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Algonquin Power & Utilities Corp. – ‘F-8’ on 3/26/07 – ‘EX-3.12’

On: Monday, 3/26/07, at 3:18pm ET · Effective: 3/26/07 · Accession #: 950136-7-1878 · File #: 333-141569

  As Of                Filer                Filing    For·On·As Docs:Size              Issuer               Agent

 3/26/07  Algonquin Power & Utilities Corp. F-8         3/26/07   27:4.1M                                   Capital Systems 01/FA

Registration Statement by a Foreign Private Issuer for Securities Offered Pursuant to a Transaction — Form F-8
Filing Table of Contents

Document/Exhibit                   Description                      Pages   Size 

 1: F-8         Registration Statement by a Foreign Private Issuer  HTML   1.33M 
                          for Securities Offered Pursuant to a                   
                          Transaction                                            
 2: EX-2.1      Support Agreement                                   HTML    109K 
 3: EX-3.1      Annual Information Form                             HTML    577K 
12: EX-3.10     Short Form Prospectus                               HTML    127K 
13: EX-3.11     Amended & Restated Short Form Prospectus            HTML    169K 
14: EX-3.12     Annual Information Form 3/31/2006                   HTML    431K 
15: EX-3.13     Management's Responsibility for Financial Reprting  HTML    144K 
16: EX-3.14     Consolidated Balance Sheet                          HTML    110K 
17: EX-3.15     Ltr to Clean Power Unitholders & Debentureholders   HTML     21K 
 4: EX-3.2      Auditors' Report                                    HTML     94K 
 5: EX-3.3      Management's Discussion & Analysis 2005             HTML     91K 
 6: EX-3.4      Financial Statements Q3                             HTML     58K 
 7: EX-3.5      Management's Discussion & Analysis Q3               HTML     78K 
 8: EX-3.6      Material Change Report Dated 5/11/2006              HTML     23K 
 9: EX-3.7      Material Change Report Dated 6/30/2006              HTML     18K 
10: EX-3.8      Material Change Report Dated 2/25/2007              HTML     41K 
11: EX-3.9      Management Information Circular                     HTML     72K 
18: EX-4.1      Consent of Blake Cassels & Graydon LLP              HTML     11K 
19: EX-4.2      Kpmg LLP Consent                                    HTML     12K 
20: EX-4.3      Consent of Ernst & Young                            HTML     12K 
21: EX-5.2      Certificate                                         HTML     18K 
22: EX-5.3      Certificate                                         HTML     21K 
23: EX-5.4      Certificate                                         HTML     16K 
24: EX-99.6.1   Amended & Restated Declaration of Trust 5/26/2004   HTML    211K 
25: EX-99.6.2   Schedule A Extraordinary Resolution                 HTML     11K 
26: EX-99.6.3   Trust Indenture                                     HTML    442K 
27: EX-99.6.4   Supplemental Trust Indenture                        HTML     84K

EX-3.12 — Annual Information Form 3/31/2006
Exhibit Table of Contents

Page	(sequential)	(alphabetic)	↑Top
		Alternative Formats (Word, et al.) Acquisition and Investment Strategy Acquisition of the Waterpower Facilities Additional Information Administration Agreement, The Administrator and Manager, The Alberta Amendments to the Fund Trust Indenture Appendix A Audit Committee Audit Committee Terms of Reference Auditors, Registrar and Transfer Agent Big Spring Biomass Biomass Facilities, The Book Entry Form and Depository Service Canada Cash Distributions Certain Restrictions on Trustee's Powers Chandler Clean Power Clean Power Income Fund Clean Power Limited Partnership Clean Power Operating Trust Commodity Prices Conflicts Construction Risk CPOT Trustees Currency of Information Delays in Distributions Dependence upon CPOT Dependence Upon Key Customers Description of CPLP Description of Cpot Description of the Business Description of the Fund Distributable Cash Distribution Policy Distributions Diversified Asset Base Environmental Choice(M) Program, The Equipment Failure ERC Participation Strategy Exchange Rates Facilities, The Foote Creek Ii Foote Creek Iii Foote Creek Iv Forward-Looking Statements Gas Purchase Agreements Gas Sale Agreements General General Development of the Business General Economic Conditions General Partner Industry Overview Information and Reports Interest of Experts Interest of Management and Others in Material Transactions Investment in the Chapais Facility Investments in the U.S. Windpower Facilities Investments, The Issuance of Trust Units Issuance of Trust Units and 6.75 percent Convertible Unsecured Subordinated Debentures Issuer Rating Labour Relations Landfill Gas Landfill Gas Facilities Landfill Gas Facilities in Illinois Legal Proceedings Limitation on Non-Resident Ownership Loan Default Management Agreement, The Market for Securities Meetings of Unitholders Names, residences and principal occupations of directors and officers of the Administrator of the Fund and Administrator/Manager of CPOT Nature of Trust Units Officers of CPOT Ontario Operating Strategy Partnership Units Payments of Distributions Peet U.S Peetz Table Power Purchase Agreements Rating of Trust Units Ratings Redemption at the Option of Unitholders Redemption Right Regulatory Regime and Permits Reliance on the Administrator/Manager and the Operators and Potential Conflicts of Interest Repurchase of Trust Units Reserve Account Resource Availability and Constancy Restrictions on CPOT Trustees' Powers Restrictions on Redemptions Risk Factors Special Committee Structure of the Fund Take-over Bids Tax Related Risks Term of the Fund The Administration Agreement The Administrator and Manager The Biomass Facilities The Environmental Choice(M) Program The Facilities The Investments The Management Agreement Transfer of Trust Units Trustee Trustee of the Fund Trustees/Governance Trustees of the Fund and of Cpot Trust Units Unit Certificates Unitholder Value Enhancement Process U.S. Windpower Facilities Waterpower Waterpower Facilities Weather Wind
1	1st Page – Filing Submission
2	Clean Power Income Fund
5	Forward-Looking Statements
6	Currency of Information
"	Clean Power Operating Trust
7	Clean Power Limited Partnership
"	Structure of the Fund
9	General Development of the Business
"	Special Committee
"	Issuance of Trust Units and 6.75 percent Convertible Unsecured Subordinated Debentures
13	Diversified Asset Base
"	The Investments
14	Investments in the U.S. Windpower Facilities
15	Acquisition of the Waterpower Facilities
"	Investment in the Chapais Facility
17	Peet U.S
"	Operating Strategy
18	Acquisition and Investment Strategy
"	ERC Participation Strategy
19	Description of the Business
"	The Facilities
"	U.S. Windpower Facilities
"	Foote Creek Ii
20	Foote Creek Iii
"	Foote Creek Iv
21	Peetz Table
22	Big Spring
23	Chandler
"	Waterpower Facilities
31	The Biomass Facilities
35	Landfill Gas Facilities
"	Power Purchase Agreements
36	Gas Sale Agreements
37	Gas Purchase Agreements
38	Landfill Gas Facilities in Illinois
"	Industry Overview
39	Canada
"	Alberta
40	Ontario
42	Clean Power
43	The Environmental Choice(M) Program
44	Wind
45	Waterpower
46	Biomass
"	Landfill Gas
48	Distribution Policy
"	Market for Securities
49	Ratings
"	Rating of Trust Units
50	Issuer Rating
"	Trustees of the Fund and of Cpot
"	Trustee of the Fund
"	CPOT Trustees
51	Audit Committee
52	Officers of CPOT
"	The Administrator and Manager
"	The Administration Agreement
53	The Management Agreement
55	Names, residences and principal occupations of directors and officers of the Administrator of the Fund and Administrator/Manager of CPOT
56	Description of the Fund
"	General
"	Trustee
57	Certain Restrictions on Trustee's Powers
58	Trust Units
"	Issuance of Trust Units
"	Cash Distributions
"	Redemption at the Option of Unitholders
59	Repurchase of Trust Units
"	Book Entry Form and Depository Service
60	Transfer of Trust Units
"	Payments of Distributions
"	Meetings of Unitholders
61	Limitation on Non-Resident Ownership
"	Amendments to the Fund Trust Indenture
"	Term of the Fund
"	Take-over Bids
"	Information and Reports
62	Description of Cpot
"	Trustees/Governance
63	Restrictions on CPOT Trustees' Powers
"	Redemption Right
64	Distributions
"	Unit Certificates
"	Conflicts
65	Description of CPLP
"	General Partner
"	Partnership Units
"	Risk Factors
"	Dependence upon CPOT
66	Unitholder Value Enhancement Process
"	Tax Related Risks
"	Resource Availability and Constancy
"	Legal Proceedings
"	Construction Risk
67	Dependence Upon Key Customers
"	Loan Default
"	Exchange Rates
68	Regulatory Regime and Permits
69	Labour Relations
"	Reliance on the Administrator/Manager and the Operators and Potential Conflicts of Interest
"	Delays in Distributions
"	Nature of Trust Units
"	Restrictions on Redemptions
"	Equipment Failure
70	Commodity Prices
"	Reserve Account
"	Weather
"	General Economic Conditions
"	Distributable Cash
"	Interest of Management and Others in Material Transactions
71	Auditors, Registrar and Transfer Agent
"	Interest of Experts
"	Additional Information
76	Appendix A
"	Audit Committee Terms of Reference

This Exhibit is an HTML Document rendered as filed. [ Alternative Formats ]

EX-3.12	1st Page of 80	TOC	↑Top	Previous	Next	↓Bottom	Just 1st


EX-3.12 2nd Page of 80 TOC 1st Previous Next ↓Bottom Just 2nd
                                      Clean          ENVIRONMENTAL CHOICE
                         [LOGO]       Power                 [LOGO]
                                   Income Fund       CHOIX ENVIRONMENTAL

                             CLEAN POWER INCOME FUND

                             ANNUAL INFORMATION FORM

                                  MARCH 31, 2006

EX-3.12 3rd Page of 80 TOC 1st Previous Next ↓Bottom Just 3rd
                                TABLE OF CONTENTS

FORWARD-LOOKING STATEMENTS ....................................................1
CURRENCY OF INFORMATION .......................................................2
CLEAN POWER INCOME FUND .......................................................2
  Clean Power Income Fund .....................................................2
  Clean Power Operating Trust .................................................2
  Clean Power Limited Partnership .............................................3
  Structure of the Fund .......................................................3
GENERAL DEVELOPMENT OF THE BUSINESS ...........................................5
  Special Committee....................., .....................................5
  Issuance of Trust Units and 6.75 percent Convertible Unsecured
  Subordinated Debentures .....................................................5
  Diversified Asset Base ......................................................9
  The Investments .............................................................9
  Operating Strategy .........................................................13
  Acquisition and Investment Strategy ........................................14
  ERC Participation Strategy .................................................14
DESCRIPTION OF THE BUSINESS ..................................................15
  The Facilities .............................................................15
  Industry Overview ..........................................................34
  Wind .......................................................................40
  Waterpower .................................................................41
  Biomass ....................................................................42
  Landfill Gas ...............................................................42
DISTRIBUTION POLICY ..........................................................44
MARKET FOR SECURITIES ........................................................44
RATINGS ......................................................................45
  Rating of Trust Units ......................................................45
  Issuer Rating ..............................................................46
TRUSTEES OF THE FUND AND OF CPOT .............................................46
  Trustee of the Fund ........................................................46
  CPOT Trustees ..............................................................46
  Audit Committee ............................................................47
  Officers of CPOT ...........................................................48
THE ADMINISTRATOR AND MANAGER ................................................48
  The Administration Agreement ...............................................48
  The Management Agreement ...................................................49
  Names, residences and principal occupations of directors and officers
  of the Administrator of the Fund and Administrator/Manager of CPOT .........51
  Conflicts oflnterest .......................................................51
DESCRIPTION OF THE FUND ......................................................52
  General ....................................................................52
  Trustee ....................................................................52
  Certain Restrictions on Trustee's Powers ...................................53
  Trust Units ................................................................54
  Issuance of Trust Units ....................................................54
  Cash Distributions .........................................................54
  Redemption at the Option of Unitholders ....................................54
  Repurchase of Trust Units ..................................................55
  Book Entry Form and Depository Service .....................................55
  Transfer of Trust Units ....................................................56
  Payments of Distributions ..................................................56
  Meetings of Unitholders ....................................................56
  Limitation on Non-Resident Ownership .......................................57
  Amendments to the Fund Trust Indenture .....................................57

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  Term of the Fund ...........................................................57
  Take-over Bids .............................................................57
  Information and Reports ....................................................57
DESCRIPTION OF CPOT ..........................................................58
  General ....................................................................58
  Trustees/Governance ........................................................58
  Restrictions on CPOT Trustees' Powers ......................................59
  Redemption Right, ..........................................................59
  Distributions ..............................................................60
  Unit Certificates ..........................................................60
  Meetings of Unitholders ....................................................60
  Conflicts ..................................................................60
DESCRIPTION OF CPLP ..........................................................61
  General ....................................................................61
  General Partner ............................................................61
  Partnership Units ..........................................................61
RISK FACTORS .................................................................61
  Dependence upon CPOT .......................................................61
  Unitholder Value Enhancement Process .......................................62
  Tax Related Risks ..........................................................62
  Resource Availability and Constancy ........................................62
  Legal Proceedings ..........................................................62
  Construction Risk ..........................................................62
  Dependence Upon Key Customers ..............................................63
  Loan Default ...............................................................63
  Exchange Rates .............................................................63
  Regulatory Regime and Permits ..............................................64
  Labour Relations ...........................................................65
  Reliance on the Administrator/Manager and the Operators and Potential
  Conflicts of Interest ......................................................65
  Delays in Distributions ....................................................65
  Nature of Trust Units ......................................................65
  Restrictions on Redemptions ................................................65
  Equipment Failure ..........................................................65
  Commodity Prices ...........................................................66
  Reserve Account ............................................................66
  Weather ....................................................................66
  General Economic Conditions ................................................66
DISTRIBUTABLE CASH ...........................................................66
INTEREST OF MANAGEMENT AND OTHERS IN MATERIAL TRANSACTIONS ...................66
AUDITORS, REGISTRAR AND TRANSFER AGENT .......................................67
INTEREST OF EXPERTS ..........................................................67
ADDITIONAL INFORMATION .......................................................67
APPENDIX A -- AUDIT COMMITTEE TERMS OF REFERENCE .............................72

                                     - ii -

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                           FORWARD-LOOKING STATEMENTS

      This Annual Information Form may contain forward-looking information or
forward-looking statements within the meaning of applicable securities
legislation ("forward-looking statements"). Any statements that express or
involve discussions with respect to the Fund's predictions, expectations,
beliefs, plans, projections, objectives, assumptions, potentials, estimates,
intentions, future events or performance (often, but not always, using words or
phrases such as "believes", "expects" or "does not expect", "is expected",
"anticipates" or "does not anticipate", or "intends" or stating that certain
actions, events or results "may", "could", "would", "might" or "will" be taken
or achieved) are not statements of historical fact, but are forward-looking
statements. Such forward-looking statements, by their nature, necessarily
involve known and unknown risks, assumptions, uncertainties and other factors
beyond the Fund's ability to control or predict, that may cause our actual
results, performance or achievements, or developments in our business or in our
industry, to differ materialiy from the anticipated results, performance,
achievements or developments expressed or implied by such forward-looking
statements.

      Forward-looking statements may include, but are not limited to: the Fund's
operating and financial results, capital expenditures, distribution policy and
the ability to execute on its operating, investing and financing strategies,
with respect to the Fund, and entities and assets which it owns or has an
interest in, directly or indirectly; the expected commercial operation date for
the Erie Shores Wind Farm; and the Administrator/Manager's belief that
independent power producers will play an increasingly important role in the
supply of electricity needs in the future, that there will be an increase in the
opportunity for energy consumers to purchase electricity produced from a
particular source and that clean power projects will continue to be developed
with long term power purchase agreements.

      As described in detail below under the heading "Risk Factors", investors
and others should not place undue reliance on these forward-looking statements
as actual results could differ materially from the forward-looking statements in
this Annual Information Form for various reasons, including: the Fund's
dependence on the operations and assets of CPOT's facilities, the unitholder
value enhancement process; tax related risks; availability and constancy of
water flows, wind, biomass and methane; legal proceedings; construction risk;
dependence on key customers; default on loans to third parties; exchange rates;
regulatory risks; labour relations; reliance on Clean Power Inc. (the
"Administrator/Manager") and the operators and potential conflicts of interest;
delays in distributions; nature of the Fund's units; restrictions on
redemptions; equipment failure; commodity prices; sufficiency of the reserve
account; weather; and general economic conditions. The foregoing list of risks
is not exhaustive.

      The forward-looking statements in this Annual Information Form are based
on the material factors and assumptions that the Fund and the
Administrator/Manager considered reasonable at the time they were prepared
including that the construction schedule for the Erie Shores Wind Farm is not
delayed due to weather, natural disasters, labour problems or other matters not
in the control of or foreseeable by the Fund; that independent power producers
will play an increasingly important role in the supply of electricity needs
because they provide cost effective power generation through the efficient and
environmentally responsible development of energy resources; that markets for
electricity will continue to develop both at the institutional and retail
segments of the market; that clean power projects will continue to be developed
with long term power purchase agreements due to the ability of clean power
projects to offer stable, long-term contract prices, continued desire of
purchasers to secure long-term credits from the use of renewable energy and the
continuation of public policy adopted in North America to encourage the
development of clean power.

      It is important to note that:

            o     Unless otherwise indicated, forward-looking statements in this
                  Annual Information Form describe our views and expectations as
                  of March 31, 2006.

            o     We caution readers not to place undue reliance on these
                  statements as our actual results may differ materially from
                  our expectations if known and unknown risks or uncertainties
                  affect our business, or if our estimates or assumptions prove
                  inaccurate. Therefore, we cannot provide any assurance that
                  forward-looking statements will materialize.

            o     While it is anticipated that subsequent events and
                  developments could cause our views and expectations to change,
                  neither the Fund nor the Administrator/Manager undertakes or
                  assumes any obligation to publicly update or revise any
                  forward-looking statement, whether as a result of new
                  information, future events or any other reason.

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            o     All forward-looking statements contained in this Annual
                  Information Form are expressly qualified by this cautionary
                  statement.

                             CURRENCY OF INFORMATION

      The information set out in this annual information form is stated as at
December 31, 2005 unless otherwise indicated.

                             CLEAN POWER INCOME FUND

CLEAN POWER INCOME FUND

      The Fund is an unincorporated open-ended trust established under the laws
of Ontario pursuant to the Fund Trust Indenture. The Fund has invested in 44
power-generating facilities which use environmentally preferred energy sources.
These investments consist of: (i) six waterpower facilities that are operated
and managed by Regional Power, a subsidiary of Manulife Financial Corporation;
(ii) the Whitecourt Facility, a biomass facility that is operated and managed by
Probyn Whitecourt Management Inc., an affiliate of the Administrator/Manager;
(iii) loans to certain subsidiaries of Caithness Western Wind Holdings, LLC that
own six windpower facilities, three of which are operated and managed by
SeaWest, two of which are operated and managed by enXco and one of which is
operated by Caithness Energy, LLC; (iv) certain investments in (the Chapais
Facility, a biomass facility that is operated and managed by Probyn Power
Services Inc., an affiliate of the Administrator/Manager: (v) loans to PEET
Canadian Holdings Inc. and PEET U.S. Holdings, Inc., whose wholly-owned
subsidiary, GRS, operates and manages 29 operating landfill gas facilities which
are wholly or partly owned by GRS; and (vi) the Erie Shores Wind Farm, currently
under construction.

      The Fund is administered by the Administrator/Manager, a wholly-owned
subsidiary' of Canadian Environmental Energy Corporation ("CEEC"). The
Administrator/Manager also manages the business of Clean Power Operating Trust
("CPOT"), which is wholly owned by the Fund and is the direct or indirect
holder of the Fund's operating assets and investments. CEEC is principally owned
by a subsidiary of Probyn Eastman Ltd. and Sun Life Assurance Company of Canada.
The Fund currently owns all of the issued and outstanding units of CPOT,
Accordingly, the Fund, at the direction of the Unitholders, elects the
independent trustees of CPOT ("Independent Trustees").

      Prior to July 2003, the Fund had been making quarterly distributions of
Distributable Cash. The quarterly distribution for the quarter ended June 30.
2003 was made to Unitholders of record on June 30, 2003 and was paid to
Unitholders on July 15, 2003. Commencing with the distribution for July 2003,
the Fund makes monthly cash distributions, which distributions will be made to
Unitholders of record on the last business day of each month and will be paid on
the last business day of the following month.

      The head office and principal business office of the Fund is located at
Suite 1600, 67 Yonge Street, Toronto, Ontario, M5E 1J8.

CLEAN POWER OPERATING TRUST

      CPOT is an unincorporated open-ended trust established under the laws of
Ontario pursuant to the CPOT Trust Indenture. CPOT is a limited purpose trust
and its activities are restricted to the conduct of the business of, and the
ownership, operation and lease of assets and property in connection with, the
generation, transmission, distribution and purchase and sale of electricity,
having investments and other direct or indirect rights in companies or other
entities involved in the business of the generation, transmission, distribution,
purchase and sate of electricity, and engaging in all activities ancillary or
incidental thereto. CPOT is wholly owned by the Fund and will generally be the
direct or indirect holder of the Fund's operating assets and investments.

      The current Chairman of the Board of CPOT Trustees is one of two
appointees of the Administrator/Manager (the "Manager Trustees"), Mr. H. Allen
Jackson. At the annual and special meeting of the Fund on May 9, 2005,
unitholders of the Fund voted to amend the CPOT Trust Indenture to address
certain corporate governance matters, including updating the definitions of
"Independent Trustee" and "Manager Trustee"; changing the number of CPOT
Trustees to be elected or appointed to a range of between five and seven and
giving the CPOT Trustees the power to fill vacancies in such positions, and the
power to appoint additional CPOT Trustees within this range; to provide that all
members of the audit committee must be Independent Trustees; to provide that
there shall be a nominating committee composed oflndependent Trustees; to
provide that nominees

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for election as Independent Trustees will be recommended for nomination to the
Board of CPOT Trustees by the nomination committee; to provide that after the
current Chairman retires, and during the term of its management agreement with
CPOT, the Administrator/Manager will be entitled to appoint one Manager Trustee
and one non-voting observer to the Board of CPOT Trustees; to provide that a
lead CPOT Trustee will be appointed from among the Independent Trustees until
such time as the current Chairman retires, and after he retires, to provide that
the position of Chairman may only be filled by an Independent Trustee; to
provide that there shall be formal mandates for all committees of the Board of
CPOT Trustees and that such committees have access to such information as is
necessary to permit such committees to carry out their respective mandates; to
provide that should the Manager of CPOT, or the trustee of the Fund wish to
delegate one or more of their respective functions that CPOT Trustees have the
power to accept such delegation should they agree to perform such functions: and
to clarify certain elements of the provisions relating to indemnification of the
CPOT Trustees.

CLEAN POWER LIMITED PARTNERSHIP

      CPLP is a limited partnership established under the laws of Ontario to
carry on the business of generation, transmission, distribution and purchase and
sale of electricity and other ancillary matters and, in connection with such
business, to own, operate and lease assets and property, to make investments and
hold other direct or indirect rights and to engage in all activities ancillary
and incidental thereto. The general partner of CPLP is Clean Power Income Fund
(Alberta) Inc. ("Albertaco"), a wholly-owned subsidiary of CPOT. CPLP holds
certain assets of the Fund including the Whitecourt Facility. CPLP may be used
by the Fund to acquire additional clean power assets.

