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-



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                           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;



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     (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.