of the Unitholder's Units; "NET REALIZED CAPITAL GAINS" means for any year of the Fund the amount determined as the amount, if any, by which the aggregate of the capital gains of the Fund in the year exceeds the aggregate of the capital losses of the Fund in the year and the product of two (or the reciprocal of any proportion other than one-half that may be provided under section 38 of the Tax Act in respect of the relevant year) and the amount of any net capital losses from prior years which the Fund is permitted by the Tax Act to deduct in computing the taxable income of the Fund for the year. Net Realized Capital Gains shall not include any income or capital gains, which are realized by the Fund, in accordance with the Tax Act, on a distribution of Fund Assets to a Unitholder pursuant to an in specie redemption of the Unitholder's Units; "NEW ENGLAND DEVELOPMENTS" means the Gregg Falls Facility, the Pembroke Facility, the Clement Dam Facility, the Franklin Facility, the Moretown Facility, the Lochmere Facility, the Lower Robertson Facility, the Ashuelot Facility, the Lakeport Facility, the Avery Dam Facility, the Hadley Falls Facility, the Hopkinton Facility, the Milton Facility, the Mine Falls Facility, the Great Falls Facility and the Worcester Facility; "NEWFOUNDLAND DEVELOPMENT" means the Rattle Brook Facility; "NEW YORK DEVELOPMENTS" means the following hydroelectric generating facilities: Ogdensburg, Forestport, Herkimer, Christine Falls, Cranberry Lake, Kayuta Lake, Adams, Kings Falls, Otter Creek, Phoenix, Beaver Falls, Burt Dam and Hollow Dam; "NHPUC" means the New Hampshire Public Utilities Commission; "NHWRB" means the New Hampshire Water Resources Board; "NIAGARA MOHAWK" means Niagara Mohawk Power Corporation; "NICHOLLS LSR COMPANIES" means Nicholls Holdings Inc., an Ontario corporation, and Radtke Holdings Inc., an Ontario corporation; "N-R POWER" means N-R Power & Energy Corp., an Ontario corporation; "N-R POWER PARTNERSHIP" means the partnership formed between the Nicholls LSR Companies, which partnership owns a 50% undivided interest in the Long Sault Rapids Facility; "OEFC" means Ontario Electricity Financial Corporation; "OFF-PEAK" means hours other than On-peak hours; "ON-PEAK" means hours between 7:00 a.m. and 11:00 p.m., local time, Monday to Friday, inclusive, but excluding public holidays; "ONTARIO DEVELOPMENTS" means the following hydroelectric generating facilities: Long Sault Rapids, Hurdman Dam, Drag Lake Dam, Burgess Dam and Campbellford; -11- "OPERATIONS SUPERVISORY AGREEMENT" means the amended and restated operations supervisory agreement between Algonquin and Power Systems dated as of January 1, 2006 pursuant to which Power Systems provides operations and supervisory services to certain of the subsidiary entities of the Fund; "OTTER CREEK FACILITY" means the 530 kilowatt hydroelectric generating facility located on the Otter Creek, near the Town of Craig, New York and which is owned by Tug Hill Energy, Inc., a New York corporation and an indirect, wholly-owned subsidiary of Algonquin America; "PEMBROKE FACILITY" means the 2,600 kilowatt hydroelectric generating facility located on the Suncook River near the Town of Pembroke, New Hampshire and which is owned by Pembroke Hydro Associates Limited Partnership, a New Hampshire limited partnership formed between Algonquin America and Algonquin America Holdco; "PHOENIX FACILITY" means the 3,500 kilowatt hydroelectric generating facility located on the Oswego River, in the Town of Phoenix, Onondaga County, New York and which is owned by Oswego Hydro Partners L.P.; "PINEY SHORES FACILITY" means the wastewater treatment facility located in Conroe, Texas and which is owned by AWRT, a Texas limited liability corporation which is wholly-owned by AWRA; "POWER SYSTEMS" means Algonquin Power Systems Inc., an Ontario corporation wholly-owned by Algonquin Power; "PRIMA DESCHECHA FACILITY" means the 6.1 MW landfill gas to electricity facility located in San Juan Capistrano, Orange County, California, which is owned by MM Prima Deshecha Energy LLC; "PSNH" means Public Service Company of New Hampshire, a large, investor-owned utility; "PURPA" means U.S. Public Utilities Regulatory Policies Act; "QUEBEC DEVELOPMENTS" means the Cote Ste-Catherine Facility, the Ste-Raphael Facility, the Mont Laurier Facility, the Riviere-du-Loup Facility, the Hydraska Facility, the Saint-Alban Facility, the Glenford Facility, the Donnacona Facility, the Ste-Brigitte Facility, the Rawdon