STRUCTURE OF THE FUND

      The primary structural, contractual and ownership relationships of the
Fund are as follows. Related party transactions and commitments are described in
Note 18 of the Fund's 2005 Annual Financial Statements which are hereby
incorporated by reference.

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                              [FLOW CHART OMITTED]

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                       GENERAL DEVELOPMENT OF THE BUSINESS

SPECIAL COMMITTEE

      On October 26T 2005, the Fund announced that the Trustees of CPOT had
created a special committee to investigate unitholder value enhancement
opportunities. As updated on March 16. 2006. the special committee has been
concentrating its efforts to date with respect to the investment of the Fund in
GRS. With the assistance of its financial advisors. Scotia Capital Inc. and
Ewing Bemiss & Co., the special committee has undertaken competitive process to
dispose of the Fund's interest in GRS. Also, the special committee is working
with the Administrator/Manager on how best to proceed with the unitholder value
enhancement process. On March 29, 2006, the Fund announced that following a
competitive process, the special committee received a number of conditional bids
for this investment.

      The special committee is comprised of Mr. John Fox (Chair), Mr. Donald
McCutchan and Mr. H. Allen Jackson.

ISSUANCE OF TRUST UNITS AND 6.75 PERCENT CONVERTIBLE UNSECURED SUBORDINATED
DEBENTURES

      Pursuant to a prospectus dated June 18, 2004, the Fund completed an
offering of $555,000,000 of 6.75 percent convertible unsecured subordinated
debentures (the "Debentures") due December 31, 201O (the "Maturity Date"). The
Debentures bear interest at an annual rate of 6.75 percent, payable
semi-annually in arrears on June 30 and December 31 in each year. The Debentures
are convertible at the Debenture holder's option into fully paid Trust Units at
any time prior to the earlier of their Maturity Date and the date fixed for
redemption, at a conversion price of $10.20 per Trust Unit (the "Conversion
Price"). The Debentures are not redeemable on or prior to June 30, 2007. After
June 30, 2007 and prior to July 1, 2009, the Debentures may be redeemed in whole
or in part at the Fund's option provided that the market price for the Fund's
Trust Units is not less than 125 percent of the Conversion Price. On or after
July 1, 2009 and prior to the Maturity Date, the Debentures may be redeemed, in
whole or in part, at the Fund's option, at a price equal to their principal
amount plus accrued and unpaid interest. Subject to regulatory approval, the
Fund may satisfy its obligation to repay the principal amount of the Debentures,
in whole or in part, by delivering that number of Trust Units equal to the
principal amount of the Debentures divided by 95 percent of the market price for
the Trust Units at that time.

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SUMMARY TABLES OF FACILITIES

      The Fund has invested in the following Waterpower, Biomass, U.S. Windpower
Facilities and the Erie Shores Wind Farm:



------------------------------------------------------------------------------------------------------------------------------------
                                           ANNUAL
                                          EXPECTED
                                           ENERGY                             CREDIT RATING OF PURCHASER   EXPIRY
 FACILITY              ENERGY   SIZE(1)  PRODUCTION       ELECTRICITY        ----------------------------  OF FPA
(LOCATION)             SOURCE    (MW)      (MWH)           PURCHASER            DBRS      S&P    MOODY'S    TERM       OPERATOR
------------------------------------------------------------------------------------------------------------------------------------

Erie Shores Wind          Wind    99.00              Ontario Power            A (high)    n/r      Aa2      2026        GE (11)
Farm(9) (Ontario)                                    Authority                                              (10)

Foote Creek II (5)        Wind     1.80       6,600  Bonneville Power            n/r     AA-U(7)   Aaa (7)  2024        ScaWest
(Wyoming)                                            Administration (6)

Foote Creek III (5)       Wind    24.75      79,700  Public Service Company  BBB (high)   BBB     Baal      2014        SeaWest
(Wyoming)                                            of Colorado

Foote Creek IV (5)        Wind    16.80      62,400  Bonneville Power            n/r     AA-(7)   Aaa (7)   2020        SeaWest
(Wyoming)                                            Administration (6)

Peetz Table (5)           Wind    29.70      72.700  Public Service          BBB (high)   BBB     Baal      2016         enXco
(Colorado)                                           Company of Colorado

Big Spring (5)            Wind    34.32     100,200  TXU Corp.                   n/r      BBB-     Bal      2024       Caithness
(Texas)                                                                                                               Energy, LLC

Chandler (5)              Wind     1.98       6,900  Cooperative Power           n/r      n/r      n/r      2014         enXco
(Minnesota)

Sechelt Facility (BC)    Water    16.00      90,300  BC Hydro                    AA        AA      Aal      2017    Regional Power

Wawatay Facility        Water    13.50       59,013  Ontario Electricity         AA        AA      Aa2      2042    Regional Power
(Ontario)                                            Financial Corp.

Dryden Facility          Water     3.25      20,568  Ontario Electricity         AA        AA      Aa2      2020    Regional Power
(8) (Ontario)                                        Financial Corp.

Hluey Lakes              Water     3.00       6,714  BC Hydro                    AA        AA      Aal      2020    Regional Power
Facility (BC)

Whitecourt             Biomass    28.00     200,000  TransAlta Utilities         n/r      BBB      n/r      2014   Probyn Whitecoun
Facility                                             Corp. (2)                                                      Management Inc.
(Alberta)

Chapais FBidiBa (3)         ss    31.00     219,000  Hydro Quebec                 A        A+      Al       2020     Probyn Power
(Quebec)                                                                                                    (4)      Services Inc.
------------------------------------------------------------------------------------------------------------------------------------
TOTAL MW                         303.10
------------------------------------------------------------------------------------------------------------------------------------


Notes:

(1)   Gross capacity of facility.

(2)   In accordance with the Electric Utilities Act (Alberta), the benefits and
      burdens of this agreement flow through to the Alberta Balancing Pool. See
      "Industry Overview - Canada --Alberia".

(3)   Until July 2004, the Fund's investment in this facility was in the form of
      interests in preferred shares that provided for specified preferential
      dividends. Certain of such preferred shares were exchanged in July 2004
      for senior and subordinated debt of Chapais Energie, Societe en
      Commandite, the owner of the Chapais Facility.

                                      - 6 -

EX-3.12 11th Page of 80 TOC 1st Previous Next ↓Bottom Just 11th
(4)   The original term of the PPA expires in 2015. However, provided that
      certain conditions are met, the PPA may be extended for an additional five
      years al the option of Chapais Energic. Societe en Commandite, owner of
      the Chapais Facility.

(5)   The Fund's investment in this Facility is in the form of a loan See "The
      Investments - Investments in the U.S. Windpowcr Facilities".

(6)   Bonneville Power Administration is an agency of the U.S. Department of
      Energy.

(7)   Rating of bonds issued by Energy Northwest on behalf of Bonneville Power
      Administration.

(8)   Made up of the Wainwright, Eagle River and McKenzie Falls waterpower
      facilities.

(9)   Capacity upon completion of construction.

(10)  The PPA has a term of 20 years from Use Commercial Operation Date.

(11)  GE will provide the first four years of post construction service and
      maintenance.

                                      - 7 -

EX-3.12 12th Page of 80 TOC 1st Previous Next ↓Bottom Just 12th
      The Fund has also invested (in the form of indirect loans) in the
following Landfill Gas Facilities:



-------------------------------------------------------------------------------------------------------------------
                                                                        CREDIT RATING OF PURCHASER    EXPIRY OF PPA
    FACILITY            SIZE                                            --------------------------    OR GAS SALE
    (LOCATION)        (MW)(1)        ELECTRICITY OR GAS PURCHASER          S&P       MOODY'S           AGREEMENT
-------------------------------------------------------------------------------------------------------------------

American Canyon         1.500     Pacific Gas & Electric Company(2)        BBB        Baal                 2015
(California)
Arbor Hills            23.200     The Detroit Edison Company               BBB        Baal                 2030
(Michiaan)
C&C                     3.100     Consumers Power Company                  BB          Ba2                 2030
(Michigan)
Charlotte               5.300     The City of Concord                      AA-         Aa2                2019(3)
(North Carolina)
Chicoee                 1.950     Chicopee Municipal Lighting Plant        AA-         n/r                 n/a(4)
(Massachusetts)
Coyote Canyon           21.00     San Diego Gas & Electric Company          A          A2                  2012
(California)
East Bridgewater        5,850     Taunton Municipal Lighting Plant         n/r         A3                 2019(5)
(Massachusetts)
Fall River              6.950     Taunton Municipal Lighting Plant         n/r         A3                 2020(5)
(Massachusetts)
Guadalupe               2.675     Pacific Gas & Electric Company(2)        BBB        Baal                 2014
(California)
Halifax                 1.950     Massachusetts Electric Company            A          A2                 n/a(6)
(Massachusetts)
Lyon                    5.10Q     The Detroit. Edison Company              BBB        Baal                 2030
(Michigan)
Mallard Lake           23.200     Commonwealth Edison Company             BBB+        Baa2                2O17(7)
(Illinois)
Menlo Park              2.100     Pacific Gas & Electric Company(2)        BBB        Baal                 2013
(California)
Newby Island I          2.100     Pacific Gas & Electric Company(2)        BBB        Baal                 2014
(California)
Newby Island 1I         3.300     Pacific Gas & Electric Company(2)        BBB        Baal                 2014
(California)
Newby Island III(8)   Gas Sales   City of San Jose                         AA+         Aal                2O18(9)
(California)
Pine Bend              17.000     Northern States Power Company            BBB         A3                  2025
(Minnesota)
Quad Cities             2.000     MidAmerican Energy Company               A-          A2                 2008(7)
(Illinois)
Randolph                2.925     *(10)                                    AAA         Aaa                n/a(10)
(Massachusetts)
Richmond                2.050     Virginia Electric Power Company          BBB         A3                  2013
(Virginia)
Rockford (Illinois)     2.000     Commonwealth Edison Company             BBB+        Baa2                2006(7)
Sacramento (8)        Gas Sales   California Almond Growers Exchange       n/r         n/r                n/a(12)
(California)
San Marcos              1.325     San Diego Gas & Electric Company          A          A2                  2007
(California)
Santa Cruz              0.933     Pacific Gas & Electric Company(2)        BBB        Baal                 2009
(California)
South Barrington        1.600     Commonwealth Edison Company             BBB+        Baa2                 2007(7)
(Illinois)
Sunset Farms            4.075     The City of Austin                       n/r         Aa2                 2021
(Texas)
Sycamore I              1.325     San Diego Gas & Electric Company          A          A2                  2007
(California)
Sycamore II             3.100     San Diego Gas & Electric Company          A          A2                  2013
(California)
Vienna Junction(8)    Gas Sales   General Motors Corporation                B          B2                2015(11)
(Michigan)
-------------------------------------------------------------------------------------------------------------------
TOTAL MW                147.608
-------------------------------------------------------------------------------------------------------------------
TOTAL MW FOR ALL
OPERATING FACILITIES    450.708
-------------------------------------------------------------------------------------------------------------------


Notes:

                                      - 8 -

EX-3.12 13th Page of 80 TOC 1st Previous Next ↓Bottom Just 13th
(1)   Name plate capacity rating.

(2)   Pncific Gas & Electric Company emerged from Chapter 11 in April 2004 and
      has re-established its investment grade credit rating.

(3)   The term of the Charlotte PPA is five years commencing in 1999. extended
      automatically for three successive five-year terms unless notice to
      terminate is given by either party one year prior io the end of the
      initial term or any extended term.

(4)   The Chicopee facility is on a month-to-month PPA.

(5)   Taunton Municipal Lighting Plant has an option to purchase these Landfill
      Gas Facilities exercisable prior to the expiration date of the applicable
      PPA as described below under the heading "Power Purchase Agreements".

(6)   Electricity generated at the Halifax facility is sold to Massachusetts
      Electric Company at the prevailing market rates under a Qualifying
      Facility Power Purchase Rate Agreement that is terminable by either party
      on seven days notice.

(7)   These facilities sell power under the Illinois Public Utilities Act. The
      dates shown above represent the dates on which above-market payments under
      this law cease in respect of those facilities. The facilities are required
      to continue operating for a period of 10 years (20 in the case of Mallard
      Lake) beyond these dates to avoid early repayment of the above-market
      payments received. See "Landfill Gas Facilities in Illinois" below.

(8)   The Sacramento, Vienna Junction and Newby Island III facilities do not
      produce electricity but instead sell processed landfill gas directly to
      end-users. See "Gas Sale Agreements" below.

(9)   The Newby Island III gas sale agreement has a term of 15 years from the
      date of first delivery of landfill gas, which occurred in June 2003. The
      City of San Jose may terminate the Newby Island III gas sale agreement
      without cause at any time after April 11, 2007.

(10)  The terms of this PPA are subject to restrictions on publication but are
      generally similar to terms of GRS' other PPAs.

(11)  The term of the Vienna Junction gas sale agreement ends on the first to
      occur of (a) the day 20 years from the date of first delivery of processed
      gas under the gas sale agreement and (b) delivery of 4,881,800 MMBtu of
      processed landfill gas, and may be extended for five years at the option
      of GRS. As of December 31, 2005, approximately 1,074,000 MMBtu's have been
      delivered, 107,000 MMBtu's in 2005.

(12)  The initial term of the Sacramento gas sale agreement expired December
      2002. Gas is currently sold under one-year renewal terms.

DIVERSIFIED ASSET BASE

      The Fund's strategy is to enhance the stability of its financial
performance by making investments in electricity generating Facilities that are
diversified based on the geographic market which they serve and the sources of
energy which they use to generate electricity. The Facilities serve the
provincial power grids in Ontario, Alberta, Quebec and British Columbia, a
municipality in northern British Columbia and markets in the Pacific Northwest,
Colorado, California, Texas, Minnesota, Illinois, Michigan, Massachusetts,
Virginia and North Carolina. The Facilities generate electricity using
waterpower, biomass (waste wood from forest industry operations), landfill gas
and windpower.

THE INVESTMENTS

INVESTMENT IN THE ERIE SHORES WIND FARM

      On November 25, 2004, the Fund and AIM PowerGen Corporation ("AIM")
announced that their Erie Shores Wind Farm Limited Partnership (the
"Partnership") was one of the successful bidders in the Ontario Government's
Request for Proposals for 300 MW of renewable energy. The Partnership entered
into a 20-year Renewable Energy Supply Contract ("RES Contract") with the
Ontario Electricity Financial Corporation ("OEFC") for the sale of all the
energy generated from the Erie Shores Wind Farm. The RES Contract was assigned
by OEFC to the Ontario Power Authority ("OPA") on November 10,2005, as was
provided for in the RES Contract.

      The Erie Shores Wind Farm, a 99 MW wind energy project, is being
constructed along the northern shoreline of Lake Erie between Copenhagen and
Clear Creek, Ontario. The facility will consist of 66 wind turbines, each with
1.5 MW (nameplate) capacity.

      In March 2005, the Partnership executed a contract with the consortium of
General Electric Canada and General Electric Company ("GE") to supply the wind
turbines at a fixed price. Under a separate contract between General Electric
Canada and the Partnership. GE will also provide the first four years of the
wind project's post-construction turbine operations and maintenance at a fixed
price. The GE turbine supply agreement includes a power curve warranty and wind
industry standard guarantees of equipment performance and availability for the
entire four- year period, backed by the full credit of GE.

      On June 29, 2005, the Fund acquired AIM'S interest in the Partnership for
nominal consideration and additional potential payments as described in note 9
of the Fund's 2005 Annual Financial Statements.

      Also on June 29, 2005, the construction financing of $I86 million was
completed, consisting of the following three parts:

                                      - 9 -

EX-3.12 14th Page of 80 TOC 1st Previous Next ↓Bottom Just 14th
      o     $120 million non-recourse project financing arranged and led by Sun
            Life Financial:

      o     $56 million equity bridge loan from CPOT's acquisition facility
            provided by Scotia Capital and National Bank; and

      o     $1O million equity bridge loan from Sun Life Financial.

      (See Notes 9 and 14 of the Fund's 2005 Annual Financial Statements for
financing terms.)

      Construction of the Erie Shores Wind Farm was started in the summer of
2005 after a fixed-price contract for the balance of plant construction was
entered into between the Partnership and a joint venture of AMEC Americas
Limited (an affiliate of AMEC pic) and Black. Sc McDonald Limited. AMEC pic is
an international project management and engineering services company with $11
billion in revenue in 2004. Black & McDonald Limited is a private Canadian
multi-trade contracting Firm operating in North America and selected global
markets. On December 7, 2005, the Fund announced the completion of the
foundations for the wind turbines. Also in December 2005, deliveries of major
equipment from GE began. The project was "energized" on March 6, 2005. This is a
major construction milestone as the initial stage of the commissioning process
to begin electricity production and sales. The commercial operation date, which
occurs at the completion of performance testing for all 66 turbines, is expected
to occur in the second quarter of 2006. By March 10, 2005, 33 of the 66, or half
of the project's GE SLE 1.5MW turbines had been erected.

      In addition to the Erie Shores Wind Farm, the Fund acquired a first right
of refusal respecting a proposed 50 MW expansion of the Erie Shores Wind Farm
from AIM. This expansion project is well advanced with respect to environmental
permitting approvals.

INVESTMENTS IN THE U.S. WINDPOWER FACILITIES

      On October 8, 2003, as part of an overall transaction involving the
indirect sale by Cinergy Global Power ("Cinergy") of the Foote Creek III, Foote
Creek IV and Peetz Table facilities (the "Sold Facilities") to subsidiaries of
Caithness Western Wind Holdings, LLC ("CWWH") and the release of payment
obligations of Cinergy, CPOT closed the refinancing of its windpower loan
interests in the Sold Facilities and obtained indirect investments in three
additional windpower generating facilities, being Big Spring, Texas (34.32 MW),
Chandler, Minnesota (1.98 MW) and Foote Creek II, Wyoming (1.80 MW). The effect
of the overall transaction was to consolidate CPOT's windpower loan interests
into the single U.S. Windpower Loan which is supported by cash flows generated
from the Sold Facilities plus the three additional windpower facilities. Cash
payments on the U.S. Windpower Loan have also been consolidated into two
semi-annual payments, in arrears, to be received in March and September versus
the three payments that were previously received in March. July and October. In
addition, Albertaco has been granted an option, exercisable at the maturity of
the Senior Loan, to effectively convert the U.S. Windpower Loan into 35.0
percent of the equity of the U.S. Windpower Facilities. The Fund believes that
the refinancing was beneficial to Unitholders in that it diversified operating
cash flow amongst a greater number of facilities thereby reducing business risk.
CWWH is a subsidiary of Caithness Energy, LLC. Caithness Energy, LLC is a large
U.S.-based, privately held energy company that has been investing in energy
assets since 1964. The Big Spring facility is operated by Caithness Energy, LLC;
the Chandler and Peetz Table facilities are operated by enXco, and the Foote
Creek II, Foote Creek II and Foote Creek IV facilities are operated by SeaWest.

      The U.S. Windpower Loan bears interest at 11.5 percent per annum, and as
a result of the original assignment by CEEC to CPOT, the effective yield to
maturity to CPOT on the U.S. Windpower Loan will be approximately 10.5 percent.

      The project revenue is derived from payments under the PPA for each U.S.
Windpower Facility and does not rely on available production tax credits
received by the equity owners of such U.S. Windpower Facilities. All project
revenues will be required to be applied to sen'ice the Senior Loan before they
may be applied to service the U.S. Windpower Loan. The U.S. Windpower Loan has a
term to September 30, 2024 with no right of pre-payment. As from March 31, 2022,
the principal of the U.S. Windpower Loan will be amortized over the balance of
its term in accordance with an amortization schedule set out in the U.S.
Windpower Loan agreement.

      The obligations of CWWH under the U.S. Windpower Loan are secured against
the assets of the U.S. Windpower Facilities, subject to the terms of a
subordination agreement (the "Subordination Agreement") in favour of the lenders
of the Senior Loan. Under the terms of the Subordination Agreement, the U.S.
Windpower Loan is subject to standstill obligations preventing the exercise of
any rights or remedies by CPOT with respect to the U.S. Windpower Loan unless
consented to by the lenders of the Senior Loan or until such time as such Senior
Loan is repaid in full. In addition, the security granted in respect of the U.S.
Windpower Loan has been fully subordinated to the Senior Loan and the related
security.

                                     - 10 -

EX-3.12 15th Page of 80 TOC 1st Previous Next ↓Bottom Just 15th
      Upon a defauli in payment of interest or principal owed in respect of the
U.S. Windpower Loan the entire principal and outstanding interest owed in
respect of the U.S. Windpower Loan may be declared to be due and payable,
subject to the standstill obligations under the Subordination Agreement which
will prevent CPOT from exercising any enforcement rights without the consent of
the lenders under the Senior Loan. In addition, any default under the U.S.
Windpower Loan (other than failure to pay any amount relative thereto) may be
waived by the lenders under the Senior Loan. Pending payment of such amounts,
interest will continue to accrue and, to the extent not paid, will be compounded
yearly. Prepayment of the U.S. Windpower Loan is not permitted without payment
to CPOT of a make whole amount.

INVESTMENT IN GRAND MANAAN PROJECT

      On November 15, 2004, the Fund and Western Wind Energy Corp. ("Western
Wind") announced an intention to enter into a joint venture agreement to
develop, construct, finance and operate a 20 MW windpower generating facility in
Grand Manaan, New Brunswick.

      As a result of reduced return expectations, in November 2005 the Fund
withdrew its interest in proceeding with the Grand Manaan Project. In November
2005, the Fund was repaid in full, principal and accrued interest on a $400,000
secured senior promissory note provided to Western Wind for development costs.

ACQUISITION OF THE WATERPOWER FACILITIES

      The terms of the acquisition agreement between CPOT and Regional Power
contemplated that the base rate under the Dryden PPA and the Wawatay PPA, which
was to be indexed to changes in OEFC's direct customer rate ("DCR") would be
replaced with some mechanism which would increase, over time, the rates paid by
OEFC for electricity sold under the Dryden PPA and the Wawatay PPA. See
"Industry Overview - Canada - Ontario". CPOT and Regional Power had agreed that
in such an event, Regional Power would be entitled to 75.0 percent of the
incremental revenue under each of the Dryden PPA and Wawatay PPA resulting from
such increase being in excess of 3.0 percent per year. Subsequently, in 2003,
binding term sheet were signed by the Fund and OEFC replacing the DCR with a
replacement index based on the total cost of electricity over a three-year
period. No payments have been made by the Fund to Regional Power resulting from
the replacement index, and no amounts are payable. In any other event in which
there is a rate increase under the Dryden PPA or the Wawatay PPA, Regional Power
will be entitled to 75.0 percent of the incremental revenue received by CPOT
resulting from rate increases which are, on a cumulative basis, in excess of the
greater of the Consumer Price Index for Ontario and 3.0 percent. All other forms
of payment received after Closing resulting from any decrease or forgiveness of
generator debt, any change or replacement to the interest rate applied by OEFC
to such generator debt, or any other amendment or change to the economic
provisions of the Dryden PPA or the Wawatay PPA, will be paid 100.0 percent to
Regional Power if it relates to a period ending on or before Closing and 75.0
percent to Regional Power and 25.0 percent to CPOT if it relates to a period
commencing after Closing.

      Regional Power has the rights to expand the Wawatay Facility and the
Dryden Facility beyond their current capacities and has the right to build a new
facility in the upper Sechelt Creek and in each case, will be entitled to the
revenue attributable to electricity generated by any expansion equipment. CPOT
has the right to approve the design of any such expansion, such approval not to
be unreasonably withheld. In undertaking any expansion or new facility Regional
Power is required to ensure the structural integrity of the existing facilities
is not compromised and will indemnify CPOT for any damage to or material adverse
effect on the current facilities and the operation of its business which results
from such an expansion or new facility.

INVESTMENT IN THE CHAPAIS FACILITY

      In connection with the Chapais Refinancing Arrangement, Capital d'
Amerique CDPQ Inc. ("CDPQ"), one of the lenders to CHESEC, acquired 15,321,084
Class A Preferred Shares, 3,783,534 Class B Preferred Shares and 2,558,268 Class
C Preferred Shares of CHEL Subco Inc. (collectively, the "Subject Preferred
Shares"), and CDPQ and Caisse de Depot et Placement du Quebec (the "Caisse")
entered into certain agreements with each other and with a Canadian chartered
bank (the "Swap Counterparty"). Under these agreements, CDPQ transferred the
Subject Preferred Shares to the Swap Counterparty, and the Caisse entered into a
swap arrangement with the Swap Counterparty in which it agreed to pay a variable
rate of interest on the amount of paid up capital of the Subject Preferred
Shares outstanding in return for payments from the Swap Counterparty based on
the dividends received on the Subject Preferred Shares. In addition, these
agreements provided for various put and call rights which would entitle or
require, as the case may be, the Caisse to purchase the Subject Preferred Shares
from the Swap Counterparty for a specified price. CDPQ and the Caisse also
entered into put and call arrangements that would

                                     - 11 -

EX-3.12 16th Page of 80 TOC 1st Previous Next ↓Bottom Just 16th
permit or require, as the case may be, CDPQ to reacquire the Subject Preferred
Shares following their acquisition by the Caisse.

      On February 22, 2002, pursuant to the terms of a share purchase and
assignment agreement between CPOT, CDPQ, the Caisse and CPOT Holdings Corp.
("Holdings"), a wholly-owned subsidiary of CPOT, CPOT acquired all of the
Caisse's rights pursuant to certain of the above-described agreements entered
into in connection with the Chapais Refinancing Arrangement (collectively, the
"Caisse Assigned Agreements") and Holdings acquired all of CDPQ's rights
pursuant to certain agreements entered into in connection with the Chapais
Refinancing Arrangement (the "CDPQ Assigned Agreements") as well as 105 Class B
preferred shares in the capital of CHEL held by CDPQ. As consideration for such
acquisition, CPOT assumed all of the Caisse's obligations under the Caisse
Assigned Agreements (including the obligation to purchase the Subject Preferred
Shares upon the occurrence of a put event under such contracts) and Holdings
assumed all of CDPQ's obligations under the CDPQ Assigned Agreements and paid
CDPQ (pound)944,201.74.

      In furtherance of the Caisse Assigned Agreements, CPOT entered into an
arrangement with the Swap Counterparty pursuant to which CPOT made certain
variable rate interest payments in return for payments based on the dividends
received by the Swap Counterparty on the Subject Preferred Shares. CPOT
originally deposited $16,775,798 with the Swap Counterparty as security for its
obligations to purchase the Subject Preferred Shares from the Swap Counterparty
under such arrangements. The Fund received interest from the Swap Counterparty
on the principal amount of the deposit outstanding from time to time at a
variable rate. An amount of the deposit equal to amounts repaid on capital on
the Subject Preferred Shares was returned to the Fund from time to time.

      The put/call arrangement with the Swap Counterparty and between CPOT and
Holdings was exercised on July 30, 2004, the date upon which the Chapais
Refinancing Arrangement was scheduled to terminate. As a result of the
termination of the Chapais Refinancing Arrangement, the Fund now holds (i) 24.79
percent of the Tranche A Senior Debt of CHESEC, which bears interest at a rate
of 10.789 percent per annum, and is payable by monthly blended payments of
principal and interest, and matures in December 2015; (ii) 24.79 percent of the
Tranche B Senior Debt of CHESEC, which bears interest at a rate of 4.91 percent
per annum, payable by semi-annual interest payments, with annual principal
payments based on CHESEC's free cash flow and which matures in December 2015;
and (iii) 50.0 percent of the subordinated debt of CHESEC. which does not bear
interest and matures in December 2015. Upon termination of the Chapais
Refinancing Arrangement in July 2004, the Fund's portion of the approximate
outstanding aggregate principal amount of Tranche A Senior Debt of CHESEC was
$9.4 million, Tranche B Senior Debt of CHESEC was S3.8 million and subordinated
debt of CHESEC was S2.5 million.

GRS INVESTMENTS

      Please refer to the section above under the heading "Special Committee"
regarding the disposition process of the Fund's investment in GRS.

      The Landfill Gas Facilities are wholly or partly owned by GRS, all of the
shares of which are owned by PEET U.S., a wholly-owned subsidiary of PEET
Canada. PEET Canada is a wholly-owned subsidiary of PEET, an independent
charitable trust settled by Stephen Probyn and Dr. Barbara Eastman.

      In December 2004, a new executive team of power industry and management
specialists was appointed by the company's U.S. parent to replace the third
party management contract which was terminated by mutual agreement of the
parties, effective December 15, 2004.

      CPOT has loaned US$15 million to PEET Canada (the "PEET Canada Loan") and
Albertaco has loaned US$85 million to PEET U.S. (the "PEET U.S. Loan" and
together with the PEET Canada Loan, the "GRS Loans") of which approximately
US$78.3 million consists of a term loan used to finance the acquisition by PEET
U.S. of GRS. The balance consists of a revolving loan and letter of credit
facility to assist with the financing of the ongoing operations of PEET U.S. and
GRS. The GRS Loans are provided for in definitive loan documentation entered
into between CPOT and PEET Canada and between Albertaco and PEET U.S. that
contain customary covenants, representations and warranties for loans of this
type. The PEET Canada Loan has a remaining term of 17 years and bears interest
at 11.5 percent payable quarterly in arrears. The term loan portion of the PEET
U.S. Loan has a remaining term of 7 years and bears interest at 11.5 percen l
payable monthly in arrears. The revolving portion of the PEET U.S. Loan, which
may take the form of loans or letters of credit, bears interest at floating
rates based upon Albertaco's cost of borrowing plus 0.25 percent. The revolving
portion was amended in December 2003 to expand the facility capacity from US$6
million to US$15 million to fund certain capital expenditures and temporary
working capital requirements. The GRS Loans provide for repayment of outstanding
principal in each year, in amounts expected to require a period of years longer
than the term of the applicable GRS Loan for full principal

                                     - 12 -

EX-3.12 17th Page of 80 TOC 1st Previous Next ↓Bottom Just 17th
repayment. Accordingly, the remaining outstanding principal amounts of the GRS
Loans will be required to be repaid or refinanced at the end of the applicable
terms. See "Risk Factors".

      PEET U.S. has 1,000 Class A voting common shares and 14,000 Class B
non-voting common shares issued and outstanding, all of which are owned by PEET
Canada. The economic entitlements of the Class A voting and Class B non-voting
shares are the same in all material respects. CPOT has a contingent option to
acquire the 14,000 Class B non-voting common shares of PEET U.S. during a period
ending 10 business days after repayment of the PEET Canada Loan, upon the
occurrence of certain specified events, including an event of default having
occurred under both the PEET Canada Loan and the PEET U.S, Loan that is not
remedied within 90 days, receipt by PEET of a bona fide offer to purchase shares
of PEET Canada, receipt by PEET Canada of a bona fide offer to purchase shares
of PEET U.S., receipt by PEET U.S. of a bonafide offer to purchase shares of GRS
or any other material subsidiary, or repayment of the PEET Canada Loan. The
contingent option will cease to be exercisable and will terminate upon a secured
party, trustee in bankruptcy, receiver, custodian or similar person being
appointed for, or taking possession of, all or a material portion of the assets
of CPOT, The definitive loan agreements for the GRS Loans include restrictions
on the issuance by PEET Canada and PEET U.S. of additional debt or equity
without the consent of CPOT or Albertaco. respectively and require PEET Canada
and PEET U.S. to enforce, or cause to be enforced, their rights and the rights
of GRS under the acquisition agreement between PEET U.S. and the vendors of the
shares of GRS.

      In September 2004, PEET U.S, created a new class of non-voting preferred
shares with a par value of US$1,000 per share. The preferred shares entitle
holders to a 4% cumulative dividend payable in preference to the Class A voting
common shares and Class B non-voting common shares, and are retractable by the
holders and redeemable by PEET U.S. after five years. Pursuant to a subscription
agreement dated September 27, 2004, PEET U.S. issued 10,000 preferred shares to
Albertaco for US $10,000,000. Pursuant to a subscription agreement dated
December 22, 2005, PEET U.S. issued an additional 5,000 preferred shares to
Albertaco for US $5,000,000. Such proceeds have been used by PEET U.S. to pay
down the revolving portion of the PEET U.S. Loan, thereby permitting it to
reduce existing debt and provide additional capacity in the revolving portion of
the PEET U.S. Loan to fund future capital expenditures. The subscription price
for the preferred shares was loaned by CPOT to Albertaco pursuant to a term loan
bearing interest at 3% and maturing on the earlier of September 27, 2025 or
immediately following the redemption or retraction of the preferred shares
issued to Albertaco.

OPERATING STRATEGY

      The Fund retains the services of highly qualified operators for the
facilities it acquires.

      Under a contract signed in March 2005, GE will provide the first four
years of the Erie Shores Wind Farm's post-construction turbine service and
maintenance at a fixed price. The GE agreement includes a revenue reimbursement
warranty and wind industry standard guarantees of equipment performance and
availability for the entire four-year period, backed by the full credit of GE.

      The Waterpower Facilities are operated by Regional Power, a leading
operator of waterpower facilities in Canada and a subsidiary of Manulife
Financial Corporation. Regional Power was responsible for the design,
development and construction of the Sechelt Faciiity and the Wawatay Facility
and for the completion of the design, development and construction of the Hluey
Lakes Facility. Regional Power has operated the Wawatay Facility since its
completion in 1992, the Sechelt Facility since its completion in 1997 and the
Hluey Lakes Faciiity since its completion in 1999. Regional Power has operated
the Dryden Facility since acquiring it in 1985.

      The Whitecourt Facility is operated by Probyn Whitecourt Management Inc.,
a member of the Probyn Group, a leading operator of biomass power generating
facilities in Canada. The Probyn Group has been operating since 1987 and
currently owns, operates and/or manages electrical generating facilities with
total capacity of 230 MW, Companies in the Probyn Group currently employ or
manage over 110 employees involved in finance, contract administration,
management, maintenance, operations, stationary engineering, fuel management and
accounting located in offices and facilities in Toronto, Ontario; Brooklyn. Nova
Scotia: Chapais, Quebec; and Whitecourt, Alberta.

      The Fund will ensure that, at the time of investment, facilities in which
it makes investments otherwise than by way of acquisition (including by way of
loans, preferred shares exchangeable for loans or minority equity interests),
such as the U.S. Windpower Facilities owned by CWWH. the Chapais Facility and
the Landfill Gas Facilities owned by GRS, are managed by highly qualified
operators.

      The operator of three of the six U.S. Windpower Facilities, being Foote
Creek II, Foote Creek III and Foote Creek IV, is SeaWest. SeaWest has extensive
experience in the windpower industry dating back to 1983, having

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developed 35 projects and installed over 3,300 wind turbines with a total
capacity of over 970 MW. The operator of Peetz Table and Chandler is enXco, a
subsidiary of enXco A/S. enXco A/S has extensive experience in the windpower
industry dating back to l985. Caithness Energy, LLC is the operator of Big
Spring.

      The operator of the Chapais Facility is Probyn Power Services Inc., a
member of the Probyn Group, a leading operator of biomass power generating
facilities in Canada.

      Until December 2004. the operator of the Landfill Gas Facilities had been
GRSM. In December 2004, an agreement was reached between GRS and GRSM, whereby
GRSM's operating contract was terminated. A new senior management group
consisting of a President. Chief Financial Officer and VP Operations was put in
place in GRS to establish and execute a business plan that will increase GRS
production and profitability.

ACQUISITION AND INVESTMENT STRATEGY

      The Fund may, where practical and economic, expand its operations by
acquiring or otherwise investing in additional electricity generating facilities
which use environmentally preferred energy sources. The Fund will acquire or
invest in such facilities only if the Fund believes that the acquisition or
investment will likely result in an increase in Distributable Cash per Trust
Unit will otherwise meet the Fund's acquisition and investment guidelines and is
in accordance with the Fund's objectives, as set out in the Fund Trust
Indenture.

      The management of the Administrator/Manager has extensive experience and
contacts in the independent power industry in Canada and the United States and
is required to present appropriate acquisition or other investment opportunities
to the Fund. Continued deregulation around the world may result in an increase
in divestitures by electrical utilities of waterpower or other power generating
facilities and increased construction of power generating facilities which use
environmentally preferred energy sources, thereby enabling the
Administrator/Manager to present the Fund with opportunities meeting the Fund's
acquisition and investment guidelines.

ACQUISITION AND INVESTMENT GUIDELINES

      The Administrator/Manager intends to pursue an acquisition and investment
strategy that will target environmentally-preferred power generating facilities
or developments. The Administrator/Manager intends to employ the following
guidelines in the review and evaluation of possible acquisitions and other
investments:

      (a)   each facility or development will be acquired, or an investment
            therein will be made, only if the Fund believes that the acquisition
            or investment will likely result in an increase in Distributable
            Cash per Trust Unit;

      (b)   facilities in respect of which long term PPAs with major electrical
            utilities exist will be preferred and, in other cases, free market
            electricity price and exchange rate assumptions used in acquisition
            or investment evaluations will be from a recognized independent
            source;

      (c)   the acquisition of, or investment in, each facility or development
            will be based on an independent engineering report confirming the
            condition of the facility or development and the technical
            assumptions utilized in the acquisition or investment evaluation;

      (d)   the expected useful life of each facility or development and
            associated structures will, with reguiar maintenance and upkeep, be
            long enough for an investment therein to conform with the Fund's
            objective of providing long term distributions of Distributable Cash
            to Unitholders; and

      (e)   the acquisition of, or investment in, each facility or development
            will be reviewed and approved by the CPOT Trustees.

      All acquisitions or investments must be made in accordance with the Fund
Trust Indenture.

ERC PARTICIPATION STRATEGY

      The Fund will attempt to obtain a participation in emission reduction
credits ("ERCs") pertaining to assets in which the Fund acquires indirect equity
interests, where such participation can be commercially negotiated. ERCs are
credits that are created as a result of a business engaging in an activity that
leads to an overall decrease in emissions from a utility/facility that is under
an obligation to either reduce, or not increase, its emissions. ERCs could be
created if a business installs a facility utilizing renewable resources or a
co-generation plant or engages in an energy efficiency retrofit that displaces
marginal fossil fuel generation at a utility. These ERCs can be traded; although
at present markets for ERCs are in an early stage of development. Both Ontario
Power Generation Inc. and TransAlta Utilities Corporation have purchased such
credits to assist them in achieving their environmental

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performance objectives. Revenue from any sales of ERCs related to the
Waterpower Facilities will be divided equally between Regional and the Fund.

                           DESCRIPTION OF THE BUSINESS

THE FACILITIES

WINDPOWER FACILITIES

      ERIE SHORES WIND FARM

      The Erie Shores Wind Farm ("Erie Shores") is an on-shore wind project
located near the shores of Lake Erie, in Ontario. Construction has started in
2005, and once completed the farm will have 99 MW comprising of 66 GE wind
turbines of 1.5 MW capacity each by the time of its projected operational date
in the second quarter of 2006. The power will be sold to the Ontario Power
Authority under a 20-year Renewable Energy Supply Contract ("RES Contract"), as
the developer was a successful bidder under Ontario's first Renewable Energy
Supply Request for Proposals ("RES 1") in the fall of 2004.

      The maintenance and service provider of Erie Shores is GE Wind which will
provide services under a 4-year revenue maintenance contract.

U.S. Windpower Facilities

      FOOTE CREEK II

      Overview

      Foote Creek II is located on the Foote Creek Rim in Carbon County,
Wyoming. The facility consists of 3 Mitsubishi 600 wind turbines generators that
achieved full commercial operation in June 1999. Each wind turbine has a
capacity of 600 kW and was manufactured by Mitsubishi Heavy Industries. Ltd.
("MHI") of Japan. The facility as a whole has a capacity of 1.8 MW and MHI have
provided a comprehensive, 15-year parts, labour, maintenance, availability and
performance warranty on all MHI equipment installed at Foote Creek II. The
warranty includes a direct revenue reimbursement provision which compensates the
facility for lost production tax credits and PPA revenue should the wind
turbines not reach the warranted threshold form availability and performance of
97.0 percent for the first ten years after substantial completion and 95,0
percent thereafter. Should there be a breakdown, MHI must repair or replace the
faulty equipment.

      Each wind turbine contains an on-board microprocessor controller which
monitors and controls operation of the wind turbine. The facility also includes
a computer monitoring system ("CMS") that allows remote supervision and
operations of the individual wind turbines. The CMS is designed to monitor and
record the performance of the wind turbines and the facility as a whole. The
data collected by the CMS provides detailed operating and performance
information for reporting purposes.

      The electrical energy generated by the wind turbines is collected and
delivered by underground 34.5 kV collection lines. The power collection system
consists of individual power cable that run from each wind turbine to padmount
transformers located adjacent to each wind turbine which increases the voltage
of the electricity to the required level for collection. A system of underground
34.5 kV collection lines then delivers the power to the Foote Creek Springs
substation. At the Foote Creek substation the voltage is stepped up to
transmission voltage for delivery to Bonneville Power Administration ("BPA").

      The owner of Foote Creek II has acquired all rights to use and have access
to the facility site by means of a 25-year lease and necessary transmission and
access easements, and the necessary and required permits of governmental
agencies to own and operate the facility.

      Foote Creek II has not been certified under the EcoLogo program as
certification for all facilities is not required for the Fund to retain its
EcoLogo qualification.

      Power Purchase Agreement

      All electricity generated by the Foole Creek II facility is sold to SPA
under a long-term contract with a term of 15 years that commenced in June 1999,
The power sales contract can be extended for 2 additional 5-year terms. The PPA
contains specific fixed rates for each year of operation from the commissioning
of the facility,

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EX-3.12 20th Page of 80 TOC 1st Previous Next ↓Bottom Just 20th
which occurred in June 1999. Contract pricing is a fixed schedule rate that at
the time of commissioning was US$0.016 per kWh escalating by a GDPIPD adjustment
per year rale. The payment rate for energy output at December 31, 2005 was US
$0.01780 per kWh. The PPA contains no minimum or maximum power deliver
obligation and has standard force majeure and termination provisions. In the
event of termination, Foote Creek II would have the ability to operate and sell
electricity into the competitive market.

      FOOTE CREEK III

      Overview

      Foote Creek III is located on the Foote Creek Rim in Carbon County,
Wyoming. The facility consists of an array of 33 NEG Micon Model NM 750/44 wind
turbine generators (which achieved commercial operation in June of 1999). Each
wind turbine has a capacity of 750 kW and the facility as a whole has a total
capacity of 24.75 MW. NEG Micon USA, Inc. ("NEG Micon"), the equipment supplier,
has provided a comprehensive five-year parts, labour, maintenance, availability
and performance warranty on the wind turbines that expired in July 2005.

      Each wind turbine contains an on-board microprocessor controller which
monitors and controls operation of the individual wind turbine. The facility
also includes a CMS that allows remote supervision and operations of the
individual wind turbines. The CMS is designed io monitor and record both the
performance of the individual wind turbines and the facility as a whole. The
data collected by the CMS provides detailed operating and performance
information for reporting purposes.

      The electrical energy generated by the wind turbines is collected and
delivered by underground 34,5 kV collection lines. The power collection system
consists of individual power cables that run from the controller of each wind
turbine to padmount transformers located adjacent to each wind turbine which
increases the voltage of the electricity up to the level required for
collection. A system of underground 34.5 kV collection lines then delivers the
power to the Foote Creek substation.

      The owner of Foote Creek III has acquired all rights to use and to have
access to the facility site by means of a 25-year sublease and necessary
transmission and access easements, and the necessary and required permits of
governmental agencies to own and operate the facility.

      Foote Creek III has been certified under the EcoLogo Program.

      Power Purchase Agreement

      Foote Creek III, LLC sells electrical energy produced by the Foote Creek
III wind turbines to the Public Service Company of Colorado ("PSCo") under a
15-year PPA that commenced in July 1999. The payment rate for energy output and
transmission reimbursement at December 31, 2005 was US $0.050209 per kWh. The
energy rate is adjusted annually in June by a specified inflation adjustment
factor. The transmission reimbursement rate is fixed during the term of the PPA
($0.007689 per kWh). The PPA contains standard "take or pay" provisions under
which PSCo will hold the facility harmless if it fails to take delivery when the
facility stands ready to deliver except upon the occurrence of a force majeure
event.

      FOOTE CREEK IV

      Overview

      Foote Creek IV is located on the Foote Creek Rim in Carbon County,
Wyoming. The facility consists of an array of 28 MHI Model MWT-600 wind turbine
generators that achieved commercial operation in September 2000. Each wind
turbine has a capacity of 600 kW and was manufactured by Mitsubishi Heavy
Industries, Ltd. ("MHI") of Japan. The facility as a whole has total capacity of
16.8 MW. MHI and Mitsubishi Heavy Industries America, Inc. have provided a
comprehensive 15-year parts, labour, maintenance, availability and performance
warranty on all MHI equipment installed at Foote Creek IV. The warranty includes
a direct revenue reimbursement provision which compensates the facility for both
lost production tax credits and PPA revenue should the wind turbines not reach
the warranted threshold for availability and performance of 97 percent for the
first ten years after substantial completion and 95 percent thereafter. Should
there be a breakdown, MHI must replace faulty equipment with new equipment
having a minimum 20-year useful life.

      Each wind turbine contains an on-board microprocessor controller which
monitors and controls operation of the individual wind turbine. The facility
also includes a CMS that allows remote supervision and operations of the
individual wind turbines. The CMS is designed to monitor and record the
performance of the wind turbines and

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the facility as a whole. The data collected by the CMS provides detailed
operating and performance information for reporting purposes.

      The electrical energy generated by the wind turbines is collected and
delivered by underground 34.5 kV coliection lines. The power collection system
consists of individual power cables that run from each wind turbine to padmount
transformers located adjacent to each wind turbine which increases the voltage
of the electricity to the required level for collection. A system of underground
34.5 kV collection lines then delivers She power to the Foote Creek substation.
At the Fooie Creek substation, the voltage is stepped up to transmission voltage
for delivery to Bonneville Power Administration ("BPA").