Facility, the Belleterre Facility and the St. Raphael de Bellechasse Facility; "RATTLE BROOK FACILITY" means the 4,000 kilowatt hydroelectric generating facility located on the Rattle Brook, near the Village of Jackson's Arm, Newfoundland and which is owned by the Rattle Brook Partnership; "RATTLE BROOK PARTNERSHIP" means the Algonquin Power (Rattle Brook) Partnership, a Newfoundland partnership currently comprised of Algonquin Power Corporation (Rattle Brook) Inc., wholly-owned by the shareholders of Algonquin Power and Algonquin Canada; "RAWDON FACILITY" means the 2,500 kilowatt hydroelectric generating facility located on the Ouareau River approximately one kilometre from the Village of Rawdon, Quebec and which is owned by Algonquin Canada; "RIO RICO FACILITY" means the water reclamation and water distribution facility located in Rio Rico, Arizona and which is owned by Rio Rico Utilities Inc., an Arizona company which is wholly-owned by AWRA; -12- "RIVIERE-DU-LOUP FACILITY" means the 2,600 kilowatt hydroelectric generating facility located on the Riviere-du-Loup near the Town of Riviere-du-Loup, Quebec, formerly known as the Hydro Senmo Facility, and which is owned by Algonquin Canada; "RUN-OF-THE-RIVER" means a mode of operation of a hydroelectric generating facility where there is a continuous discharge of water from the facility with no storage and release of water; "SAINT-ALBAN FACILITY" means the 8,200 kilowatt hydroelectric generating facility located on the Ste-Anne River approximately one kilometre from the Village of Saint-Alban, Quebec and which is owned by SLI; "SANGER FACILITY" means a 43.5 MW natural gas-fired generating facility located in the City of Sanger, California and which is owned by Algonquin Sanger Power, L.L.C.; "SENIOR DEBT FACILITY" means the $73.3 million senior debt facility provided by a syndicate of banks to AirSource; "SLI" means SNC-Lavalin Inc., a Canadian corporation which owns the Saint-Alban Facility; "SMALL POWER ACT" means the Small Power Research and Development Act (Alberta); "ST. LEON FACILITY" means the 99 MW wind energy generating facility near St. Leon, Manitoba which is currently being constructed and is owned by St. Leon GP; "ST. LEON GP" means St. Leon Wind Energy GP Inc., a corporation incorporated under the laws of Canada; "ST. LEON GP CONSTRUCTION FACILITY" means the $64.4 million subordinated construction/term debt facility provided by Algonquin Power Operating Trust to St. Leon GP; "ST. LEON LP" means St. Leon Wind Energy LP, a limited partnership formed under the laws of the province of Manitoba; "ST. LEON TRUST" means St. Leon Wind Energy Trust, a trust established under the laws of the province of Manitoba; "ST. LEON TRUST CONSTRUCTION FACILITY" means the $69.4 million subordinated construction/term debt facility provided by Algonquin Power Operating Trust to St. Leon Trust; "ST. RAPHAEL DE BELLECHASSE FACILITY" means a 650 kilowatt hydroelectric generating facility located on the Du Sud River near Saint-Raphael de Bellechasse, approximately 40 kilometres east of Quebec City, also known as the Arthurville Facility, and which is owned by Algonquin Power Trust; "STE-BRIGITTE FACILITY" means the 4,200 kilowatt hydroelectric generating facility located on the Nicolet River, in the Municipality of Ste- Brigitte-des-Saults, Quebec and which is owned by Algonquin Canada; "STE-RAPHAEL FACILITY" means the 3,500 kilowatt hydroelectric generating facility located on the Riviere de Sud near Quebec City and which is owned by Algonquin Canada; -13- "STRANDED COSTS" means costs incurred by a utility during the normal course of business prior to deregulation that can no longer be paid by the rate base due to changes to various factors, including price, the economy, system requirements, government policies and technology; "SUNCOOK FACILITY" means the 3.1 MW landfill gas to electricity facility located in Nashua, New Hampshire, which is owned by Suncook Energy LLC; "TALL TIMBERS FACILITY" means the wastewater treatment facility located in Tyler, Texas and which is owned by Tall Timbers Utility Company, Inc., a Texas corporation which is wholly-owned by AWRA; "TAJIGUAS FACILITY" means the 3.05 MW landfill gas to electricity facility located in Goleta, County of Santa Barbara, California, which is owned by MM Tajiguas Energy LLC; "TAX ACT" means the Income Tax Act (Canada); "TCEQ" means the Texas Commission on Environmental Quality; "THERMAL DEVELOPMENTS" means the Fund's indirect interests in the EFW