      The owner of Foote Creek IV has acquired all rights to use and have access
to the facility site by means of a 25-year sublease and necessary transmission
and access easements, and the necessary and required permits of governmental
agencies to own and operate the facility.

      Foote Creek IV has not been certified under the EcoLogo Program as
certification for all facilities is not required for the Fund to retain its
EcoLogo qualification.

      Power Purchase Agreement

      All electricity generated by the Foote Creek IV facility is sold to BPA
under a long-term contract with a term of 20 years that commenced in October
2000. The Foofe Creek IV PPA contains specific fixed rates for each year of
operation from the date of commissioning of the facility, which occurred in
September 2000. The fixed rates commence at US$0.035 for the first six years of
the agreement, with a modest increase in the seventh year and thereafter are
adjusted annually for inflation. The PPA contains standard "take or pay"
provisions under which BPA will hold the facility harmless if it fails to take
delivery when the facility stands ready to deliver except upon the occurrence of
a force majeure event. The PPA may be terminated by BPA at will at the end of
five years of operation upon the payment of liquidated damages In an amount
which should be sufficient to repay all indebtedness senior to the Foote Creek
IV Loan, including expected make whole payments in respect of such senior
indebtedness. In such circumstances, Foote Creek IV will have the ability to
continue to operate and sell electricity into the competitive market.

      PEETZ TABLE

      Overview

      Peetz Table is located at Peetz Table, Logan County, Colorado. The
facility has a total rated capacity of 29.7 MW.

      The facility consists of 33 NEG Micon 900/52 wind turbines, each with a
capacity of 900 kW, interconnected by a series of utility-grade transmission
facilities. These facilities include foundations, transformers, underground
power and communication cables, roads, and communications equipment.

      The power collection system consists of individual power cables that run
from each wind turbine to padmount transformers located adjacent to each wind
turbine that increase the voltage of the electricity to the required level for
transmission to the Peetz Table substation. A system of underground 34.5 kV
collection lines delivers the power to the Peetz Table substation. At the Peetz
Table substation, the voltage is stepped up to transmission voltage for delivery
to the bulk transmission system.

      Each wind turbine contains an on board microprocessor controller which
monitors and controls operation of each individual wind turbine. The facility
also includes a CMS that allows remote supervision and operations of the
individual wind turbines. The CMS is designed to monitor and record the
performance of the wind turbines and the facility as a whole. The data collected
by the CMS provides detailed operating and performance information for reporting
purposes.

      The remaining NEG Micon warranty consists of a three-year major components
guarantee that covers the cost and delivery of replacement parts during that
period but not associated labour costs (expires in December 2006). For a period
of three three years commencing in December 2003, enXco provides the facility
with an availability warranty of 97 percent that will includes a revenue
reimbursement provision at a fixed price per kWh.

      The owner of Peetz Table has acquired all rights to use and have access to
the facility site by means of an assignment for a term expiring January 25, 2024
of 12 easement agreements and a ground lease of the substation, and the
necessary and required permits of governmental agencies to own and operate the
facility. Peetz Table achieved full commercial operation in September 2001.

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EX-3.12 22nd Page of 80 TOC 1st Previous Next ↓Bottom Just 22nd
      Peetz Table has not been certified under the EcoLogo program as
certification for all facilities is not required for the Fund to retain its
EcoLogo qualification.

      Power Purchase Agreement

      All electricity generated by Peetz Table is sold to PSCo under a long-term
contract ending November 30, 2016. Under the terms of the PPA, PSCo pays the
owner of Peetz Table for up to 77 GW-hr of energy per year. The starting tariff
rate for such energy output is US$Q.0372 per kWh. This rate is adjusted annually
by an inflation adjustment factor. Power from the facility is sold as "green
power" to PSCo's customers under PSCo's "Windsource" Program. The payment rale
for energy output at December 31, 2005 was US$0.03994 per kWh. The PPA contains
standard "take or pay" provisions under which PSCo will hold the facility
harmless if it fails to take delivery when the facility stands ready to deliver
except upon the occurrence of a force majeure event.

      BIG SPRING

      Overview

      Big Spring is located near the town of Big Spring, Texas. The facility
consists of an array of 42 Vestas V-47 660 kW and 4 Vestas V-66 1650 kW wind
turbines generators that achieved commercial operation in April and June 1999.
Each V-47 wind turbine has a capacity of 660 kW. Each V-66 wind turbine has a
capacity of 1.65 MW and is manufactured by Vestas of Holland. The facility as a
whole has a capacity of 34.32 MW. None of the turbines have remaining
warranties.

      Each wind turbine contains an on-board microprocessor controller which
monitors and controls operation of the wind turbine. The facility also includes
a CMS that allows remote supervision and operations of the individual wind
turbines. The CMS is designed to monitor and record the performance of the wind
turbines and the facility as a whole. The data collected by the CMS provides
detailed operating and performance information for reporting purposes.

      The electrical energy generated by the wind turbines is collected and
delivered by underground 25 kV collection lines. The power collection system
consists of individual power cable that run from each wind turbine to padmount
transformers located adjacent to each wind turbine which increases the voltage
of the electricity to the required ievel for collection. A system of underground
25 kV collection lines then delivers the power to the Big Spring substation. At
the Big Spring substation the voltage is stepped up to transmission voltage for
delivery to TXU Corp. ("TXU").

      The owner of Big Spring has acquired all rights to use and have access to
the facility site by means of a l5- year lease with 2 additional extension
periods of 5 years each and necessary transmission and access easements, and the
necessary and required permits of governmental agencies to own and operate the
facility. Big Spring achieved full commercial operation in June l999.

      Big Spring has not been certified under the EcoLogo program as
certification for all facilities is not required for the Fund to retain its
EcoLogo qualification.

      Power Purchase Agreement

      All electricity generated by the Big Spring facility is sold to TXU under
a long-term contract with a term of 15 years that commenced in June 1999. The
power sales contract can be extended for 2 additional 5-year terms by TXU. If
not extended by TXU, the contract may be extended by Big Spring, however in such
case, the power will be purchased by TXU at a price based upon its standard
tariff rate. The Big Spring PPA contains specific fixed rates for each year of
operation from the commissioning of the facility. At the time of commissioning,
contract pricing up to monthly, expected energy quantity was US $0.0426 per kWh
escalating by 3.0 percent per year for the first 13 years and at a rate of 0.5
percent thereafter. The rate for excess energy is based on a non-firm Qualifying
Facility rate and is expected to be 3-7 percent lower. The payment rate for
energy output at December 31, 2005 was US$0.0509 per kWh. The PPA contains no
minimum or maximum power deliver obligation and has standard force majeure and
termination provisions. In the event of termination, Big Spring would have the
ability to operate and sell electricity into the competitive market. TXU has the
option to purchase the facility whenever the term of the PPA expires.

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EX-3.12 23rd Page of 80 TOC 1st Previous Next ↓Bottom Just 23rd
      CHANDLER

      Overview

      Chandler is located near Buffalo Ridge, Minnesota. The facility consists
of 3 Vestas V-47 660 kW wind turbines generators that achieved commercial
operation in December 1999. Each V-47 wind turbine has a capacity of 660 kW
and is manufactured by Vestas of Holland. The facility as a whole has a capacity
of 1,98 MW. The V-47 turbines have no remaining warranties.

      Each wind turbine contains an on-board microprocessor controller which
monitors and controls operation of the wind turbine. The facility aiso includes
a CMS that allows remote supervision and operations of the individual wind
turbines. The CMS is designed to monitor and record the performance of the wind
turbines and the facility as a whole. The data collected by the CMS provides
detailed operating and performance information for reporting purposes.

      The electrical energy generated by the wind turbines is collected and
delivered by underground 25 kV collection lines. The power collection system
consists of individual power cables that run from each wind turbine to padmount
transformers located adjacent to each wind turbine which increases the voltage
of the electricity to the required levei for collection. A system of underground
25 kV collection Sines then delivers the power to the Chandler substation. At
the Chandler substation the voltage is stepped up to transmission voltage for
delivery to Cooperative Power Associates.

      The owner of Chandler has acquired all rights to use and have access to
the facility site by means of a 15-year lease, necessary transmission and access
easements, and necessary and required permits of governmental agencies to own
and operate the facility.

      Chandler has not been certified under the EcoLogo program as certification
For all facilities is not required for the Fund to retain its EcoLogo
qualification.

      Power Purchase Agreement

      All electricity generated by the Chandler facility is sold to the
Cooperative Power Associates under a long-term contract with a term of 15 years
which commenced in December 1999. PPA contract pricing which commenced at the
time of plant commissioning in December 1999 is a fixed flat rate of US$0.0347
per kWh for production sold up to an annual 7.47 GWh with excess sold at the
then established avoided cost. Additionally, the project receives US$0.0150 per
kWh from the state of Minnesota for every kWh generated and sold by the
facility. The all-in payment rate for energy output at December 31, 2005 was
US$0.0497 per kWh, The PPA contains no minimum or maximum power deliver
obligation and has standard force majeure and termination provisions. In the
event of termination, Chandler would have the ability to operate and sell
electricity into the competitive market.

WATERPOWER FACILITIES

      THE SECHELT FACILITY

      Overview

      The Sechelt Facility is a run-of-the-river facility, located on Sechelt
Creek, which runs into Salmon Inlet about 30 kilometres northeast of Sechelt,
British Columbia and about 70 kilometres northwest of Vancouver. The Sechelt
Facility has an installed capacity of 16 MW and is one of the largest
independently owned and operated waterpower generating facilities in British
Columbia.

      Regional Power began construction of the Sechelt Facility in the summer of
1995 and commercial operation began in March 1997. Electricity from the facility
is delivered through a 300-metre transmission line to BC Hydro's grid. The
Sechelt Facility has been operated by Regional Power since its completion and
continues to be operated by Regional Power pursuant to the Waterpower O&M
Agreement.

      The Sechell Facility has been certified under the EcoLogo Program and in
2005 won the International Hydro Association's "Blue Planet" Award for
environmental excellence. Environmental enhancements undertaken at the Sechelt
Facility include a salmon spawning channel, one of the first of its kind
established in connection with a small waterpower generating facility in British
Columbia. This consists of a 400 metre, natural inflow channel below the
tailrace adjacent to the existing creek, which was established by removing
sediment and replacing it with natural spawning gravel from the area. The
channel was built with the assistance and support of Fisheries Canada and the
Sechell First Nation. It has been stocked both naturally with salmon returning
to the creek and with coho,

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chinook and pink salmon transplanted from a local hatchery that is owned and
operated by the Sechelt First Nation. Monitoring to date confirms significant
improvement in the salmon production of Sechelt Creek.

      The Sechelt Facility has two vertical Pelton turbine/generator sets of 8
MW each, a gross operating head of 343 metres and is designed to use a flow of
up to six cubic metres per second. The expected annual energy production from
the facility is 90.3 gigawatt hours. Two intake structures (Sechelt Creek and
Jackson Creek), including a low control weir on Sechelt Creek, collect water in
a small headpond which feeds a buried low pressure steel penstock. The low
pressure penstock merges into a buried, high pressure steel penstock which
carries the water to the powerhouse where a bifurcation distributes the water to
the turbine/generators. The water is then returned to Sechelt Creek through the
laiirace. The portions of Sechelt Creek and Jackson Creek above the intake
structures drain an area of the Coast Mountains of approximately 67 square
kilometres.

      Sechelt Power Purchase Agreement

      The sale of power from the Sechelt Facility to BC Hydro is governed by a
PPA dated August 31, 1990 (the "Sechelt PPA"), as amended. The Sechelt PPA has
an initial term of 20 years from the commercial operation date, which was March
1, 1997. Following the initial term, the Sechell PPA wiH continue in force from
year to year unless otherwise terminated upon six months" notice by either
party. Also, BC Hydro has agreed to purchase all power made available by the
Sechelt Facility at the delivery point. Under the Sechelt PPA, the Sechelt
Facility is required to make available to BC Hydro not less than 57 gigawatt
hours per year.

      Under the Sechelt PPA, BC Hydro pays monthly for the electricity delivered
under the agreement. The price as at December 31, 2005 was $0.0609 per kilowatt
hour. The price is increased on April 1 of each year by three percent over the
prior year. In addition, BC Hydro will pay any extraordinary incremental costs
reasonably and property incurred by the Sechelt Facility that arise as a result
of extraordinary changes to government policy, law and regulation and BC Hydro's
established quality requirements for eleciricity made available by the Sechelt
Facility in excess of the three percent annual increase. The Secheit Facility is
required to provide a credit to BC Hydro if any costs are reduced as a result of
extraordinary changes in government policy, iaw and regulation.

      The electricity made available to BC Hydro must conform to BC Hydro's
established quality requirements and BC Hydro may refuse to accept deliveries of
electricity that do not conform to these requirements. If a disconnection occurs
under these requirements and the Secheit Facility does not take corrective
action so that it is in compliance with these requirements within six months, BC
Hydro may terminate the Sechelt PPA. Routine and emergency operating procedures
for the Sechelt Facility are established through an agreement with BC Hydro,
including local operating orders lhat set forth requirements to be met to allow
the interconnection of the Sechelt Facility to BC Hydro's system.

      The respective obligations of the operator of the Sechelt Facility and BC
Hydro under the Sechelt PPA are suspended if a forced outage occurs. A "forced
outage" is defined as an exceptional situation which makes either party's plant
unavailable to perform as required by the Sechelt PPA and which could not be
reasonably anticipated or protected against and is beyond the reasonable control
of the party claiming that a forced outage has occurred. If a forced outage of
the Sechett Facility continues for more than 18 months then either party may
terminate the Secheit PPA without notice. Forced outages attributable to BC
Hydro, require BC Hydro to pay for power not taken if after 24 hours the outage
has not been corrected.

      Land and Water Rights

      The land rights in respect of the Sechelt Facility (including the intake
from Sechelt Creek and Jackson Creek, the powerhouse, penstock and the tailrace)
are held pursuant to two Crown leases each dated October 10, l995, as well as a
statutory right of way from the Crown dated April 17, 2001. Rights to the water
used by the Sechelt Facility have been granted under conditional water licences
dated July 19, 1994 and August 11, 1995 granted by the Office of the Comptroller
of Water Rights, Each of these conditional water licences is appurtenant to the
October 10, 1995 lease relating to the powerhouse, which has a term of 30 years.
A permit issued by the British Columbia Comptroller authorizes the occupation of
Crown land fora dam site at, and the flooding of, Sechelt Lake.

      Access to the Sechelt Facility is provided pursuant to an agreement dated
April 1, 1995 with Canadian Forest Products Ltd. (the "Canfor Agreement") that
is in effect until 2016. Access rights to use the existing roads and to
construct additional roads expire on the earlier of the termination of the
Sechelt PPA and the termination of the Canfor Agreement. A right of way for
transmission lines from the Sechelt Facility to the BC Hydro interconnection
point is secured by a registered statutory right of way that expires on the
termination of the Sechelt PPA.

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      THE WAWATAY FACILITY

      Overview

      The Wawatay Facility is a run-of-the-river facility located on the Black
River. 30 kilometres east of Marathon, Ontario and 10 kilometres north of the
northern shove of Lake Superior. It was one of the early development projects
contracted by the former Ontario Hydro under its non-utility generation program
and is one of the largest independent waterpower power facilities in Ontario.

      Construction of the Wawatay Facility began in the fall of 1990 and
commercial operation began in the spring of 1992. Electricity from the Wawatay
Facility is delivered through the facility's own six kilometre transmission line
which connects into the Hydro One Inc. main grid north of the station. The
Wawatay Facility has been operated by Regional Power since its completion and
continues to be operated by Regional Power pursuant to the Waterpower O&M
Agreement.

      The Wawatay Facility has an installed capacity of 13.5 MW. It has three
horizontal Francis turbine/generator sets of 4.5 MW each, a gross operating head
of 48 metres and is designed to use a flow of up to 34.5 cubic metres per
second. Expected annual energy production from the station is 59.0 gigawatt
hours. The intake structure is located upstream of an existing dam on the Black
River. Water at the intake flows through a 0.625 kilometre rock tunnel/steel
penstock. A trifurcation in the penstock distributes the water to the turbines,
and the water is then returned to the river through the tailrace built into the
bank of the Black River. The drainage area of the Black River is 1,980 square
kilometres.

      The Wawatay Facility has been certified under the EcoLogo Program.

      Wawatay Power Purchase Agreement

      Power produced from the Wawatay Facility is sold exclusively to OEFC under
a PPA dated April 1, 1992 (the "Wawatay PPA") under which OEFC has committed to
purchase all power delivered at the delivery point. The Wawatay PPA has an
initial term of 50 years from the commercial in-service date, which was July 2,
1992. Following the initial term, the Wawatay PPA will automatically continue in
force for renewal terms of one year each provided that either party may, with at
least one year's prior written notice, terminate the Wawatay PPA upon the expiry
of the initial term or any renewal term.

      The Wawatay PPA has different pricing provisions for power produced during
summer and winter, as well as for power produced during on-peak and off-peak
hours. Higher rates are paid for electricity sold to OEFC during the winter or
during on-peak hours than those for electricity sold during the summer or during
off-peak hours. The Wawatay PPA contains pricing provisions designed to assure
that payments under the agreement are sufficient to repay the Wawatay Loan over
the term of the Wawatay Loan, which term coincides with the first twenty years
of the Wawatay PPA (the "Wawatay Amortization Period"). Payments made by OEFC
during the Wawatay Amortization Period are comprised of: (i) a yearly amount
(paid in monthly instalments) necessary to fully amortize and pay the Wawatay
Loan over the Wawatay Amortization Period (the "guaranteed payment"); (ii) a
monthly payment based upon the actual generation of power up to 120 percent of
target generation, multiplied by the performance rate as set out in the Wawatay
PPA (the "performance payment"); and (iii) a monthly payment based on generation
in excess of 120 percent of target generation, multiplied by the rate for excess
generation as specified from time to time by OEFC (the "excess payment"). The
average price paid under the Wawatay PPA during the year ended December 31, 2005
was $0.0622 per kilowatt hour.

      So long as the guaranteed payment is in effect the owner of the Wawatay
Facility is deemed to be in default of the Wawatay PPA if (i) actual generation
is less than 85 percent of the target generation for two consecutive years,
other than due to the fault of OEFC, unless the owner of the Wawatay Facility
can show that the cause of the generation deficiency is from lower than average
total annual precipitation on the watershed and/or lower than average daily
flows on the Black River, or (ii) actual generation is less than 90 percent of
the target generation for five consecutive years for any reason, other than due
to the fault of OEFC. The defaults are subject to applicable cure periods as
stipulated in the Wawatay PPA. Failure to comply with the obligations under the
Wawatay PPA or ancillary agreements with OEFC could, in certain circumstances,
result in termination of the Wawatay PPA.

      Neither party under the Wawatay PPA will be held responsible or liable or
be deemed in default or breach of the agreement if an event of force majeure
prevents it from fulfilling its obligations thereunder. An event offeree majeure
is defined in the Wawatay PPA as any cause which is unavoidable or beyond a
party's reasonable control which wholly or partially prevents the parlies or
either of them from carrying out the terms of the agreement.

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      The guaranteed payments and the performance payments under the Wawatay PPA
during the Wawatay Amortization Period result in payments from OEFC for power at
rates higher than OEFC's base rate. Accumulated payments in excess of OEFC's
base rate are known as "generator debt" (referred to as 'icvelizalion amount" in
the consolidated financial statements of the Fund), and are required to be
repaid to OEFC by the end of the term of the Wawatay PPA. At the end of the
Wawatay Amortization Period it is expected that OEFC will pay for power
delivered up to 120 percent of the target generation at the performance rate.
The sum of money for each month is determined by multiplying the power
delivered, up to 120 percent of the target generation, by the difference between
the base rate and the performance rate will then be applied from time to time
against the outstanding generator debt balance until the generator debt reaches
zero or until the end of the Wawatay PPA in 2042. At the time of signing the PPA
it was originally expected that accumulated generator debt would be fully or
partially offset by increases in Ontario Hydro's direct customer rate ("DCR").
However, as anticipated increases in the direct customer rate had not occurred,
by the time the Fund acquired the Wawatay Facility it was not anticipated that
the generator debt balance associated with the Wawatay Facility would be reduced
to zero by the end of Wawatay PPA. As at December 31, 2005, the balance of
Wawatay PPA generator debt associated with the Wawatay Facility was $15,292,000.
In December 2003 a new agreement was reached with the OEFC to replace
(retroactive to January 1, 2002) the DCR with an escalator based on the year
over year change of a number of factors including Ontario energy prices,
wholesale market prices, the transmission service charge as well as other
components. The agreement established a floor and ceiling range for the
escalator and has the effect of increasing performance payments received under
the Wawatay PPA. Depending on the escalator applied, generator debt could be
eliminated before the end of the PPA term. Negotiations with OEFC continue with
respect to the treatment of the generator debt.

      OEFC has the right to take a security interest in the Wawatay Facility to
secure payment of the outstanding generator debt. Unless the generator debt is
either paid, or a compromise is negotiated with OEFC, OEFC will have the right
to realize upon the Wawatay Facility pursuant to such security, if taken, upon
termination of the Wawatay PPA in 2042. While in December 2003 a new agreement
was reached with OEFC to replace the DCR with a new escalator, negotiations
continue with respect of the treatment of generator debt.

      If during the Wawatay Amortization Period the power delivered by the
Wawatay Facility is less than the target generation specified in the Wawatay
PPA, the difference between the actual generation and the target generation
multiplied by the guaranteed rate (defined as the guaranteed payment divided by
the target generation), is accumulated in a deficiency value account. In any
month in which power generated by the Wawatay Facility exceeds 120 percent of
target generation, then the amount of excess generation multiplied by the excess
rate, as specified from time to time by OEFC, will be applied to reduce the
deficiency value, if any, or be paid directly to the owner of the Wawatay
Facility if there is no deficiency value.

      If there is an accumulated deficiency value in existence for longer than
two years, OEFC has the option to reduce the accumulated deficiency value by the
profit portion of any performance payment until such time as the accumulated
deficiency value is reduced to zero. The profit portion of a performance payment
is determined by subtracting the Wawatay Facility's operating and maintenance
costs for a year from the performance payments for the same year. To the extent
that ail or part of a performance payment or excess payment is applied to reduce
an accumulated deficiency value, there shall automatically be a reduction in the
amount of the generator debt to the same extent. In addition, if any accumulated
deficiency amount exists for two consecutive years as a result of actual
electricity production being less than 85 percent of target electricity
production levels for such years for reasons other than lower than average
precipitation, OEFC is entitled to give notice of default. If any accumulated
deficiency exists for five consecutive years that is the result of actual
electricity production being less than 90 percent of target electricity
production levels for such years, regardless of the cause of such deficiency,
OEFC is entitled to give notice of default. Such a default may be cured by the
owner of the Wawatay Facility making payment of an amount equal to the
accumulated deficiency arising as a result of actual production being less than
85 percent or 90 percent of target production levels, as the case may be. If the
default is not cured, OEFC is entitled to either (i) request that the prime
lender to the Wawatay Facility declare an event of default and assign its
security to OEFC, such assignment to concurrently provide for OEFC to assume the
generator's obligations to the prime lender, failing which OEFC may terminate
the Wawatay PPA, or (ii) if there is no longer a prime lender to the Wawatay
Facility, terminate the Wawatay PPA and enforce its security.

      As at December 31, 2005, the accumulated deficiency value for the Wawatay
Facility was $1,267,245.

      First Nations Net Profits Interest Agreement

      Under a net profits interest agreement made in 1990, the Ojibways of the
Pic River First Nation (the "Pic River FN") hold a net profits interest in the
Wawatay Facility (the "Wawatay Net Profits Interest"). The Wawatay Net Profits
Interest entitles the Pic River FN to 10.0 percent of the positive balance in
the Wawatay Net Profits

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Interest account, if any. payable monthly, less the cumulative amounts
previously paid on account of the Wawatay Net Profits Interest. The Wawatay Net
Profits interest account equals the excess obtained by subtracting from the
cumulative revenues of the Wawatay Facility the sum of the cumulative costs and
the cumulative deemed interest charges. The Wawatay Net Profits Interest account
currently has a negative balance as a result of original development and
construction costs. It is estimated that the balance in such account may become
positive before 2010. The Pic River FN is paid advances against amounts that may
be due in respect of the Wawatay Net Profits Interest in the sum of $25,000 per
year. As at December 31. 2005, the total advances paid to date to the Pic River
FN was $375,000.

      Under the terms of the Wawatay Net Profits Interest agreement, the Pic
River FN acknowledges that if its claim to any aboriginal interest in or rights
to any lands or waters or activities carried on in, on or over any lands or
waters shall at any time be upheld by a court, the Pic River FN WILL not
exercise any such interest or rights so as to in any manner interfere with the
operation of the Wawatay Facility or any modification or expansion thereof. The
agreement requires the owner of the Wawatay Facility to use its best efforts to
give priority to employing members of the Pic River FN who are equally qualified
with other persons being offered employment and to require its contractors and
subcontractors to use their best efforts to give such priority in employing
personnel to work on the Wawatay Facility.

      Under the terms of the Wawatay Net Profits Interest agreement the Pic
River FN is entitled to 90 days' notice of any proposed sale of the Wawatay
Facility and to purchase all the assets proposed to be sold at the price and
upon the terms specified in the notice within said 90-day period. The Pic River
FN was given notice of the proposed sale of the Wawatay Facility to CPOT and
waived its right to purchase the Wawatay Facility.

      Land and Water Rights

      The land and water rights in respect of the Wawatay Facility are held (i)
pursuant to a water power lease with the Crown made January 1, 1992 for a term
of 20 years from June 18, 1992 with three rights of renewal of 10 years each and
which provides for certain annual payments; (ii) freehold with respect to
certain lands acquired from 907153 Ontario Inc. ("Q&O") together with easements
from Q&O: and (iii) pursuant to two perpetual Crown easements, each dated May 1,
1992, for roads and transmission lines from the site to a public highway and
Hydro One Inc.'s main grid interconnect. The respective rights and obligations
of the owner of the Wawatay Facility and Q&O, with respect to their respective
easements, are governed by a transfer of easement agreement dated June 23, 1992.
Crossing permits for the road and transmission line have been obtained from The
Ontario Ministry of Transportation, with respect to Highway 17, and from
Canadian Pacific Railway Company, with respect to its railway line.

      THE DRYDEN FACILITY

      Overview

      The Dryden Facility is comprised of three run-of-the-river waterpower
generating stations with a total installed capacity of 3.25 MW. The Wainwright
generating station was built in 1922 on the Wabigoon River in Dryden, Ontario
five kilometres downstream of the outlet of Wabigoon Lake. The Eagle River
generating station was built in 1928 at the outlet of Eagle Lake about 30
kilometres west of Dryden. The McKenzie Falls generating station was built in
1938 on the Eagle River two kilometres downstream of the Eagle River generating
station. The generating stations were originally built by the Dryden Paper
Company Limited to supply electricity to its mill in Dryden. The Dryden Facility
has been operated by Regional Power since its refurbishment in 1986 and
continues to be operated by Regional Power pursuant to the Waterpower O&M
Agreement.

      The generating stations comprising the Dryden Facility obtain water from
large drainage areas, which include large lakes. The size of such drainage areas
mitigates against changes in water flow which might otherwise be caused by
variations in precipitation. The Wainwright generating station has a single,
vertical, fixed blade propeller turbine that operates under a head of 8.8 metres
and with a flow of up to 17 cubic metres per second. The Wabigoon River drainage
area, which provides water for the Wainwright generating station, is 2,600
square kilometres, with regulation from Wabigoon Lake, which has a surface area
of 180 square kilometres. The Eagle River generating station has a single,
vertical Francis turbine that operates under a head of 10 metres and a flow of
up to 17 cubic metres per second. The McKenzie Falls generating station has a
single, vertical, double regulated Kaplan turbine that operates under a head of
8 metres and with a flow of up to 17 cubic metres per second. The Eagle River
drainage area, which provides water for both the Eagle River generating station
and the McKenzie Fails generating station, is 2,600 square kilometres at that
point, with regulation from Eagle Lake, which has a surface

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area of 285 square kilometres. Expected annual production of electricity from
the three generating stations comprising the Dryden Facility is 20.6 gigawatt
hours.

      The Dryden Facility has been certified under the EC Program.

      Dryden Power Purchase Agreement

      Power produced from the Dryden Facility is sold exclusively to OEFC under
a PPA dated October 23, 1990 (the "Dryden PPA"). OEFC has agreed under the
Dryden PPA to purchase all power delivered at the delivery points near each of
the generating stations that comprise the Dryden Facility. The Dryden PPA has an
initial term of 30 years ending on November 1, 2020. Following the initial term,
the Dryden PPA will automatically continue in force for renewal terms of one
year each, provided that either party may, with at least one year's prior
written notice, terminate the Dryden PPA upon the expiry of the initial term or
any renewal term thereafter.

      The Dryden PPA has different pricing provisions for power produced during
summer and winter, as well as for power produced during on-peak and off-peak
hours. Higher rates are paid for electricity sold to OEFC during the winter or
during on-peak hours than those for electricity sold during the summer or during
off-peak hours. The average price paid under the Dryden PPA during the year
ended December 31, 2005 was $0.0673 per kilowatt hour.

      The Dryden PPA has provisions regarding generator debt that function
similarly to those in the Wawatay PPA except that under the Dryden PPA, OEFC's
recourse for payment of outstanding generator debt is not limited to the
security interest granted to OEFC over the Dryden Facility. As at December 31,
2005 the Dryden PPA generator debt was $986,350 and is referred to as
levelization amount in the financial statements of the Fund.

      As the guaranteed payments ended in October 2005 and the generator debt
has not reached zero, the OEFC now pays the bonus rate provided in the Dryden
PPA for power delivered up to a maximum of 110 percent of the target generation.
The sum of money for each month determined by multiplying the power delivered,
up to 110 percent of target generation, by the difference between the base rate
and the bonus rate will be appiied from time to time against the outstanding
generator debt balance until the generator debt reaches zero. After the
generator debt reaches zero, then for the remaining term of the Dryden PPA OEFC
will pay for the actual power generated at the Dryden Facility in each month at
the OEFC base rate. It is anticipated that the generator debt balance in respect
of the Dryden Facility will reach zero before 2010.

      The Dryden PPA also contains provisions regarding generation deficiency
value. If there is an accumulated deficiency value in existence for longer than
two years, OEFC has the option to reduce the accumulated deficiency value by the
profit portion of any performance payment until such time as the accumulated
deficiency value is reduced to zero. If any accumulated deficiency value exists
for two consecutive years for reasons other than insufficient precipitation, or
if any accumulated deficiency value exists for five consecutive years under any
circumstances, OEFC is entitled to either (i) request that the prime lender to
the Dryden Facility declare an event of default and enforce its security,
failing which OEFC may terminate the Dryden PPA, or (ii) if there is no longer a
prime lender to the Dryden Facility, terminate the Dryden PPA and enforce its
security. The Dryden PPA restricts the Dryden Facility from making distributions
in the event that an accumulated deficiency value exists. The accumulated
deficiency value for the Dryden Facility was zero at Closing. The
Administrator/Manager intends to ensure that the Fund will pay any accumulated
generation deficiency that arises in the future under the Dryden Facility. As at
December 31, 2005, the accumulated deficiency value for the Dryden Facility was
$138,300. As the guaranteed payments have ended, no more generation deficiency
value will be added to the accumulated deficiency value under the Dryden PPA.

      Land and Water Rights

      The land and water rights in respect of the Wainwright generating station
are held: (i) pursuant to a water power lease which will expire December 31,
2022, subject to renewal rights, and (ii) freehold with respect to the flood
plain and lands on which a portion of the dam is located. Access to the
Wainwright generating station from Highway 17 is by private road egressing to
Keller road, which intersects with the highway. The transmission line to the
Hydro One Inc. interconnect is a 12.5 kilovolt line running over the Wainwright
generating station land and connects to the Hydro One Inc. distribution line
along Keller Road.

      The land and water rights in respect of the Eagle River generating station
and the McKenzie Falls generating station are held (i) pursuant to a water power
lease with the Crown which will expire December 31, 2022, subject to renewal
rights; and (ii) freehold with respect to the flood plain. A transmission line
connects the McKenzie Falls generating station to the Eagle River generating
siation. While this line was originally laid out under rights granted to Dryden
Paper Company Limited, those rights were withdrawn from title, perhaps

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inadvertently, by Dryden Paper Company Limited. Although the
Administrator/Manager believes that it is unlikely to affect the transmission
line, the lack of registered title could require the construction of a new
transmission line in the even of a challenge by owners of the land over which
the transmission line runs. Regional Power has agreed to indemnify the Fund in
the event of such an occurrence. Hydro One Inc.'s main grid interconnect is
located on the land rights held by the owner of the Dryden Facility. Access to
the Eagle River generating station and the McKenzie Fails generating station is
directly off of Highway 594.

      THE HLUEY LAKES FACILITY

      Overview

      The Hluey Lakes Facility is located in the Dease Lake area in northwestern
British Columbia, approximately 15 kilometres southwest of the town of Dease
Lake and has an installed capacity of 3.0 MW. Electrical power generated by the
Hluey Lakes Facility is sold to BC Hydro for distribution to BC Hydro's clients
in the community of Dease Lake through a non-integrated distribution system
that had previously been served by a diesel generating station. The use of the
waterpower facility helped reduce the environmental pollution caused by the
combustion of diesel fuel and the environmental risks associated with fuel
transport.

      Construction of the Hluey Lakes Facility began in the autumn of 1995. The
facility was acquired in 1999 by a subsidiary of Manulife Financial Corporation,
which retained Regional Power to complete the design and construction of the
facility. Construction was completed in 1999 and the facility began operations
in December 1999. The Hluey Lakes Facility's commercial operation date was
January 15, 2000, following a rigorous proving period that began in December
1999. Regional Power has operated the Hluey Lakes Facility since its commercial
operation date and continues to operate it pursuant to the Waterpower O&M
Agreement.

      The Hluey Lakes Facility is located in the Tanzilla River watershed, and
consists of two dams, a buried high-density polyethylene low pressure penstock
("HDPE Penstock), a surge shaft, a low pressure penstock, powerhouse and
turbine/generator, a tailrace conduit, switchyard, transmission lines and access
roads. From the power intake dam, water is conducted by way of the HDPE Penstock
to the 14-metre deep surge shaft at the edge of the major elevation drop to the
Tanzilla River. From the surge shaft, a tow pressure penstock carries the water
to the powerhouse. The powerhouse houses a single 3 MW Pelton turbine and
generator, and discharges water via the 1.4 kilometre tailrace to the Tanzilla
River. From the powerhouse switchyard, power is transmitted by way of a
28-kilometre wood-pole transmission line to the BC Hydro substation at Dease
Lake.

      Water for the Hluey Lakes Facility is stored by means of a low diversion
dam on Tsenaglode Creek, which drains Sitsa and Tuttiduch Lakes into the
Tanziila River, and a low power intake dam on Hluey Creek, which drains Hluey
Lake into the Tanzilla River. The Tsenaglode diversion dam is an earth filled
dam about 400 metres long with a maximum height of five metres. The Hluey Lakes
power intake dam is an earth filled dam about 436 metres long with maximum
height of 7.5 metres. These dams raise the water levels in the lakes by about
five metres. Together they provide a single water reservoir for Hluey Lakes of
about 4.95 square kilometres. The total watershed covers an area of 135 square
kilometres. Overflow type spillways at both dams have their crests at an
elevation so that spill is automatic when the reservoir is full and the inflow
exceeds the regulated outflow, thus meeting the conditions in the Habitat
Compensation Agreement.

      The Hluey Lakes Facility must respond immediately to load changes because
it is the single source of power generation for the town of Dease Lake. This is
accomplished by using a 100 kW load bank, a system designed to provide
regulation and toad stabilization. As load demand increases, electricity will
automatically be diverted from the load bank to the transmission lines, and vice
versa. In order to provide power to the load bank the facility is run to
generate slightly more than the expected load with the excess diverted to the
load bank.

      The owner of the Hluey Lakes Facility is responsible for the ongoing
maintenance of the transmission line right up to the BC Hydro substation in a
manner that meets BC Hydro's technical requirements. These requirements include
standard terms regarding maintenance, outages, product quality, protection and
control, and equipment inspection.

      The Hluey Lakes Facility was designed and constructed to meet the demand
for energy, not only for the town of Dease Lake, but also for any contemplated
integration of the nearby towns of Telegraph Creek and Iskut, to reduce the
amount of reliance by these communities on isolated diesel systems. All civil
works, including the reservoir, the water conveyance system and powerhouse
foundations, are in place for the potential installation of a second
turbine/generator in connection with an expansion of the facility. Any
contemplated expansion of the Hluey Lakes Facility would require agreement with
BC Hydro on the terms and conditions for the sale of additional electricity.

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      The Hluey Lakes Facility has been certified under the EcoLogo Program.

      Hluey Lakes Power Purchase Agreement

      Under a power purchase agreement dated November 1, 1993, with BC Hydro
(the "Hluey Lakes PPA"), BC Hydro is obligated to purchase all energy required
to meet the load demand of Dease Lake from the Hluey Lakes Facility until
January 31, 2020. The 3.0 MW installed capacity is expected to meet the
requirements of the town of Dease Lake for at least until the end of the Hluey
Lakes PPA.

      BC Hydro has the exclusive right to purchase electricity from the Hluey
Lakes Facility for an unspecified additional period, at a price and on terms and
conditions to be negotiated. The exclusive right terminates 18 months before the
termination of the Hluey Lakes PPA if an agreement regarding price, terms and
conditions is not reached by then. Under the Hluey Lakes PPA, the Hluey Lakes
Facility may also sell power in excess of the Dease Lake load demand to third
parlies, provided that all regulatory approvals have been obtained, the third
party customers are not supplied by BC Hydro, the requirements of Dease Lake are
first met, and the power quality to Dease Lake is not reduced.

      The payments by BC Hydro for power from the Hluey Lakes Facility are
generally based on the following three components: (i) debt service and return
on equity: (ii) operations, maintenance and insurance payments: and (iii) water
rental, school and property taxes paid in the prior year. Payments are made
monthly based on all three components as described below, provided that no
payments are made on account of debt service and return on equity during failed
reliability testing period(s) (as described below).

      The payment in respect of each component is equal to the amount which
results from dividing (i) a predetermined base value for such component
multiplied by the amount of electricity delivered by the Hluey Lakes Facility to
BC Hydro in that month, by (ii) 102.5 percent of the prior year's load demand,
assuming a plant availability of 98 percent. Therefore, if actual demand grows
by 2.5 percent and the plant achieves 98 percent availability, or demand is flat
and the plant achieves 100 percent availability, the entire revenue is earned.
Should demand decrease (increase) in the future, revenues are affected only
until the decline (growth) subsides, at which time the year-over-year load
demand ratio is 1:1 and the entire revenue is again earned. The average price
for electricity in the year ended December 31, 2005 under the Hluey Lakes PPA
was $0.3120/kWh.

      In determining the payments under the Hluey Lakes PPA as described above,
the debt service and return on equity base value was to be escalated with the
Hydro-Electric Construction Price Index, as published by Statcan, from January
to the commercial operation date (January 2000) and remain constant for the life
of Hluey Lakes PPA. However, the Hydro-Electric Construction Price Index was
discontinued after 1997. As a result, an interim increase had been implemented.
In January 2006, the Fund reached an agreement with BC Hydro on a substitute
index provided by Statcan. The operations, maintenance and insurance payments
base value was to escalate annually with the BC GDP Price Deflator, as published
by Statcan, from January 1993. The BC GDP Price Deflator was discontinued after
1999. In January 2006 the Fund reached an agreement with BC Hydro on a
substitute index provided by Statcan. Because the new indexes are not available
until the middle of the next year, BC Hydro will retroactively adjust the
invoices when the actual statistics become available from Statcan. The
difference between the original amounts paid on the Hluey Lakes PPA and the
adjusted amounts resulting from implementation of the new indexes back to their
effective dates resulted in a "catchup" by BC Hydro to the Fund of approximately
$0.4 million. The water rental, school and property taxes base value is paid on
the basis of actual costs incurred by the Hluey Lakes Facility in the prior
year. Adjustments are made in the last month of each year for any variations in
the formula described above from actual results subject to a maximum downward
adjustment of 15 percent and a maximum upward adjustment of 25 percent.

      The payments to be made by BC Hydro under the Hluey Lakes PPA are subject
to further adjustment under the terms of a collateral agreement dated May 23,
1997 (the "Collateral Agreement"). Under the Collateral Agreement, BC Hydro is
required to pay only 50 percent of the price otherwise established under the
Hluey Lakes PPA (other than the incremental cost of water rentals, which is paid
at full price) for all electricity provided in excess of 102.5 percent of the
prior year's load demand, but not for electricity provided in excess of 125
percent of the prior year's load demand, for which full prices are payable as
described above.

      Under the Hluey Lakes PPA, the Hluey Lakes Facility was required to
undergo a proving period which required the facility, without support from BC
Hydro, to make electricity available to BC Hydro and to maintain the continuous
delivery ofelectricity (i) for 400 hours, twice within a 40-day interval, or
(ii) for 800 hours. At least 400 hours had to occur during the peak winter
period between November 1st and March 1st. The Hluey Lakes Facility achieved
these requirements from December 13, 1999 to January 15, 2000, without any
outages or problems.

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      The Hluey Lakes Facility is entitled to up to 10 days of scheduled outage
in any 12-month period beginning each November 1st, without incurring payments
for incremental costs of operating the back up BC Hydro diesel generating
station. The operator of the Hluey Lakes Facility is required to use its best
efforts not to schedule outages during the winter period. If BC Hydro is unable
to accept electricity due to an outage at its substation, BC Hydro will pay for
any electricity that would have been delivered by the Hluey Lakes Facility. If
the Hluey Lakes Facility is unable to deliver electricity, other than during a
scheduled outage, then the Hluey Lakes Facility must pay BC Hydro the
incremental cost of running its back-up diesei generator.

      If the total duration of forced outages in a year exceeds 20 hours, or if
the total number of forced outages in a year exceeds 15, then the Hluey Lakes
Facility will be required to undergo a reliability testing period. The
requirements of the reliability testing period are the same as those of the
initial proving period other than the requirement for a minimum portion of
electricity to be delivered during the winter period, BC Hydro will pay the full
price for electricity delivered during the reliability testing period(s) except
that the portion of the price for debt service and return on equity is not paid
for electricity delivered during a failed reliability testing period(s).

      Land and Water Rights

      The land and water rights in respect of the Hluey Lakes Facility are held
pursuant to (i) a lease with the Crown dated May 29, 2000, for a term of 30
years, (ii) statutory rights of way for the transmission line and (iii) a
conditional water licence dated August 1, 1995. Access to the Hluey Lakes
Facility is from the public highway, by a road over Crown land subject to a
statutory right of way. The BC Hydro interconnect is located at the substation
at Dease Lake and the 28 kilometre transmission line is situated on leased lands
and rights of way.

      Relationship and Agreements with Tahltan Nation

      The Tahltan Nation (which is comprised of the Tahltan and Iskut Bands for
the purposes of treaty negotiations) has signed a non-disturbance agreement
dated February 27, 1999, regarding any potential acquisition of jurisdiction,
through the treaty process, to the lands on which the Hluey Lakes Facility is
located or to the rights to impose taxes, fees, levies, or other monetary
charges. In this agreement, the Tahftan Nation has agreed that if it obtains any
such jurisdiction, it will treat ail leases, permits, licenses and renewals with
respect to the Hluey Lakes Facility in a manner consistent with the Crown's
present treatment.

      The Tahltan Nation Development Corporation ("TNDC"), as assignee from the
Stikine Nation Power Corporation (a corporation owned by the Tahltan and Iskut
Bands), has the right to purchase all or a portion of the Hluey Lakes Facility
at fair market value within six months following the maturity of the initial
20-year term of the Hluey Lakes PPA. If the Hluey Lakes Facility is to be sold
after the fifth year of the Hluey Lakes PPA, TNDC has the right for a 90-day
period to negotiate the purchase of the Hluey Lakes Facility before it is
offered for sale to others.

      In addition, the Fund has offered TNDC a 33.0 percent net profit interest
in the Fund's net profit from sales of power to industrial customers other than
BC Hydro. As at December 31, 2005, there had been no sales to industrial
customers other than BC Hydro.

THE BIOMASS FACILITIES

      THE WHITECOURT FACILITY

      Overview

      The Whitecourt Facility is a wood waste fired electricity-generating plant
located on lands owned by WPLP near Whitecourt, Alberta about two hours
northwest of Edmonton with an installed capacity of 28.0 MW. The Whitecourt
Facility is comprised of one steam turbine and one generator. Other major
components of the Whitecourt Facility include: a 236,000 Ibs./hr fluidized
bubbling bed boiler with combustion air re-injection; wood receiving, conveying,
stockpiling, reclaiming, hogging and screening systems; an ash handling unit,
cooling tower, circulating water piping and condenser; and self-unloading trucks
for the transport of wood waste materials.

      The Whitecourt Facility was the first power generating facility in Canada
to be certified under the EcoLogo Program.

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      Whitecourt Facility Power Purchase Agreement

      Power produced at the Whitecourt Facility is sold pursuant to a small
power production agreement dated November 6, 1990 (the "Whitecourt PPA") with
TransAlta. The terms of the Whitecourt PPA were specified by the Small Power
Research and Development Act (Alberta) ("SPRDA"). The Whitecourt PPA requires
TransAlta to purchase the first 20.7 MW of power produced by the Whitecourt
Facility on a continuous basis. The Whitecourt PPA has a term of 20 years from
the date on which the Whitecourt Facility received its final allocation under
the SPRDA, which was in December 1994. Pursuant to amendments to the Electric
Utilities Act (Alberta) in 2000, the rights and obligations of TransAlta under
the Whitecourt PPA have been transferred to the Alberta Balancing Pool and
TransAUa simply functions as the flow-through entity between the Whitecourt
Facility and the Balancing Pool. See "Industry Overview- Canada -Alberta".