Facility, Prima Deshecha Facility, Tajiguas Facility, Milliken Facility, Mid-Valley Facility, Colton Facility, Nashville (Bordeaux) Facility, Balefill Facility, Kingsland Facility, Suncook Facility, Burnsville Facility and Flying Cloud Facility; "TRAFALGAR" means Trafalgar Power, Inc., a Delaware corporation; "TRAFALGAR CLASS B NOTE" means the 6.10% secured, subordinated note due December 31, 2010 jointly and severally of the Trafalgar Companies; "TRAFALGAR COMPANIES" means Trafalgar and Christine Falls Corporation, a New York corporation; "TRAFALGAR CONTINGENCY PARTICIPATION" means the contingent management fee paid to the operator of the Trafalgar Facilities pursuant to the Trafalgar Operations Contract and the Trafalgar Indenture; "TRAFALGAR FACILITIES" means the following hydroelectric generating facilities: Ogdensburg, Forestport, Herkimer, Christine Falls, Cranberry Lake, Kayuta Lake and Adams, which are owned by the Trafalgar Companies; "TRAFALGAR INDENTURE" means the collateral trust indenture between the Trafalgar Companies and a security trustee dated July 1, 1988, as amended and restated on January 15, 1996, which governs the terms of the Trafalgar Class B Note, among other things; "TRAFALGAR OPERATING CASHFLOW" means the cash flows generated from the operation of the Trafalgar Facilities after payment of direct operating costs, including, without limitation, property taxes, supplies and consumables and amounts due to Algonquin Power under the Trafalgar Operations Contract, prior to deduction of amounts payable in respect of the Trafalgar Contingency Participation; "TRAFALGAR OPERATIONS CONTRACT" means the agreement dated January 15, 1996 between Algonquin Power and the Trafalgar Companies, pursuant to which Algonquin Power provides operations and management services for the Trafalgar Facilities; "TRAFALGAR OPERATIONS SUBCONTRACT" means the agreement dated December 23, 1997 between Algonquin Power and Algonquin Canada, pursuant to which Algonquin Canada provides those services -14- to be provided by Algonquin Power in connection with the operation of the Trafalgar Facilities under the Trafalgar Operations Contract; "TRUST INDENTURE" means the trust indenture dated as of July 20, 2004 between the Fund and the Debenture Trustee; "TRUST UNITS" or "UNITS" means units of the Fund, each unit representing an equal undivided beneficial interest in the Fund; "TRUSTEE" means a trustee of the Fund from time to time; "TSX" means the Toronto Stock Exchange; "UNITHOLDERS" means the holders of Trust Units from time to time; "VALLEY POWER FACILITY" (formerly Drayton Valley) means the 12 MW biomass-fired generating facility located in the Town of Drayton Valley, Alberta and which is owned by Valley Power LP, a limited partnership of which Algonquin Power Operating Trust owns 49.9995% of the limited partnership interests and Algonquin Power Trust indirectly holds 50% of the general partnership interests; "WASTEWATER TREATMENT DEVELOPMENTS" means the Black Mountain Facility, Gold Canyon Facility, Tall Timbers Facility, Bella Vista Facility, Woodmark Facility, Litchfield Facility, Fox River Facility, Holiday Hills Facility, Timber Creek Facility, Ozark Mountains Facility, Holly Ranch Facility, Big Eddy Facility, Piney Shores Facility, Hill Country Facility and the Rio Rico Facility; "WESTERN CANADA DEVELOPMENT" means the Dickson Dam Facility and the Valley Power Facility; "WINDSOR LOCKS FACILITY" means the 56 MW (gross) combined cycle, gas-fired co-generation facility located at Windsor Locks, Connecticut and which is owned by Algonquin Windsor Locks LLC, a Connecticut limited liability company, wholly-owned by Algonquin America; "WOODMARK FACILITY" means the wastewater treatment facility located in Tyler, Texas and which is owned by Woodmark Utility Company, Inc., a Texas corporation which is wholly-owned by AWRA; and "WORCESTER FACILITY" means the 180 kilowatt hydroelectric generating facility located on the North Branch of Winnooskie River, in the Town of Worcester, Vermont and which is owned by Worcester Hydro Company, Inc., a Vermont corporation which is indirectly wholly-owned by Algonquin America. Words importing the singular number only include the plural and vice versa and words importing any gender include all genders. All dollar amounts are in Canadian dollars unless otherwise stated. For the purposes of this annual information form, any reference to any direct or indirect subsidiary, associate or affiliate of the Fund or any entity in which the Fund holds, directly or indirectly, a majority of the equity interests, the word "control", the word "wholly-owned" and similar expressions, shall be construed without reference to any holdings by the Manager of special voting shares entitling the Manager to elect directors of Algonquin Canada or Algonquin America. SCHEDULE B ALGONQUIN POWER INCOME FUND AUDIT COMMITTEE CHARTER By appropriate resolution of the Trustees of Algonquin Power Income Fund (the "TRUSTEES"), the Audit Committee (the "COMMITTEE") has been established as a standing committee of the Trustees with the terms of reference set forth below. At the time of its establishment, the Committee is comprised of all the Trustees. Unless the context requires otherwise, the term "FUND" refers to Algonquin Power Income Fund and its subsidiaries. 1. PURPOSE 1.1 The Committee's purpose is to: (a) assist the Trustees' oversight of: (i) the integrity of the Fund's financial statements, Management's Discussion and Analysis of Operating Performance ("MD&A") and other financial reporting; (ii) the Fund's compliance with legal and regulatory requirements; (iii) the external auditor's qualifications, independence and performance; (iv) the performance of the Fund's internal audit function and internal auditor; (v) the communication among Algonquin Power Management Inc. (the "MANAGER"), management of the Fund's subsidiary entities and the Fund's Chief Financial Officer (collectively, "MANAGEMENT"), the external auditor, the internal auditor and the Trustees; (vi) the review and approval of any related party transactions; and (vii) any other matters as defined by the Trustees; (b) prepare and/or approve any report that is required by law or regulation to be included in any of the Fund's public disclosure documents relating to the Committee. 2. COMMITTEE MEMBERSHIP 2.1 Number of Members - The Committee shall consist of not fewer than three members. 2.2 Independence of Members - Each member of the Committee shall: (a) be a Trustee of the Fund; (b) not be an officer or employee of any of the Fund's subsidiary entities or the Manager or any of their respective affiliates; (c) be an unrelated director for the purposes of the Toronto Stock Exchange (the "TSX") Corporate Governance Policy; and -2- (d) satisfy the independence requirements applicable to members of audit committees under each of the rules of Multilateral Instrument 52-110 -Audit Committees of the Canadian Securities Administrators ("MI 52-110") and other applicable laws and regulations. 2.3 Financial Literacy - Each member of the Committee shall satisfy the financial literacy requirements applicable to members of audit committees under the TSX Corporate Governance Policy, MI 52-110 and other applicable laws and regulations. 2.4 Accounting or Related Financial Experience - At least one member of the Committee shall satisfy the financial expertise and experience requirements under the TSX Corporate Governance Policy and be an audit committee financial expert within the meaning of MI 52-110 and other applicable laws and regulations. 2.5 Annual Appointment of Members - The Committee and its Chair shall be appointed annually by the Trustees and each member of the Committee shall serve at the pleasure of the Trustees until he or she resigns, is removed or ceases to be a Trustee. 3. COMMITTEE MEETINGS 3.1 Time and Place of Meetings - The time and place of the meetings of the Committee and the calling of meetings and the procedure in all things at such meetings shall be determined by the Committee; provided, however, that the Committee shall meet at least quarterly, a majority of the members of the Committee shall constitute a quorum and the Committee shall maintain minutes or other records of its meetings and activities. 3.2 In Camera Meetings - As part of each meeting of the Committee at which it approves, or if applicable, recommends that the Trustees approve, the annual audited financial statements of the Fund or at which the Committee reviews the interim financial statements of the Fund, and at such other times as the Committee deems appropriate, the Committee shall meet separately with each of the persons set forth below to discuss and review specific issues as appropriate: (a) representatives of Management; (b) the external auditor; and (c) the internal audit personnel. 4. COMMITTEE AUTHORITY AND RESOURCES 4.1 Direct Channels of Communication - The Committee shall have direct channels of communication with the Fund's internal and external auditors to discuss and review specific issues as appropriate. 