      The contract price for power under the Whitecourt PPA was set by the SPRDA
and is escalated annually at the Consumer Price Index (Alberta) for each year of
operation commencing December 31, 1994 until the tenth year of the Whitecourt
PPA. For the eleventh and subsequent years of the Whitecourt PPA, the price paid
for the power delivered was to be established by the Alberta Energy Board and
was to have been the greater of the utility avoided cost and the price paid
during the tenth year (2004) of the Whitecourt PPA. The 2005 rate was $0.0684
per kilowatt hour. As a result of industry deregulation in Alberta, the Alberta
Energy and Utility Board ("AEUB") is no longer establishing a utility avoided
cost. The AEUB has also ruled that because the utility avoided cost no longer
exists, the "greater of clause is no longer relevant. This ruling was challenged
by a review and variance application presented by the SPRDA contract holders
before the board. The board rejected the review and variance application and
upheld the original ruling.

      TransAlta may disconnect the Whitecourt Facility upon 30 days' written
notice if the Whitecourt Facility is in violation of any term or condition of
the Wliitecourl PPA and the violation is not remedied within the notice period.
TransAlta may disconnect the Whitecourt Facility without notice in the event of
substandard power delivery or safety risks. All remedial expenses to reconnect
are for the account of the Whitecourt Facility.

      Approximately 3.3 MW of capacity is not contracted and sold at the Alberta
Power Pool spot price. The actual average Power Pool price for 2005 was $70 per
MWh. compared to $54 per MWh for 2004 and $63 per MWh for 2003.

      Wood Waste Supply Arrangements

      Wood waste is supplied to the Whitecourt Facility under agreements with
Millar-Western Industries Ltd. and Millar Western Pulp Ltd. (collectiveiy,
"Millar-Western") and BlueRidge Lumber (1981) Ltd. ("BlueRidge"). Millar-Western
operates a 190 million board foot per year sawmill, and a low-cost pulp mill
that produces 280,000 air-dried metric tonnes of pulp per year. Millar-Western
has agreed to supply a minimum of 275,000 tonnes of wood waste per year (based
on 50 percent moisture content per truckload) to the Whitecourt Facility for a
term of 20 years commencing December 1994. Millar-Western pays the Whitecourt
Facility a flat fee of $0.50 per tonne during the term of the contract.
Millar-Western is required to pay for the full cost of replacement fuel for the
Whitecourt Facility if itdoes not deliver the required minimum quantity of wood
waste. The Millar-Western facility is located approximately seven kilometres
away from the Whitecourt Facility.

      BlueRidge is a producer of 240 million board feet per year of lumber and
140 million square feet (3/4" basis) of medium density fiberboard products.
BlueRidge has agreed to supply a minimum of 50,000 tonnes of wood waste per year
to the Whitecourt Facility for a term of 20 years commencing May 1996, subject
to the right of BlueRidge to terminate the agreement with two years' prior
written notice. BlueRidge is currently supplying approximately 30,000 tonnes of
wood waste per year. The BlueRidge facility is located approximately 38
kilometres away from the Whitecourt facility. BlueRidge gave notice an December
31, 2003, that it would stop supplying wood waste at the end of 2005. However,
we have continued hauling ail of BlueRidge's wood waste to the end of March
2006. in addition, the facil ity is expected to have enough fuel for the
remainder of 2006. The Administrator/Manager is investigating other fuel
sources.

      The Whitecourt Facility consumes approximately 300,000 tonnes of wood
waste per year. During the past several years, approximately 270,000 green
tonnes has been supplied by Millar-Western, and 30,000 green tonnes by
BlueRidge. Wood waste fuel is delivered at the Whitecourt Facility's cost by the
Whitecourt Facility's fleet of four tractors pulling trailers with a
self-unloading system.

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      Environmental Matters

      The average annual emission levels at the Whitecourt Facility are
approximately 50.0 percent below the ievels of permitted emissions as set out in
the Whitecourt Facility's environmental permit with the exception that
approximately 20 to 25 times per year, for a period of approximately one hour,
emission levels have exceeded the Facility emissions levels due to the
unavoidable occasional intake of high moisture content fuei and fuel plugs and
fuel feed interruptions caused by the non-uniform nature of wood waste. In 2005,
the Whitecourt Facility renewed its environmental permit and as part of the
renewal, has the ability to average its emission for two hours based on a fuel
interruption to the furnace. The bed drain project completed in the spring of
2005 has also enabled the facility to eliminate the excedersces in 2005.

      THE CHAPAIS FACILITY

      Overview

      The Chapais Facility is a wood waste fired electricity-generating plant
located in the town of Chapais, Quebec approximately 600 kilometres northwest of
Quebec City. The Chapais Facility is owned by Chapais Energie, Societe en
Commandite ("CHESEC"), a limited partnership whose sole general partner is
Chapais Eiecirique Limitee ("CHEL") and whose sole limited partner is CHESEC
LPCO Inc., a wholly-owned subsidiary of CHEL. The Chapais Facility has an
installed capacity of 31.0 MW, The power from the Chapais Facility is sold to
Hydro-Quebec through an interconnect point at a substation approximately 1.5
kilometres from the site.

      The Chapais Facility is mainly comprised of one steam turbine and one
generator. Other major components of the Chapais Facility include: a 250,000
lbs/hr fixed pin hole grate boiler with combustion air re-injection; wood
receiving, conveying, stockpiling, reclaiming, hogging and screening systems; an
ash handling unit, cooling tower, circulating water piping and condenser.

      In April and October of each year, there are scheduled shut-downs at the
Chapais Facility to perform maintenance and mechanical inspections. In September
2002, the hourly employees of the Chapais Facility elected to become members of
la Confederation des syndicats nationaux, a labour union within the province of
Quebec. Agreement was reached with the union in September 2003, for the period
October 2003 to October 2005. The operator of the Chapais Facility is currently
negotiating a new agreement with the union.

      Power Purchase Agreement

      Power produced at the Chapais Facility is sold pursuant to a long term
power purchase agreement with Hydro Quebec dated March 30, 1992, as amended (the
"Chapais PPA"). The Chapais PPA has an initial term ending in 2015, which may be
extended to 2020 at the request of the owner of the Chapais Facility and subject
to obtaining certification by an engineering firm acceptable to Hydro Quebec as
to the Chapais Facility's useful life over the requested extension.

      The Chapais PPA requires the Chapais Facility to produce annually a
minimum of l98,064 MWh, and 95.0 percent of the contractual capacity of 28 MW,
during the winter months of December to March. The Chapais PPA provides for a
$0.011 per kWh (1991 value) penalty, which is escalated annually at a rate
equivalent to the increase in the Greater Montreal Consumer Price Index from
January 1991, in the event that the annual production at the Chapais Facility is
at a shortfall below the contractual energy threshold. Pursuant to the Chapais
PPA, a shortfall in the delivery of the 95.0 percent contractual winter capacity
for two consecutive years would permit Hydro Quebec to impose a permanent pro
rata reduction in the contractual capacity.

      The contract price for 105.0 percent of the 208,488 MWh of contractual
energy pursuant to the Chapais PPA was $54.80 per MWh for 2005. Energy delivered
to Hydro Quebec in excess of 105.0 percent of the 208,488 MWh threshold will be
paid for at an occasional energy rate that is significantly lower. The contract
price for the capacity payment was $136.52 per kW of available capacity during
the winter period in 2005. Both the energy rate and the capacity rate are
escalated annually by the Greater Montreal Consumer Price Index, subject to a
minimum escalation of 3.0 percent and a maximum of 6.0 percent per year.

      Wood Waste Supply Arrangements

      Wood waste is supplied to the Chapais Facility under long-term agreements
with two longstanding local Quebec sawmills. The Barrette-Chapais Mill
("Barreete") is owned by Barrette-Chapais Ltee and is located approximately ten
kilometres from the Chapais Facility. The Chantier Chibougamau Mill ("Chantier")
is owned by Les Chantiers de Chibougamau Ltee and is located approximately 40
kilometres from the Chapais Facility. In

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addition to the two current major suppliers, there are additional supplies of
wood waste within a range of 200 kilometres from the Chapais Facility.

      Barrette-Chapais Ltee has agreed to supply all the bark production of
Barrette to the Chapais Facility for a term of 20 years ending in 2015. This
agreement can be renewed on the same terms by CHESEC for an additional five
years at the end of the original 20-year term. The fee paid by CHESEC in 2005
for bark was $2.00 per green metric tonne. The price is escalated annually at
the Greater Montreal Consumer Price Index (with a minimum escalation of 3.0
percent and a maxim urn of 6.0 percent).

      Les Chantiers de Chibougamau Ltee has agreed to supply all the annual bark
production of Chantier to the Chapais Facility for a term of 20 years ending in
2015, at no cost. This agreement can be renewed on the same terms by CHESEC for
an additional five years at the end of the term.

      Up until July 2003, Chapais Facility had its own transportation vehicles
and employees to haul the wood waste and to dispose the ash. In July 2003, the
transportation business was sold to Transport Lapage Inc. at a price of $550,000
and the transportation employees were moved to Transport Lapage Inc. In 2005,
Chapais paid Transport Lapage Inc. $4.91 and $8.58 per green metric tonne
respectively for hauling wood waste from Barrette-Chapais Ltee and Les Chantiers
de Chibougamau Ltee.

      The Chapais Facility consumes approximately 400,000 green metric tonnes of
biomass fuel per year. During the past several years, approximately 210,000
green metric tonnes has been supplied by Barrette including 25,000 green metric
tonnes of sawdust, 150.000 green metric tonnes has been supplied by Chantiers,
and 20,000 green metric tonnes has been supplied by other local sources.

      The Province of Quebec recently passed legislation limiting the tree
cutting rights of non-native mills. As a result it is estimated that starting in
April 2005, the volume of future wood waste servicing the Chapais Facility from
the Barette and Chantiers mills may be reduced by approximately 20 to 25
percent. In October 2005, Chapais signed contracts for biomass supply with
Societe en Commandite Sciere Opitciwan and Produits Forestiers Saguenay Inc. in
the amount of 40,000 green metric tonnes per year at a price of $17.50 per
green metric tonne for a term of five years and in the amount of 50,000 green
metric tonnes per year at a price of $13.50 per green metric tonne for a term of
three years, respectively. The price is escalated annually by 3.0%. These
contracts can be renewed for an additional term of five or three years,
respectively. The price will be re-negotiated at the time of renewal for both
contracts.

      Project Histoiy

      The Chapais Facility was completed in 1995 and was financed by a syndicate
of lenders led by Sun Life Assurance Company. The construction of the Chapais
Facility experienced completion delays and incurred higher costs than
anticipated from increased start-up costs and issues regarding construction and
design of the Chapais Facility. As a result, CHESEC, CHEL, CHESEC LPco Inc. and
CHEL Subco Inc. entered into a preferred share refinancing arrangement (the
"Chapais Refinancing Arrangement") in November 1999 with the existing lending
syndicate whereby all of the existing debt of CHESEC related to the Chapais
Facility In an aggregate amount of approximately $61.0 million in senior term
loans and $5.1 million in subordinated loans was temporarily exchanged by the
lenders for preferred shares of CHEL Subco Inc., a subsidiary of CHEL.

      As part of the Chapais Refinancing Arrangement, CHEL Subco Inc. created
three classes of preferred shares, which it issued to the lenders in exchange
for the indebtedness owed to them by CHESEC. CHEL Subco Inc. issued 45,654,000
Class A Preferred Shares (corresponding to the Tranche A term debt of CHESEC and
carrying a dividend of 6.5 percent per annum payable monthly), 15,257,679 Class
B Preferred Shares (corresponding to the Tranche B term debt of CHESEC and
carrying a dividend of 6.5 percent per annum payable on the last business day of
January' and July in each year) and 5,116,536 Class C Preferred Shares
(corresponding to the subordinated debt of CHESEC and carrying a dividend of 6.0
percent per annum payable on the last business day of January and July in each
year). These dividends were generally non-taxabie to corporate shareholders as
confirmed in an income tax ruling obtained from Canadian federal and Quebec tax
authorities. Until termination of the Chapais Refinancing Arrangement, CHEL
Subco Inc. held the indebtedness of CHESEC.

      The Chapais Refinancing Arrangement terminated as scheduled in July 2004.
Upon termination, the lending syndicate exchanged their preferred shares of CHEL
Subco Inc. for the then existing indebtedness of CHESEC held by CHEL Subco Inc.
See "The Investments - Investment in the Chapais Facility".

      The authorized, issued and outstanding capital of CHEL consists of 50
common shares, all of which are owned by CEEC, 400 Class A shares, all of which
are owned by Barrette-Chapais Ltee. and 336 Class B preferred shares, of which
105 are owned by CPOT Holdings Corp., a subsidiary of the Fund. Although the
Class B preferred

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shares are non-voting, pursuant to a shareholders agreement dated December 6.
1999 between CHEL and its shareholders, the approval of 70 percent of the
holders of the Class B preferred shares is required to approve certain matters,
including the entering into of agreements other than in the ordinary course of
business or the entering into of any material agreement and the approval of ail
holders of Class B preferred shares is required to approve certain matters,
including the issuance of any securities of CHEL. the taking of any action to
liquidate, dissolve or wind-up CHEL, the sale of all or substantially all of
CHEL's assets or for CHEL to borrow money. The Class B preferred shares entitle
the holders to a preferential dividend from CHEL on the basis of 95 percent to
the holders of Class B preferred shares and 5 percent to the holders of common
shares until the amount of $12,300,000 plus 11.789 percent per annum, compounded
semi-annually, has been paid to holders of Class B preferred shares by way of
preferential dividends. The Class A shares are also non-voting and are only
entitled to receive dividends once the holders of the Class B preferred shares
have received their preferential dividend.

      Since it began production, the Chapais Facility has not had any major
mechanical difficulties and has exceeded both the 95.0 percent contractual
energy threshold and the 95.0 percent contractual capacity required by the
Chapais PPA for the past nine years.

LANDFILL GAS FACILITIES

      As noted above under "General Development of the Business - Special
Committee", the special committee of CPOT is investigating unithoider value
enhancement opportunities. As updated on March 16, 2006, the special committee
has been concentrating its efforts to date with respect to the investment of the
Fund in GRS. With the assistance of its financial advisors, Scotia Capital Inc.
and Ewing Bemiss & Co., the special committee has undertaken competitive process
to dispose of the Fund's interest in GRS. On March 29, 2006, the Fund announced
that following the competitive bid process, the special committee received a
number of conditional bids for this investment.

      GAS RECOVERY SYSTEMS, LLC

      GRS was formed in 1979 as a subsidiary of Genstar Limited ("Genstar"). In
1982, GRS executed the PPA relating to the Landfill Gas Facility located in
Menlo Park. California. GRS also developed additional facilities in California
in the early 1980s to supply power under PPAs.

      By 1989, GRS operated seven landfill gas electricity plants and one
medium-Btu gas processing plant. In 1991, GRS acquired the landfill gas
facilities of Solar Turbines Inc., adding four facilities located in New York
and California, and a controlling interest in a facility in Hawaii, to its
portfolio. In 1997, GRS was purchased by a group of equity investors who were
principals of GRS immediately prior to the time of the Fund's investment in GRS.
In April 2000, GRS completed the purchase of Browning-Ferris Gas Services, Inc.
("BFGSI"). The BFGSI acquisition more than doubled the size of GRS, adding 15
operating landfill gas electricity plants located in six states and four plants
under construction or expansion.

      GRS owns 29 operating Landfill Gas Facilities. During the first quarter of
2005, the Arbor Hills facility was extensively refurbished and work commenced on
the expansion as well, which was completed in the fourth quarter. In the third
quarter, an expansion at the Vienna Junction facility was initialed to increase
direct gas sales output. This expansion was completed in January 2006. A 2.5 MW
expansion of the C&C facility is planned for 2006.

      Power Purchase Agreements

      GRS has 26 PPAs with 13 electric utilities or municipalities to sell
electricity and in some cases to receive capacity payments. Generally, the PPAs
expire from 2007 to 2030, as described in the above table. The price per kWh
varies for each PPA, typically ranging from US$0.03 per kWh to US$0.075 kWh as
at December 31, 2005. For certain PPAs, the pricing is determined by the
respective utilities' short run avoided cost ("SRAC") formula, the cost avoided
by the utility by not producing the electricity itself.

      The price payable under certain PPAs is adjusted upwards if specified
production thresholds are exceeded, or downwards if specified production
thresholds are not achieved. In addition, if specified production capacity
targets are not met under certain PPAs, GRS may be required to pay liquidated
damages or refund amounts previously paid and certain power purchasers have the
right to "de-rate" the facility or permanently lower the amount of power
required to be purchased to the reduced capacity. Certain PPAs allow the
utilities or municipalities to terminate the PPAs, receive liquidated damages,
or purchase the relevant Landfill Gas Facility if GRS causes defaults that are
not remedied or if the PPA is terminated prior to its expiration.

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      In addition to customary events of default for breaches of representations
and covenants and insolvency events, a number of PPAs provide for termination in
the event that capacity targets are not maintained over specified periods or as
a result of outages exceeding specified time limits.

      GRS has granted a security interest over certain of the Landfill Gas
Facilities to secure its obligations under the PPAs for those facilities, and
may not grant additional liens or security interests over such facilities
without the consent of the applicable purchasing utility. GRS is also required
to maintain security in the form of cash collateral or letters of credit to
secure obligations under the PPAs for certain facilities, including the C&C,
Richmond and Sunset Farms Landfill Gas Facilities,

      The Pine Bend Landfill Gas Facility's past failure to meet capacity
targets under its PPA has been remedied without amending such PPA. Following a
default under the PPA relating to the Halifax Landfill Gas Facility as a result
of that facility's failure to meet the applicable required capacity factor,
Taunton Municipal Lighting Plant and GRS agreed to terminate the PPA effective
December 31, 2002. Electricity generated at the Halifax facility is now sold to
Massachusetts Electric Company at prevailing market rates under a Qualifying
Facility Power Purchase Rate Agreement that is terminable by either party on
seven days' notice. In addition, following defaults under the PPA for the
Chicopee Landfill Gas Facility as a result of that facility's failure to meet
the applicable required capacity factors under the PPA, GRS and the Chicopee
Municipal Lighting Plant agreed to continue the Chicopee PPA on a month-to-month
basis at a renegotiated price.

      Under the PPAs for the Fall River and East Bridgewater Landfill Gas
Facilities, the Taunton Municipal Lighting Plant has the option to purchase such
Landfill Gas Facilities commencing in 2007 at a purchase price equal to US$1,172
per kW of installed capacity for Fall River and US$1,502 per kW of installed
capacity for East Bridgewater, which prices decline each year through 2018 for
Fall River and 2014 for East Bridgewater. If the Taunton Municipal Lighting
Plant does not exercise a purchase option, it may elect to pay to GRS the
equivalent of the price payable under the option and thereafter reduce the price
paid for electricity from such facility from a fixed rate to a variable rate
based on the applicable price of landfill gas to GRS and a specified operating
and maintenance charge. In return for an annual fee from GRS, CPOT has agreed to
guarantee the obligations of GRS under the PPAs for C&C and Sunset Farms
facilities, as well as under the performance bond for the Mallard facility.

      Gas Sale Agreements

      GRS has gas sale agreements with three industrial users relating to the
Newby Island III, Vienna Junction and Sacramento Landfill Gas Facilities. Under
such agreements the industrial users buy landfill gas of at least 400 Btu per
standard cubic foot. The Vienna Junction facility sold approximately 107,000
MMBtu in 2005 and the Sacramento facility sold approximately 106,000 MMBtu in
2005. The price of landfill gas under the Vienna Junction gas sale agreement was
US$2.39 per MMBtu as of December 3i, 2005 and the price of landfill gas under
the Sacramento gas sale agreement was US$2.S33 per MMBtu as of December 31,
2005.

      GRS has entered into a gas sale agreement with the City of San Jose for
the Newby Island III Landfill Gas Facility that was completed in June 2003. The
gas sale agreement provides for the sale of landfill gas required to operate a
specified water pollution control plant, although no minimum level of operation
is specified and the City of San Jose is not required to purchase any minimum
quantity of landfill gas. The Newby Island III facility delivers approximately
261,000 MMBtu annually at a price that will vary depending upon the lower of the
price of electricity or natural gas in California.

      Site Lease Arrangements

      GRS does not own any landfills. The Landfill Gas Facilities are located on
parts of the landfills that GRS leases or subleases under site lease agreements.
The lessors either own and operate, or lease and operate, their respective
landfills and, in most cases, also own the related landfill gas collection
systems. GRS has entered into agreements whereby it operates and maintains such
gas collection systems. Such operation and maintenance agreements generally have
the same term as the gas purchase arrangements for the Landfill Gas Facilities.

      The rent payable under GRS' site lease arrangements is generally a nominal
amount. GRS and its lessors generally provide broad indemnities to each other
for damages that may arise from their respective operations and liabilities that
may arise from hazardous materials. If a lessor has an option to purchase a
Landfill Gas Facility (see "Gas Purchase Agreements" below) it may terminate its
site lease arrangement if it exercises such purchase option. Additionally, GRS
can usually terminate a site lease arrangement if the related gas purchase or
operation and maintenance agreement is terminated. If a site lease arrangement
is terminated and the lessor does not exercise its purchase option, GRS is
responsible for removing its Landfill Gas Facility. The site lease arrangements
for the

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Mallard Lake, and Coyote Canyon Landfill Gas Facilities grant the lessors rights
of first refusal to purchase the relevant Landfill Gas Facility if the site
lease is terminated. In addition, the owner of the Mallard Lake landfill has the
right of first refusal to purchase the Mallard Lake Landfill Gas Facility if GRS
wishes to sell the facility to a third party.

      Sales of Renewable Energy Certificates

      Currently, fourteen U.S. states -- including California, Texas,
Massachusetts, Connecticut and New York -- have either implemented or are in the
process of implementing Renewable Portfolio Standard ("RPS") laws. Under these
regulations, resellers of electricity within each state must include "green" or
"clean" energy in their mix of power resources to at least a minimum standard.
One option for satisfying these requirements is the purchase of Renewable Energy
Credits ("RBCs") from qualified suppliers. The developing market for RECs
provides an opportunity for qualified Fund investments to sell credits. RECs
directly relate to the kWh of green power produced, as opposed to ERCs which
reflect the displ acement of greenhouse gas ("GHG") emissions.

      The sale of "green" renewable energy credit attributes may involve a
separate and distinct transaction from the sale of power, or may be embedded in
the contracted price of power.

      In early November 2003, GRS entered into a contract for the sale of US$2.0
million (gross) of RECs to PPL Energy Plus. The sale involves RECs generated
from the first quarter 2004 through to the end of 2006 from the Chicopee and
East Bridgewater Landfill Gas Facilities. A portion of the proceeds of the sale
of RECs from the East Bridgewater Landfill Gas Facility is shared with the
purchaser under the PPAs for such facilities.

      In January 2005, GRS entered into a contract for the sate of US$1.3
million (gross) of RECs to National Grid. The sate involves RECs generated from
the first quarter 2005 through to the end of 2005 from a portion of the output
from the Fall River and Randolph facilities.

      In early September 2005, GRS entered into a contract for the sale of
US$0.3 million (gross) of RECs to Consteliation New Energy, The sale involves
RECs generated from the second quarter 2004 through to the end of the third
quarter 2005 from a portion of the output from the Mallard, Rockford and South
Barrington facilities.

      In June 2005, GRS entered into a contract for the sale of US$0.2 million
(gross) of RECs to BP Energy. The sale involves RECs generated from the fourth
quarter 2004 through to the end of 2007 from a portion of the output from the
Sunset Farms facility.