4.2 Retaining and Compensating Advisors - The Committee, or any member of the Committee with the approval of the Committee, may retain at the expense of the Fund such independent legal, accounting (other than the external auditor) or other advisors on such terms as the Committee may consider appropriate and shall not be required to obtain any other approval in order to retain or compensate any such advisors. -3- 4.3 Funding - The Fund shall provide for appropriate funding, as determined by the Committee, for payment of compensation of the external auditor and any advisor retained by the Committee under Section 4.2 of this Charter. 4.4 Investigations - The Committee shall have unrestricted access to the Fund's Chief Financial Officer and personnel of the Manager and the Fund's subsidiary entities and documents and shall be provided with the resources necessary to carry out its responsibilities. 5. REMUNERATION OF COMMITTEE MEMBERS 5.1 Director Fees Only - No member of the Committee may accept, directly or indirectly, fees from the Fund or any of its subsidiary entities other than remuneration for acting as a Trustee or member of the Committee or any other committee of the Trustees. 5.2 Other Payments - For greater certainty, no member of the Committee shall accept any consulting, advisory or other compensatory fee from the Fund. For purposes of Section 5.1, the indirect acceptance by a member of the Committee of any fee includes acceptance of a fee by an immediate family member or a partner, member or executive officer of, or a person who occupies a similar position with, an entity that provides accounting, consulting, legal, investment banking or financial advisory services to the Fund or any of its subsidiaries, other than limited partners, non-managing members and those occupying similar positions who, in each case, have no active role in providing services to the entity. 6. DUTIES AND RESPONSIBILITIES OF THE COMMITTEE 6.1 Overview - The Committee's principal responsibility is one of oversight. Management is responsible for preparing the Fund's financial statements and the external auditor is responsible for auditing those financial statements. The Committee's specific duties and responsibilities are as follows: (a) Financial and Related Information - (i) Annual Financial Statements - The Committee shall review and discuss with Management and the external auditor the Fund's annual financial statements and related MD&A and if applicable, report thereon to the Trustees as a whole before they approve such statements and MD&A. (ii) Interim Financial Statements - The Committee shall review and discuss with Management and the external auditor the Fund's interim financial statements and related MD&A and if applicable, report thereon to the Trustees as a whole before they approve such statements and MD&A. (iii) Prospectuses and Other Documents - The Committee shall review and discuss with Management and the external auditor the financial information, financial statements and related MD&A appearing in any prospectus, annual report, annual information form, management information circular or any other public disclosure document prior to its public release or filing and if applicable, report thereon to the Trustees as a whole. -4- (iv) Accounting Treatment - Prior to the completion of the annual external audit, and at any other time deemed advisable by the Committee, the Committee shall review and discuss with Management and the external auditor (and shall arrange for the documentation of such discussions in a manner it deems appropriate) the quality and not just the acceptability of the Fund's accounting principles and financial statement presentation, including, without limitation, the following: (A) all critical accounting policies and practices to be used, including, without limitation, the reasons why certain estimates or policies are or are not considered critical and how current and anticipated future events impact those determinations and an assessment of Management's disclosures along with any significant proposed modifications by the auditors that were not included; (B) all alternative treatments within generally accepted accounting principles for policies and practices related to material items that have been discussed with Management, including, without limitation, ramification of the use of such alternative disclosure and treatments, and the treatment preferred by the external auditor, which discussion should address recognition, measurement and disclosure consideration related to the accounting for specific transactions as well as general accounting policies. Communications regarding specific transactions should identify the underlying facts, financial statement accounts impacted and applicability of existing corporate accounting policies to the transaction. Communications regarding general accounting policies should focus on the initial selection of, and changes in, significant accounting policies, the impact of the Management's judgments and accounting estimates and the external auditor's judgments about the quality of the Fund's accounting principles. Communications regarding specific transactions and general accounting policies should include the range of alternatives available under generally accepted accounting principles discussed by Management and the auditors and the reasons for selecting the chosen treatment or policy. If the external auditor's preferred accounting treatment or accounting policy is not selected, the reasons therefore should also be reported to the Committee; (C) other material written communications between the external auditor and Management, such as any management letter, schedule of unadjusted differences, listing of adjustments and reclassifications not recorded, management representation letter, report on observations and recommendations on internal controls, engagement letter and independence letter; (D) major issues regarding financial statement presentations; (E) any significant changes in the Fund's selection or application of accounting principles; (F) the effect of regulatory and accounting initiatives, as well as off-balance sheet structures, on the financial statements of the Fund; and -5- (G) the adequacy of the Fund's internal controls and any special audit steps adopted in light of control deficiencies. (v) Disclosure of Other Financial Information - The Committee shall: (A) review, and discuss generally with Management, the type and presentation of information to be included in, all public disclosure by the Fund containing audited, unaudited or forward-looking financial information in advance of its public release by the Fund, including, without limitation, earnings guidance and financial information based on unreleased financial statements; (B) discuss generally with Management the type and presentation of information to be included in earnings and any other financial information given to analysts and rating agencies, if any; and (C) satisfy itself that adequate procedures are in place for the review of the Fund's disclosure of financial information extracted or derived from the Fund's financial statements, other than the Fund's financial statements, MD&A and earnings press releases, and shall periodically assess the adequacy of those procedures. (b) External Auditor - (i) Authority with Respect to External Auditor - As representative of the Fund's unitholders and as a committee of the Trustees, the Committee shall be directly responsible for the appointment, compensation, retention, termination and oversight of the work of the external auditor (including, without limitation, resolution of disagreements between Management and the auditor regarding financial reporting) for the purpose of preparing or issuing an audit report or performing other audit, review or attest services for the Fund. In this capacity, the Committee shall have sole authority for recommending the person to be proposed to the Fund's unitholders for appointment as external auditor, whether at any time the incumbent external auditor should be removed from office, and the compensation of the external auditor. The Committee shall require the external auditor to confirm in an engagement letter to the Committee each year that the external auditor is accountable to the Trustees and the Committee as representatives of unitholders and that it will report directly to the Committee. (ii) Approval of Audit Plan - The Committee shall approve, prior to the external auditor's audit, the external auditor's audit plan (including, without limitation, staffing), the scope of the external auditor's review and all related fees. (iii) Independence - The Committee shall satisfy itself as to the independence of the external auditor. As part of this process: (A) The Committee shall require the external auditor to submit on a periodic basis to the Committee a formal written statement confirming