      In December 2005, GRS entered into a contract for the sale of US$1.0
million (gross) of RECs to National Grid. The sale involves RECs generated from
the first quarter 2006 through to the end of 2006 from a portion of the output
from the Fall River and Randolph facilities.

      In December 2005, GRS entered into a contract for the sale of US$1.2
million (gross) of RECs to BP Energy. The sale involves RECs generated from the
first quarter 2006 through to the end of 2008 from a portion of the output from
the Fali River and Randolph facilities.

      In December 2005, GRS entered into a contract for the sale of US$0.1
miliion (gross) of RECs to PPL Energy Plus. The sale involves RECs generated
from the first quarter 2006 through to the end of 2006 from a portion of the
output from the Halifax, East Bridgewater and Chicopee facilities.

      Prior to its termination in December 2004, proceeds from the sale of RECs
were also shared with GRSM under the terms of their management agreement.

      Gas Purchase Agreements

      GRS has gas purchase agreements related to the Landfill Gas Facilities
that expire at various times through to 2031, in many cases with related options
in favour of the gas collection system owner to renew for up to six years. The
range of landfill gas purchase prices for gas to be used to produce electricity
was typically US$0.81 to US$0.86 per MMBtu in 2005. As at December 31, 2005 the
total annual delivery of landfill gas was approximately 5,900,000 MMBtu.

      In most of the gas purchase agreements, GRS has an option to purchase the
landfill gas collection systems and the rights related to them (including the
right to collect and use landfill gas) for a period of 30 days following the
expiration of the agreement, at the then adjusted book value, as defined in the
relevant agreements, plus the adjusted book value of certain capital
expenditures made by the gas collection systems' owners. If GRS does not
exercise its options, the counterparties have options to purchase the relevant
Landfill Gas Facility for a period of30 days at the then adjusted book value,
pius the adjusted book value of certain capital expenditures made by GRS.

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GRS has advised the Administrator/Manager that the purchase price for the gas
collection systems would generally be less than the purchase price for the
Landfill Gas Facilities, and that, in most cases, it expects GRS would exercise
its options to purchase the relevant landfill gas collection systems and related
rights.

      The Gas Purchase Agreements for the C&C, Richmond, Chicopee, Lyon and Mali
fax Landfill Gas Facilities expired as of December 31, 2002. GRS exercised its
options to purchase the Chicopee and Halifax landfill gas collection systems and
has agreed to continue the terms of the Gas Purchase Agreements for such other
facilities at present. The purchase of Richmond has been deferred until 2007.
Timing of the Lyon and C&C purchase has yet to be determined. In addition,
although the gas purchase arrangements for the American Canyon, Guadalupe and
Menio Park were not scheduled to expire until 2008, GRS permitted early
termination of these agreements in January 2003 and exercised its options to
purchase the gas collection systems for such facilities. The supplier of
landfill gas to the San Marcos, Sycamore, Santa Cruz and Orange County Landfill
Gas Facilities exercised its right to require GRS to purchase the gas collection
systems and gas rights relating to such Landfill Gas Facilities for the net
present value of US$924,G00 discounted from January 1, 2003 to the date of
exercise.

      Landfill Gas Facilities in Illinois

      GRS has part ownership interest in four Landfill Gas Facilities in
Illinois subject to the Illinois Public Utilities Act ("Illinois PUA")- Under
the Illinois PUA, such facilities receive a price per kilowatt hour that is in
excess of the local municipality's or utility's SRAC for ten years, or in the
case of Mallard Lake, 20 years. Such excess is required to be repaid to the
State of Illinois commencing in 2007 for South Harrington and Rockford, 2008 for
Quad Cities and 2017 for Mallard Lake. Repayment of such overpayment is to be
completed no later than 10 years after the repayment begins (20 years for
Mallard Lake). Commencing in October 2000, GRS established an escrow account to,
among other things, accumulate funds to meet such repayment liability. The
Illinois Commerce Commission ("ICC"), which administers the Illinois PUA,
agreed in February 2003 to extend the full funding of the then unfunded
liability period to December 31, 2005. As at December 31, 2005 the previously
unfunded balance in the escrow account had been fully funded.

      Employees

      GRS has over 110 non-unionized employees involved in the Landfill Gas
Facilities in the areas of operations, engineering, maintenance and
administration.

      Environmental

      GRS's potential environmental liabilities are generally related to GRS's
gas collection, processing and conversion activities, as GRS contracts for the
purchase of landfill gas and does not actually own the landfill sites.
Environmental considerations in the operation of the Landfill Gas Facilities
include compliance with U.S. federal New Source Performance Standards and/or
other applicable state regulations for landfill emissions and related generation
activities, and compliance with regulations regarding disposal of by-products
associated with the processing of landfill gas or generation activities such as
condensate, wastewater, waste oils and waste coolants. Generally, waste
by-products are transported by truck to licensed waste handling facilities for
disposal or recycling or are discharged under permit to waste water treatment
plants.

INDUSTRY OVERVIEW

INDEPENDENT POWER GENERATION

      In the traditional structure of the electricity industry,
vertically-integrated monopoly utilities have generated, transmitted and
distributed electricity to customers. Rapid growth in electricity demand, rising
electricity rates, technological advances and environmental concerns have led
several Canadian provincial and U.S. stale governments to implement efforts to
restructure the electricity industry within their respective jurisdictions
which, among other things, has encouraged the generation of electricity from
independent power producers. However, the pace of this restructuring has been
slowed down, or in some cases put off indefinitely, while jurisdictions complete
detailed reviews of their respective energy policies.

      In the independent power generation sector, electricity is generated from
a number of sources, including: (i) water; (ii) natural gas; (iii) waste
products, such as biomass (e.g., waste wood from forest products operations) and
landfill gas; (iv) gcothermal sources, such as heat or steam: (v) the sun; and
(vi) wind.

      While regulated utilities continue to dominate North American electricity
generating markets, the Administrator/Manager believes that independent power
producers will play an increasingly important role in the

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supply of electricity needs in the future. In recent years policy makers have
increasingly recognized the benefits of power generated by independent power
producers, especially where such power is produced from renewable or waste
resources or at higher efficiencies than conventional utility-owned generation.

CANADA

      Provincial governments have legislative authority over the generation,
transmission and distribution of electricity in Canada. The movement toward
restructuring the Canadian electricity industry has been uneven, as each
province has determined its policy in this area based on its assessment of its
unique regional circumstances and issues. Alberta restructured its electricity
market over a five-year period culminating in full retail access on January 1,
2001. In British Columbia, while there are no plans to introduce full retail
competition, the transmission systems provide open access, allowing independent
power producers to move electricity to the export market or to distribution
utilities and large industrial customers within the province. In Ontario, full,
open competition in electricity markets was introduced in May 2002, but has been
modified several times since then. In the fall of 2003, the newly elected
government in Ontario initiated a full-scale review of the Ontario energy sector
and introduced new legislation in December 2004 that substantially modified the
sector again. Most other provinces are planning to implement some degree of
competition in their local market in the short to mid-term.

      In February 2005, the Minister of Finance delivered a budget containing a
number of new measures for green energy developers, subject to ratification. The
government has set aside $1 billion over the next five years for an "innovative
Clean Fund" to purchase emission reductions from Canadians and Canadian industry
through a competitive process. Eligible projects could include new green power
sources. The budget also extended the Wind Power Production Incentive ("WPPI")
with a goal of stimulating 4,000 MW of new wind energy. The incentive payment of
1 cent per kilowatt-hour of production for the first ten years of operations
remains the same, but will be available to eligible projects commissioned before
April 1, 2010. Furthermore, a new Renewable Power Production incentive ("RPPI")
intended to stimulate up to 1,500 MW of other new renewable energy was created.
The RPPI provides for an incentive of 1 cent per kilowatt-hour of production for
the first ten years of operations for eligible projects commissioned after March
31, 2006 and before April 1, 2011. Eligible technologies could include
waterpower, advanced, innovative and highly efficient biomass, combustion
technologies using biogas, and other renewable technologies. The budget also
proposed to further accelerate the capital cost allowance rate for Class 43.1
from 30 percent to 50 percent.

      Alberta

      The government of Alberta passed the Electric Utilities Act (the "EU Act")
in 1996 and amended the EU Act in 1998 and 2000 to separate generation,
transmission and distribution of electrical power in Alberta for regulatory
purposes. The purpose of the EU Act is to permit the development of a
competitive marketplace for electricity in Alberta. The EU Act created the
Alberta Power Pool (the "Power Pool"), through which ail electrical power must
be traded in Alberta except for electricity within exempted industrial systems,
electricity from generators in remote locations not connected to the grid and
certain direct sales. Under the EU Act, owners of existing electricity
generation facilities in Alberta and importers of electrical power into Alberta
offer power into the Power Pool at such prices as they determine.

      Of particular interest to some clean power facilities in the province, the
amendments to the EU Act and corresponding regulations in 2000 also created the
Alberta Balancing Pool (the "Balancing Pool") that commenced operation on
January 1, 2001. The amended legislation provides for the purchase of power from
small producers at the prices set out in the PPAs entered into pursuant to the
Small Power Research and Development Act (Alberta) (the "SPRDA"). 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 PPAs are to be paid out of
the Balancing Pool. The effect of the amendments is to render a utility that is
party to such a PPA a flow-through entity for the rights and obligations under
that PPA. The Balancing Pool is intended to net out to zero with respect to all
payments received and made in respect of those PPAs. Any net amount greater than
zero in the Balancing Pool is to be allocated to consumers of electricity of
Alberta and to the Alberta Electric System Operator (formerly the Transmission
Administrator) under the EU Act. The legislation also provides the Balancing
Pool with a quasi-taxing authority by giving it the ability to raise rates to
consumers of electricity in Alberta in order to ensure that payments under such
PPAs can be made in the event the Balancing Pool is in a deficit situation.

      The government of Alberta proclaimed in force, June 1, 2003, a new
Electric Utilities Act (2003) (the "New EU Act") and the Independent Power and
Small Power Regulation (the "Regulations"). The New EU Act effected alterations
to the governance of institutional entities such as the Power Pool and the
Regulations addressed

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payments So be made to and by the Balancing Pool, but neither served to alter
the SPRDA-related arrangements described above.

      British Columbia

      British Columbia Hydro and Power Authority ("BC Hydro"), a British
Columbia Crown corporation regulated by the British Columbia Utilities
Commission ("BCUC"), is the main generator and distributor of electricity in
British Columbia. BC Hydro is the third largest electric utility in Canada and
accounts for approximately 11,300 MW, or 80 percent, of the province's total
generating capacity. The remaining capacity is provided mainly by large and
small industrial self-generators, FortisBC Inc., a subsidiary of Fortis Inc.,
providing utility service in the south-eastern part of the province, and
independent power producers.

      The government of British Columbia introduced a new energy plan for the
province in November 2002. Under the plan, public ownership of BC Hydro's
generation, transmission and distribution assets continues. However, BC Hydro
was reorganized and a new British Columbia Crown corporation, British Columbia
Transmission Corporation, regulated by the BCUC, was formed to plan, manage and
operate BC Hydro's transmission assets to improve access to the transmission
system for all generators and marketers under an open access transmission
tariff. Under the energy plan, new generation of electricity is primarily to be
built by private developers and, except for possible involvement in major
projects, BC Hydro is limited to undertaking efficiency improvements and
capacity upgrades at its existing facilities. BC Hydro's generation division,
which operates as a separate line of business from BC Hydro's distribution
division, is required to supply electricity from its existing waterpower and
thermal generating stations to the distribution division at embedded cost under
a "heritage contract" between the generation and distribution divisions. The
distribution division acquires new power on a least cost basis from all
potential sources (including independent power producers, customer owned
generation, power imports and conservation and energy efficiency), subject to
regulatory oversight by the BCUC, BC Hydro's existing contracts with independent
power producers include existing natural gas cogeneration, biomass and small
hydro projects that are both in service and under development. Under the
province's energy plan BC Hydro is to pursue a voluntary goal of acquiring 50
percent of new supply from "'clean" energy sources by 2013. Independent power
producers are also now permitted to serve all or part of the electricity needs
of large industrial customers in the province.

      Ontario

      On April 1, 1999, Ontario's electricity industry was substantially
restructured with the division of the vertically-integrated Crown-owned utility,
Ontario Hydro, into five separate Crown-owned companies including, Ontario Power
Generation Inc. ("OPG"), a generation company, Hydro One Inc., a transmission
and distribution company, and OEFC, the Administrator/Manager of Ontario Hydro's
"stranded" debt. OEFC is now party to the existing PPAs entered into between
Ontario's independent power purchasers and Ontario Hydro throughout the
1990's and its obligations under such PPAs are guaranteed by the Province of
Ontario.

      On May 1, 2002, Ontario's wholesale and retail electricity markets opened
to competition, and its transmission and distribution systems opened to
unrestricted access by generators and retailers. However, in the summer
following the opening, Ontario experienced high levels of demand for electricity
with resulting increases in the wholesale price of electricity and charges for
imported power. Reacting to public concerns over electricity prices, the
government of Ontario passed the Electricity Pricing, Conservation and Supply
Act, 2002 on December 9, 2002, which introduced an electricity price freeze at
4.3 cents per kilowatt hour until May 1, 2006 for certain consumers.

      In the fail of 2003, the newly elected Provincial government passed the
Ontario Energy Board Amendment Act (Electricity Pricing), 2003, which
implemented an interim electricity pricing plan effective April 1, 2004 that
increased the commodity price for the first 750 kWh of electricity consumed by
low-volume and designated consumers in any month to 4.7 cents per kilowatt-hour
and 5.5 cents per kiiowatt-hour consumed thereafter.

      On December 9, 2004, the Ontario Legislature passed the Electricity
Restructuring Act, 2004 (the "ERA") that once again significantly restructured
Ontario's electricity sector. The ERA introduced a hybrid electricity market
model that provides for a mixture of government regulation and private sector
competition to determine electricity pricing. The Ontario Energy Board will
establish the price for the output of the baseload plants owned by OPG, while
other electricity generation plants will continue to be subject to competition.

      Among other objectives, the new legislation is intended to encourage the
development of a new reliable electricity supply, lessen environmental impacts
and enhance Ontario's competitiveness in electricity pricing while ultimately
having consumers pay the true cost of electricity through the hybrid electricity
market. The government

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created a new agency, the Ontario Power Authority (the "OPA"), which has the
responsibility of ensuring the adequacy of electricity supply, forecasting
generation, transmission and distribution resource needs, and has the power to
call upon private investment for generation and conservation management
proposals. The Minister of Energy has stated that an investment of $25 billion
to $40 billion would be needed in Ontario's electricity industry over the next
15 years to replace aging facilities and the 7,500 MW of coal-fired generation
the Province intends to decommission by no later than 2009. In December 2005,
the OPA released its Supply Mix Advice Report providing recommendations
regarding priorities of such investment, and the OPA has also solicited
significant new and refurbished generation capacity to be developed between 2007
and 2010.

      The recent legislative amendments, government announcements and OPA
initiatives do not contain any specific provisions that relate to or affect PPAs
such as the Wawatay PPA or the Dryden PPA now being administered by OEFC,
although as described on page 9, the Erie Shores Wind project is one of the
capacity initiatives solicited by the OPA. The implementation of the new market
rules, however, has necessitated negotiations between the holders of existing
PPAs and OEFC, including for the purpose of replacing Ontario Hydro's "direct
customer rate", the index used to adjust rates in many PPAs (including those for
the Wawatay Facility and the Dryden Facility). In 2004, the
Administrator/Manager reached agreement with OEFC regarding pricing escalator
amendments to the PPA for the Wawatay Facility to be applied retroactive to
January 1, 2002.

UNITED STATES

      In the United States, competition in electricity generation was greatly
increased with the passage of the Public Utilities Regulatory Policy Act
("PURPA") in 1979. PURPA required utilities to purchase cogeneration power and
certain renewable energy generation from independent qualified facilities ("QF")
at the utilities' avoided cost. No utility could own more than 50 percent of a
QF. PURPA resulted in the construction of non-utility generation by independent
power producers. Their output was often sold to utilities under long-term power
purchase agreements, but this did not yet constitute a fully competitive market.
Generation, transmission and distribution remained effectively bundled until the
enactment of the U.S. Energy Policy Act of 1992 (the "1992 Act") and many
subsequent FERC orders.

      The 1992 Act allowed FERC to implement open access to transmission by
allowing any utility, Federal power marketing agency, or any other person
generating electric energy for resale to seek an order from FERC requiring a
transmitting utility to provide transmission service to that entity (including
any enlargement of transmission capacity needed to provide the service). In
addition, in FERC Order 888 (1996), all public utilities that owned, controlled
or operated transmission facilities used for transmitting electric energy in
interstate commerce were required to file open access, non-discrimination
transmission tariffs. The FERC's stated goal was to remove impediments to
competition in the wholesale bulk power marketplace and to bring more efficient,
lower cost power to consumers.

      To further facilitate competitive wholesale markets, FERC Order 2000
(1999) required transmission companies under FERC jurisdiction to form or
participate in Regional Transmission Organizations (RTOs), and defined the
characteristics and functions that qualified as an RTO. In view of the
interconnections between U.S. and Canadian transmission systems, FERC encouraged
Canadian participation in the formation of the RTOs. Later FERC orders permitted
the formation of ISOs, or independent system operators, which were organizations
that controlled only the transmission facilities within a single state. Further,
in reaction to certain adverse judicial decisions and considerable controversy,
the mandatory implementation of RTOs was dropped.

      In response to the slower than expected development of RTO's and ISOs, and
other perceived impediments to competitive electricity markets, on July 31,
2002, FERC issued a notice of proposed rulemaking (NOPR) addressing standard
market design. Under the NOPR, FERC planned to implement standardized
transmission service and wholesale electric market design. This included a
single, flexible transmission service (Network Access Service) and consistent
non-rate terms. This tariff would be administered by RTOs or ISOs. The single
open access service and other measures proposed in the NOPR were intended to
promote wholesale competition, efficient transmission systems, the right pricing
signals for investment in transmission, generation facilities and demand
reduction, and more customer options. Because of the far-reaching elements in
this proposal, including reliability planning requirements and proposed control
over certain functions that have traditionally been decided at the state level,
the NOPR was extremely controversial and was withdrawn. Although no further
action has been taken on this NOPR, many of the market design elements that it
proposed have been adopted by the existing ISOs and RTOs. Further, more ISO and
RTOs have been formed. At present, there are ISOs or RTOs operating in New
England, New York, the Midwest, throughout the mid-Atlantic states and
California. There are also pending applications or proposals for most other U.S.
regions as well. Although there are many common elements in

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the existing ISO and RTO systems, the rules are far from uniform and FERC
continues to work on eliminating "seams" between ISO/RTO systems.

      While FERC regulates interstate transmission, and has a mandate to ensure
that consumers have access to electricity at fair and reasonable rates, retail
access is largely the responsibility of individual states.

      Signed into law on October 22, 2004, H.R. 4520, the "American Jobs
Creation Act of 2004," is a U.S. federal tax bill that continues the Section 45
tax credit for wind electricity-generating facilities to those facilities placed
in service through December 31, 2005. Subject to certain phase-outs and
limitations, qualifying wind facilities can obtain a 10-year credit at 1.8 (plus
CPI escalator) cents per kilowatt-hour. The Section 45 credit formerly applied
to only wind energy and some biomass energy projects, but Section 710 of H.R.
4520 now expands the credit to a wide range of renewables, including LFG.
Qualifying LFG facilities can obtain a 5-year credit at 0.9 (plus CPI escalator)
cents per kilowatt-hour. The bill contains an array of tax breaks and other
incentives aimed at business and industries including electricity providers that
use renewable fuels.

      The Energy Policy Act of 2005 was signed into law on August 8, 2005 by
U.S. President George W. Bush. The act contains a number of important provisions
for the wind energy industry and LFG, including the extension of the production
tax credit through to 2007. Additionally, the tax credit period for LFG
electricity generating facilities was extended to ten years, from five years
under the "American Jobs Creation Act of 2004", for services placed into service
after August 8, 2005. The Energy Policy Act of 2005 also requires that utility
system reliability rules be non-discriminatory which will require, for
instance, that the North American Electric Reliability Councils stop setting
higher hurdles for wind than for other power resources. The bill also provides
incentives to encourage construction of new and upgraded transmission lines
which should have a positive impact on further renewable energy capacity
building.

CLEAN POWER

      Impact of Industry Deregulation

      Industry deregulation has increased demand for privately generated power
from a variety of sources including water, biomass and wind. With deregulation
and the opening of competition in the electricity marketplace, the
Administrator/Manager expects that there will be an increase in the opportunity
for energy consumers to choose to purchase electricity produced from a
particular source.

      Over 30 utilities in the United States now offer their customers clean
power at a premium price. The U.S. Department of Energy has suggested that in a
competitive marketplace, utilities and energy marketers will develop clean power
projects to strengthen their image with their customers and build customer
loyalty. Further, the U.S. Department of Energy has found that most utility
customers want their utilities to pursue environmentaliy preferred options for
generating electricity and some customers are willing to pay extra to receive
power generated by facilities employing environmentally preferred energy
sources.

      Advantages of Clean Power

      Clean power enjoys a number of advantages relative to other methods of
conventional energy generation.

      (a)   Availability of Long-term PPAs, The Administrator/Manager believes
            that clean power projects will continue to be developed with long
            term PPAs due to a number of factors including (i) the ability of
            clean power projects to offer stable long term contract prices, (ii)
            desire of purchasers to secure long-term credits from the use of
            renewable energy, and (iii) public policy adopted in North America
            and Europe to encourage the development of clean power.

      (b)   Cost Benefits. Depending on natural gas pricing, many renewable
            energy sources produce energy either at or below long-term marginal
            system cost. Other renewable energy sources have higher marginal
            costs, but provide offsetting environmental advantages. Recent
            technological advances have had favourable impacts on the delivered
            cost of clean power energy as well as on reliability and power
            quality. Studies by the American Wind Energy Association show that
            the costs of wind generation are now at or below the costs of gas
            generation in most major markets in the United States. A recent
            study by two engineering professors at Stanford University concluded
            that the direct costs of wind generation in the United States are
            equal to those associated with energy produced from coal.

      (c)   Environmentally Preferred. Wind power, geothermal, small hydro and
            solar facilities are not considered to have significant greenhouse
            gas emissions. Biomass facilities, which are

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            generally considered to have zero carbon emissions on a net basis
            after consideration of the entire fuel cycle, provide substantial
            reductions in particulate emissions compared to other methods of
            biomass waste disposal. Landfill gas plants, which bum the methane
            gas produced by landfill operations, substantially reduce methane
            emissions. Methane is nine times more detrimental to the upper
            atmosphere ozone layer than carbon dioxide. Although biomass
            projects do emit nitrogen oxides and other pollutants that are the
            subject of environmental regulation, the levels of such pollutants
            are typically well below those produced by more traditional sources
            of energy.