its independence under applicable laws and regulations and delineating all relationships between the auditor and the Fund and the Committee shall actively engage in a dialogue with the external auditor with respect to -6- any disclosed relationships or services that may impact the objectivity and independence of the external auditor and take, or, if applicable, recommend that the Trustees take, any action the Committee considers appropriate in response to such report to satisfy itself of the external auditor's independence. (B) In accordance with applicable laws and regulations, the Committee shall pre-approve any non-audit services (including, without limitation, fees therefore) provided to the Fund or its subsidiaries by the external auditor or any auditor of any such subsidiary and shall consider whether these services are compatible with the external auditor's independence, including, without limitation, the nature and scope of the specific non-audit services to be performed and whether the audit process would require the external auditor to review any advice rendered by the external auditor in connection with the provision of non-audit services. The Chair may approve additional non-audit services that arise between Committee meetings, provided that the Chair reports any such approvals to the Committee at the next scheduled meeting. (C) The Committee shall establish a policy setting out the restrictions on the Fund's subsidiary entities hiring employees and former employees of the Fund's external auditor or former external auditor. (iv) Rotating of Auditor Partner - The Committee shall evaluate the performance of the external auditor and whether it is appropriate to adopt a policy of rotating lead or responsible partners of the external auditors. (v) Review of Audit Problems and Internal Audit - The Committee shall review with the external auditor: (A) any problems or difficulties the external auditor may have encountered, including, without limitation, any restrictions on the scope of activities or access to required information, and any disagreements with Management and any management letter provided by the auditor and the Fund's response to that letter; (B) any changes required in the planned scope of the internal audit; and (C) the internal audit department's responsibilities, budget and staffing. (vi) Review of Proposed Audit and Accounting Changes - The Committee shall review major changes to the Fund's auditing and accounting principles and practices suggested by the external auditor. (vii) Regulatory Matters - The Committee shall discuss with the external auditor the matters required to be discussed by Section 5741 of the CICA Handbook - Assurance relating to the conduct of the audit. (c) Internal Audit Function - Controls - -7- (i) Regular Reporting - Internal audit personnel shall report regularly to the Committee. (ii) Oversight of Internal Controls - The Committee shall oversee Management's design and implementation of and reporting on the Fund's internal controls and review the adequacy and effectiveness of Management's financial information systems and internal controls. The Committee shall periodically review and approve the mandate, plan, budget and staffing of internal audit personnel. The Committee shall direct Management to make any changes it deems devisable in respect of the internal audit function. (iii) Review of Audit Problems - The Committee shall review with the internal audit personnel: any problem or difficulties the internal audit personnel may have encountered, including, without limitation, any restrictions on the scope of activities or access to required information, and any significant reports to Management prepared by the internal audit personnel and Management's responses thereto. (iv) Review of Internal Audit Personnel - The Committee shall review the appointment, performance and replacement of the senior internal auditing personnel and the activities, organization structure and qualifications of the persons responsible for the internal audit function. (d) Risk Assessment and Risk Management - (i) Risk Exposure - The Committee shall discuss with the external auditor, internal audit personnel and Management periodically the Fund's major financial risk exposures and the steps Management has taken to monitor and control such exposures. (ii) Investment Practices - The Committee shall review Management's plans and strategies around investment practices, banking performance and treasury risk management. (iii) Compliance with Covenants - The Committee shall review Management's procedures to ensure compliance by the Fund with its loan covenants and restrictions, if any. (e) Legal Compliance - (i) On at least a quarterly basis, the Committee shall review with the Fund's legal counsel, external auditor and Management any legal matters (including, without limitation, litigation, regulatory investigations and inquiries, changes to applicable laws and regulations, complaints or published reports) that could have a significant impact on the Fund's financial position, operating results or financial statements and the Fund's compliance with applicable laws and regulations. (ii) The Committee shall review and, if applicable, advise the Trustees with respect to the Fund's policies and procedures regarding compliance with applicable laws and regulations and shall notify Management and, if applicable, the Trustees, -8- promptly after becoming aware of any material non-compliance by the Fund with applicable laws and regulations. (f) Whistle Blowing - The Committee shall establish procedures for: (i) the receipt, retention and treatment of complaints received by the Fund regarding accounting, internal accounting controls or auditing matters; and (ii) the confidential, anonymous submission by employees of the Fund's subsidiary entities of concerns regarding questionable accounting or auditing matters. (g) Related Party Transactions - The Committee shall review and approve any transaction between the Fund and a related party and any transaction involving the Fund and another party in which the parties' relationship could enable the negotiation of terms on other than an independent, arms' length basis. (h) Review of the Management's Certifications and Reports - The Committee shall review and discuss with Management all certifications of financial information, management reports on internal controls and all other management certifications and reports relating to the Fund's financial position or operations required to be filed or released under applicable laws and regulations prior to the filing or release of such certifications or reports. (i) Liaison - The Committee shall review and ensure that appropriate liaison and co-operation exist between the external auditor and internal audit personnel and provide a direct channel of communication between external and internal auditors and the Committee. (j) Public Reports - The Committee shall prepare and/or approve any report that is required by law or regulation to be included in any of the Fund's public disclosure documents relating to the Committee. (k) Other Matters - The Committee may, in addition to the foregoing, perform such other functions as may be necessary or appropriate for the performance of its oversight function. 7. REPORTING TO THE TRUSTEES 7.1 Regular Reporting - If applicable, the Committee shall report to the Trustees following each meeting of the Committee and at such other times as the Committee may determine to be appropriate. 8. EVALUATION OF COMMITTEE PERFORMANCE 8.1 Performance Review - The Committee shall periodically assess its performance. 8.2 Amendments to Charter - (a) Review by Committee - On at least an annual basis, the Committee shall review and discuss the adequacy of this Charter and if applicable, recommend any proposed changes to the Trustees. -9- (b) Review by Trustees - The Trustees will review and reassess the adequacy of the Charter on an annual basis and at such other times, as it considers appropriate. 9. LEGISLATIVE AND REGULATORY CHANGES 9.1 Compliance - It is the Trustees' intention that this mandate shall reflect at all times all legislative and regulatory requirements applicable to the Committee. Accordingly, this Charter shall be deemed to have been updated to reflect any amendments to such legislative and regulatory requirements and shall be formally amended at least annually to reflect such amendments. 9.2 Rules Not Yet in Force - As of the date of this Charter, MI 52-110 and certain guidelines of the TSX applicable to audit committees were not yet in force. The Committee shall comply with such draft instruments as if they were in force. 10. CURRENCY OF CHARTER 10.1 Currency of Charter - This Charter was approved by the Trustees on May 11, 2004.
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F-8 Filing
Algonquin Power & Utilities (AQN) F-8Registration of securities, to be issued in exchange offers or a business combination
Filed: 26 Mar 07, 12:00am