            International environmental agreements, such as the Kyoto Protocol
            to the United Nations Framework Convention on Climate Change, have
            set targets for greenhouse gas emission reductions. By signing the
            Protocol, Canada has agreed to reduce its emissions of green house
            gases (GHG) by 6 percent before 2010 relative to 1990 levels. Along
            with ratifying the Kyoto Protocol, the Canadian Government in
            November 2002 released the Climate Change Plan for Canada. It set
            out a three-step approach for achieving Canada's Kyoto target. The
            government has since also released an updated document entitled
            Moving Forward on Climate Change. A Plan for Honouring our Kyoto
            Commitment, The Greenhouse Gas Technology Investment Fund Act
            enacting this legislation was introduced into the House of Commons
            in late 2004 and was assented to June 29, 2005. While the main
            feature of the Bill will be to meet Canada's Kyoto commitments while
            minimizing the economic pain to fossil fuel emitting or fossil fuel
            using corporations, renewable energy generators may receive
            inducements to undertake new projects, thereby helping to reduce
            Canada's net GHG contributions. Signed into law on October 12, 2004
            H.R. 4520, the "American Jobs Creation Act of 2004," is a U.S.
            federal tax bill adding Section 45 tax credit for LFG
            electricity-generating facilities placed in service between the
            bill's enactment and December 31, 2005. Qualifying facilities can
            obtain a 5-year credit at 0.9 cents per kilowatt-hour.

            The Bush Administration has announced a number of initiatives
            designed to foster renewable energy development, including the
            "American Jobs Creation Act of 2004" and the "Energy Policy Act of
            2005". In 2001, U.S. Vice President Richard Cheney announced the
            White House's objective of tripling the use of renewable fuels, such
            as solar, biomass and wind power, from about two percent of the
            United States' current energy demand to six percent within 20 years.
            In addition, active efforts to encourage the development and use of
            renewable energy are currently occurring at the state level. A
            number of states, including California, New York, Texas,
            Massachusetts and others, have implemented renewable portfolio
            standards that require or encourage the use of more renewable energy
            in the state.

      (d)   Energy Security. Clean power facilities, which utilize local
            renewable energy sources, are less vulnerable to political factors
            that may affect the availability or cost of energy sources on the
            world market. Due to favourable characteristics of clean power,
            these faciiities are more likely to operate in a more supportive
            regulatory environment.

THE ENVIRONMENTAL CHOICE(M) PROGRAM

      The Environmental Choice(M) Program (the "EcoLogo Program"), is a
labelling program established by Environment Canada which assists consumers to
identify products and services that are less harmful to the environment and as a
result provides a market incentive to manufacturers and suppliers of
environmentally preferred products and services. The EcoLogo Program is a part
of the Global Ecolabelling Network, which is an international association of
ecolabelling programs. Certification under the EcoLogo Program results in the
right of a manufacturer or supplier to carry the EcoLogo(M) label.

      To be authorized to carry the EcoLogo(M) label, a clean power source must
typically meet or exceed all applicable governmental and industrial safety and
performance standards and laws and regulations including, for facilities located
in Canada, the Fisheries Act and the Canadian Environmental Protection Act.

      The EcoLogo Program certification criteria for all sources of energy are
as follows: (i) the facility must be operating, reliable, non-temporary and
practical, (ii) during project planning and development, appropriate
consultation with communities and stakeholders must have occurred, and prior or
conflicting land use, biodiversity losses and scenic, recreational and cultural
values must have been addressed: (iii) no adverse impacts can be created for any
species recognized as endangered or threatened; (iv) supplementary non-renewable
fuels must not be used in more than two percent of the fuel heat input required
for generation; and (v) sales levels of EcoLogo Program-certified electricity
must not exceed production/supply levels.

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      There are also additional criteria relating to specific energy sources.
For example: windpower facilities must take measures to protect endangered bird
species; waterpower facilities must comply with regulatory licenses and protect
indigenous species and habitat including fish migration patterns; and biomass
facilities must use only wood wastes, agricultural wastes and/or dedicated
energy crops and must observe environmental management systems including
environmentally sound harvesting practices.

      The Fund is the first income fund to be certified under the EcoLogo
Program and to be authorized to carry the EcoLogo(M) label. In February 2004,
the Fund received certification for GRS, in which the Fund has an indirect
investment. GRS is now authorized to carry the EcoLogo(M) label.

WIND

WINDPOWER GENERATION PROCESS

      The wind can be used to generate electricity by making use of wind
turbines that face the prevailing wind direction. When the wind blows, large
rotor blades on the wind turbines are rotated, generating energy that is
converted to electricity. Most modern wind turbines in use in North America
consist of a rotor mounted on a shaft connected to a speed increasing gear box
and high speed generator. Sophisticated computer monitoring systems are commonly
employed to control the angle of and power output from the rotor blades to
ensure that the rotor blades are turned to face the wind direction, and
generally to monitor all wind turbines installed at a windpower facility. The
longer the blades are, the larger the area 'swept' by the rotor and the greater
the energy output. The trend is moving towards larger machines as capital and
operational efficiencies are realized by using larger machines and a greater
number of machines at a wind site. Most wind turbines start operating at a speed
of three to five metres per second, reach maximum power in a wind speed range
from about 11 to 15 metres per second, and stop operating at speeds in excess of
25 metres per second.

ADVANTAGES OF WINDPOWER GENERATION

      Construction Flexibility

Windpower facilities are relatively simple to construct when compared to more
traditional electricity-producing facilities. A 50 MW windpower facility can be
constructed within 6 to 12 months of its start date, as compared to several
years for other technologies.

      Low Operating Costs

Windpower facilities do not have any fuel costs, which can be a significant and
highly volatile cost for fossil-fuelled plants. In addition, many windpower
plants can be operated by a single person from a central monitoring system.
Combined with the low maintenance and reliability of equipment, operating
expenses are comparatively low.

      Operational Flexibility

Wind turbines are modular and as such can be added to an existing site quickly
to increase overall system reliability and performance. Windpower facilities are
compatible with agricultural uses, thereby permitting sites to be erected in
areas where traditional technologies would cause substantial harm. As windpower
facilities use no fuels, the logistical problem of supplying fuel to remote
locations is eliminated.

      Reliability

The capability to operate when the wind is available is an indication of a
turbine's reliability. According to AWEA, this is typically 98 percent or more
for modern U.S. and European wind turbines.

      Environmentally Preferred

Windpower facilities produce no greenhouse gas emissions or acid rain, both of
which have significant negative impacts on the environment. Windpower generation
minimizes thermal, chemical, radioactive, water and air pollution as compared to
fossil-fuelled and nuclear generated power. The Administrator/Manager estimates
that one 750 kW wind turbine can produce enough power to displace over 6,000,000
lbs. of carbon dioxide, over 14.000 lbs. of sulphur dioxide and over 8.500 lbs.
of nitrous oxides per year which would have been produced by a typical fossil
fuelled power facility.

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FACTORS AFFECTING PERFORMANCE

      The power available from the wind is a function of the cube of the wind
speed. Therefore, a doubling of the wind speed produces eight times the power
output from the turbine. All other things being equal, a turbine at a site with
an average wind speed of five metres per second will produce nearly twice as
much power as a turbine at a location where the wind averages four metres per
second.

      Turbines in wind farms must be carefully arranged to gain the maximum
energy from the wind. Failure to properly align turbines can result in turbines
sheltering other turbines from the prevailing wind. Optimization of generating
capacity of a wind farm not only addresses how the topographic features affect
the local wind flow, but also how the wind turbines will interact with each
other.

      The wind is an intermittent energy resource and thus does not produce
power at an even rate. Electricity demand is constantly fluctuating, and supply
and demand has to be matched on a minute-to-minute basis, 24 hours of the day,
every day of the year. The fluctuation caused by the introduction of windpower
to the system is not discernible above these normal fluctuations, and according
to AWEA it should not impact system reliability until electricity generated from
wind turbines reaches approximately 20 percent of the total system supply.

WATERPOWER

THE WATERPOWER GENERATION PROCESS

      Waterpower is generated by harnessing the force created as water falls
from a higher elevation of the headpond to the lower elevation of the downstream
tailrace. The difference in elevation between the headpond and the tailrace is
referred to as "head" or "operating head". The energy in the moving water is
ultimately converted into electric energy. The water generally flows through an
intake pipe or tunnel (known as the penstock) to a turbine, which is essentially
a water wheel. The turbine spins a shaft attached to a generator that converts
the mechanical energy of the spinning shaft into electricity. The electricity is
then sent through a transformer where its characteristics are adjusted so that
it can be sent along the transmission system. The water, after going through the
turbine, exits the generating station through the draft tube and the tailrace
where it rejoins the main stream of the river.

ADVANTAGES OF WATERPOWER GENERATION

      Reliability

      The equipment involved in producing waterpower power has relatively few
moving parts. This contributes to a long life and low maintenance requirements.
Unplanned outage rates for waterpower units are among the lowest in the
electricity industry.

      Low Operating Costs

      Other than property taxes and water royalties or license fees paid to
governmental authorities or first nations, waterpower facilities have minimal
fuel costs and therefore minimize the volatility of their cost structures
compared to fossil-fuelled plants. As well, most waterpower facilities can be
operated remotely by a single person from a centralized control centre. As a
result of these factors, the low maintenance requirement and the reliability of
waterpower equipment, operating expenses for waterpower facilities are
comparatively low and predictable.

      High Operational Flexibility

      Waterpower facilities can adjust quickly to changes in demand and,
depending on the flow of the river or headponds, a waterpower facility can
service both the base power requirements of its customers as well as their peak
power requirements.

      Environmentally Preferred

      Waterpower generation produces virtually no greenhouse gas emissions or
emissions that create acid rain, both of which have significant negative impacts
on the environment. Waterpower generation creates none of the thermal, chemical,
radioactive, water and air pollution produced by fossil-fuelled and nuclear
generated generation. Instead of producing substantial amounts of residual
wastes during the power generation process, waterpower generation simply returns
the water to the river.

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FACTORS AFFECTING PERFORMANCE

      The performance of waterpower facilities is primarily affected by
available water flows, which can be projected based on the hydrological
information available for a particular site. Hydrology is usually measured using
gauges which record water flows over a period of time. Statistical principles
are then applied to this information to permit reasonable projections of
production. Notwithstanding the typical accuracy of hydrological projections,
revenues at waterpower facilities are significantly affected by low and high
water flows within the watercourses on which the facilities are located. Low
water flows typically result in a decrease in power production from a waterpower
facility, as can extremely high water flows if they result in severe flooding
which damages facilities. Available water flows are affected by climatic factors
such as precipitation and temperatures.

BIOMASS

BIOMASS GENERATION PROCESS

      The principal technology for the conversion of biomass for electricity
production is combustion. The combustion process generates hot flue gases that
in turn produce steam in the heat exchange sections of boilers. The steam is
used to generate electricity in the turbine/generator.

      Electricity production from biomass is being used, and is expected to
continue to be used, as base load power. Much of this is associated with the
wood and wood products industries that obtain electricity and thermal energy
from biomass.

ADVANTAGES OF BIOMASS GENERATION

      Lower emissions

      Biomass combustion produces negligible amounts of sulphur dioxide and
nitrous oxide emissions. Biomass facilities significantly reduce particulate
emissions associated with the disposal of wood waste by the forest products
industry.

      Reduction of Greenhouse Gases

      Biomass is a renewable resource that consumes carbon dioxide during its
growing cycle. Sources of biomass such as wood waste would otherwise have to be
disposed of by either incineration or dumping at a landfill site. As a result,
a biomass facility contributes no additional carbon dioxide emissions from those
that would otherwise have been produced at incineration facilities or from decay
in landfill sites (in which lecheates would also be produced). To the extent
that energy produced at a biomass plant replaces energy that would have been
required from a fossil fuel power facility, greenhouse gas emissions are further
reduced.

      Fuel Costs

      Biomass facilities generally have minimal fuel costs other than the
transportation costs. Therefore, the volatility of their cost structures, other
than transportation costs, is minimized compared to fossil fuelled plants.

LANDFILL GAS

GAS COLLECTION PROCESS AND POWER GENERATION

      Landfill gas results from the decomposition of organic materials that
occurs over a period of time. Landfill gas consists mainly of methane and carbon
dioxide, generally in roughly equal proportions. Methane gas may be used for
electrical power generation and other industrial applications. The rate,
quantity and quality of methane gas produced as a result of the decomposition is
dependent on the landfill's size, depth, age, moisture content, exposure to air,
and compaction. Once certain conditions are met, landfill gas is typically
produced at a landfill site on a continual basis for a period of time with
production generally increasing while the landfill is "open" or accepting more
waste and for a short period after the landfill is "closed". Once a landfill is
closed, gas production generally diminishes over time. Methane gas production at
a landfill is estimated using models developed in association with the U.S.
Environmental Protection Agency and other similar bodies.

      Landfill gas is collected by drilling gas wells into the landfill at
predetermined separations. Horizontal renches may also be used in conjunction
with, or in lieu of, vertical wells. The wells are connected by a series of
pipes that deliver the gas to the processing and conversion stations. The entire
piping system is under a partial

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vacuum, causing gas in the landfill to migrate toward the wells. Once the gas is
collected, it is delivered to a central processing facility where it is filtered
to remove any particles, trace contaminants and condensate that may be suspended
in the gas stream. Landfill gas can then be carried to a flare, to a pipeline
for sale or to a conversion station for power generation.

      Several types of equipment can be used to generate electricity from
landfill gas. The most common pieces of equipment are reciprocating engines or
internal combustion engines, which are customised to run on landfill gas. Where
there is a high gas flow, steam turbines or combined cycle gas and steam
turbines are used rather than reciprocating or internal combustion engines.

OUTLOOK FOR THE U.S. LANDFILL GAS INDUSTRY

      The Energy Information Administration of the U.S. Department of Energy
estimates in its Annual Energy Outlook 2004 that electricity generation from
municipal solid waste, including both direct firing with solid waste and the use
of landfill gas, is projected to increase by nearly 9 billion kWh, from 22
billion kWh in 2002 to about 31 billion kWh in 2025. No new capacity additions
are expected for plants that burn solid waste, but landfill gas power generation
capacity is projected to grow by more than 1 GW during this period. The Landfill
Gas Methane Outreach Program ("LMOP"), a branch of the U.S. Environmental
Protection Agency (EPA), estimates that there are approximately 2,300 landfills
in the U.S., 600 of which are large enough to merit economic consideration as an
energy project, in addition to about 400 currently operating LFG projects.

ADVANTAGES OF LANDFILL GAS POWER GENERATION

      Readily Available

      Proper disposal that results in the containment and consolidation of solid
waste into landfill sites is common practice worldwide. The containment results
in decomposition of the organic waste, which in turn produces landfill gas. The
proper disposal of landfill gas continues to grow in importance, as does the
opportunity to convert landfill gas to other forms of energy such as space
heating and cooling, industrial processing or mechanical energy and electricity.

      Environmentally Preferred

      Methane produced in landfills has been described as one of the largest
contributors to the 'greenhouse' effect. It has been estimated that the global
warming potential of methane is 21 times greater than that of carbon dioxide.
The production of electricity through combustion of methane dramatically reduces
the gas' global warming potential.

      Incremental Benefit

      Absent another application, methane (which is a highly combustible gas)
must be burned, or flared, in a controlled manner in order to reduce the hazard
arising from gas build-up and to comply with environmental regulations regarding
methane emissions. Converting landfill gas into electricity not only allows
landfill sites to reduce the hazard associated with uncontrolled methane
emissions and to comply with such environmental regulations, but also provides a
source of energy to the community.

      High Operational Flexibility

      Landfill gas projects are dynamic facilities that respond to constant
change and variation, and are therefore easily adaptable. As landfills are in a
constant state of growth and shifting, new wells are introduced when old wells
are capped or sections of the landfills are closed. Use of standardized
well-known technology (reciprocating and combustion engines) adds to the
operating flexibility by allowing easy redeployment of the generating equipment.

FACTORS AFFECTING PERFORMANCE

      Electricity production and gas sales from landfill gas facilities are
dependent upon the rate, quantity and quality of gas flow from a landfill site
which in turn may be affected by the composition of waste at a landfill site,
including the type of waste that is added to the site over time, the size,
depth, age, moisture content, exposure to air and compaction of that waste and
whether a landfill is "open" or "closed". An "open" landfill site is one that

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continues to accept new waste while a "closed" landfill has ceased to do so.
Extreme cold temperature may also slow the decomposition process contributing to
reduced production levels of landfill gas.

                               DISTRIBUTION POLICY

      At the Fund's Annual General and Special Meeting held on May 28, 2003,
Unitholders approved the payment of monthly distributions which commenced in
July 2003 and which are paid the last business day of the month, following the
record date. Previously, distributions were paid on a quarterly basis.

      The Fund declared distributions per unit of $1.1297 in 2002 and $0.9569 in
2003. The distributions declared in 2002 were in respect of the period
commencing November 14, 2001 to December 31, 2002 and were declared at an
annualized rate of $0.925 for the period from November 14, 2001 to September 30,
2002 and $0.95 for the fourth quarter of 2002. The annualized rate remained at
$0.95 until October 2004.

      In November 2004, the Fund declared a cash distribution of $0.05833 per
Trust Unit for the month of November 2004. This distribution, payable on
December 31, 2004, represented a reduction of $0.02084 per Trust Unit from
previous monthly distributions.

      The decision to make this reduction in distributions was a response to
changes in the Fund's business environment that became apparent in the third
quarter of 2004. Most importantly, these changes included:

      Continued weakening of the U.S. dollar against the Canadian dollar.

      Evidence that the achievement of production growth in Gas Recovery
Systems, LLC ("GRS") - the Fund's largest U.S. investment - will take longer
than previously expected.

      A distribution of $0.0583 declared in respect of December 2004 was paid in
January 2005. Monthly distributions throughout 2005 were at the same level of
$0.058334, equivalent to an annualized rate of $0.70.

      Any income of the Fund that is applied to any cash redemptions of Trust
Units or is otherwise unavailable for cash distribution will be distributed to
Unitholders in the form of additional Trust Units. Such additional Trust Units
will be issued pursuant to applicable exemptions under applicable securities
laws, discretionary exemptions granted by applicable securities regulatory
authorities or a prospectus or similar filing.

                              MARKET FOR SECURITIES

      The Trust Units and Debentures are listed for trading on the Toronto Stock
Exchange under the symbols CLE.UN and CLE.DB, respectively

      The following table sets forth the reported high and low trading prices
and the average daily trading volumes of the outstanding Trust Units on the
Toronto Stock Exchange for the periods indicated.

--------------------------------------------------------------------------------
                                                                 AVERAGE DAILY
2005                                 HIGH            LOW            VOLUME
--------------------------------------------------------------------------------
January                              6.95            6.64           144,970
February                             7.77            6.82           188,910
March                                7.60            6.67            68,866
April                                7.15            6.69            65,258
May                                  7.25            6.19            94,827
June                                 6.60            6.10            80,769
July                                 6.97            6.30            83,260
August                               6.98            5.50           122,091
September                            6.30            5.65            96,008
October                              5.99            5.00            91,035
November                             5.24            4.01           186,142
December                             4.77            4.22           235,088
--------------------------------------------------------------------------------

      The following table sets forth the reported high and low trading prices
and the average daily trading volumes of the outstanding Debentures on the
Toronto Slock Exchange for the periods indicated.

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--------------------------------------------------------------------------------
                                                                 AVERAGE DAILY
2005                                 HIGH             LOW            VOLUME
--------------------------------------------------------------------------------
January                             105.00          101.55              482
February                            106.00          102.15              574
March                               104.75          101.00              790
April                               104.00           99.11              803
May                                 102.00           99.50              507
June                                102.99          100.50              583
July                                103.50          100.30              531
August                              103.25           99.11              568
September                           105.11           99.50            1,530
October                             100.00           91.11              913
November                             97.00           78.91            1,824
December                             90.00           81.01              984
--------------------------------------------------------------------------------

                                     RATINGS

      Credit ratings are intended to provide investors with an independent
measure of the credit quality of an issue of securities and are indicators of
the likelihood of payment and of the capacity and willingness of a company to
meet its financial commitment on an obligation in accordance with the terms of
the obligation.

      Credit ratings are not recommendations to purchase, hold or sell
securities and do not address the market price or suitability of a specific
security for a particular investor. Credit ratings may not reflect the potential
impact of all risks on the value of securities. In addition, real or anticipated
changes in the rating assigned to a security will generally affect the market
value of that security. No assurance can be given that a rating will remain in
effect for any given period of time or that a rating will not be revised or
withdrawn entirely by a rating agency in the future.

RATING OF TRUST UNITS

      Standard and Poor's, a division of The McGraw-Hill Companies ("S&P") has
assigned a Stability Rating of SR-3 with a Stable Outlook and an Aggressive
Distribution Profile Assessment to the Fund's distributable cash flow. S&P's
stability ratings are current opinions on the prospective relative stability of
distributable cash flow generation of Canadian income funds. Stability ratings
refer specifically to the prospective relative sustainability and variability of
an income fund's distributable cash flows, which underpin cash distributions.
The stability rating scale is organized such that a rating of SR-1 signifies the
lowest level of cash distribution variability and the highest level of cash
distribution sustainability, while a rating of SR-7 signifies the highest level
of variability and the highest amount of uncertainty in the sustainability of
the cash distribution stream. The outlook indicates the expected short to
medium-term stability ratings trend. A stable, negative, positive, or developing
outlook expresses which way the rating might change if current trends continue
over a one to three-year horizon. The distribution profile assessment considers
an income fund's distribution policy in the context of its cash flow dynamics,
and comments on the ability of a fund to maintain a given level of
distributions, expressed on a seven-step scale, ranging from very conservative
to very aggressive. The distribution profile assessment takes into account,
among other factors, how aggressive or conservative the income fund's
distribution policy is relative to the variability of its distributable cash
flow generation. Stability ratings do not comment on an income fund's net asset
value, share price, yield, or return on capital. In addition, stability ratings
are not a recommendation to buy, sell or hold a particular income fund, nor do
they comment on the suitability of any investment for a given investor. A
stability rating may be subject to revision or withdrawal at any time by S&P.

      Specifically, issuers rated as SR-3 are considered to have a high level of
distributable cash flow generation stability relative to other income funds in
the Canadian market place.

      The Dominion Bond Rating Service ("DBRS") assigned a stability rating of
STA-3 (low) to the Trust Units on December 15, 2004. In November 2004, the Trust
Units were placed "Under Review with Negative Implications" following the Fund's
announcement to cut its distributions from $0.95/Trust Unit per year to
$0.70/Trust Unit per year. The stability rating was confirmed on August 23,
2005. The rating is based on a rating scale developed by DBRS which provides an
indication of both the stability and sustainabiiity of an income fund's cash
distributions per unit over the longer term. Seven key factors are considered in
determining a

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stability rating. They are (1) Operating Characteristics, (2) Asset Quality, (3)
Financial Profile, (4) Diversification, (5) Size and Market Position, (6)
Sponsorship/Governance, and (7) Growth. Rating categories range from STA-I to
STA-7, with STA-1 being the highest rating.

      Issuers rated as STA-3 are considered to have good stability and
sustainability of distributions per unit.

ISSUER RATING

      DBRS assigned an Issuer Rating of BB (high) to the senior most ranking
unsecured obligations of the Fund. Previously, the Issuer Rating assigned by
DBRS was BBB (low) with a negative outlook. In November 2004, the Issuer Rating
had been placed "Under Review With Negative Implications" following the Fund's
announcement to cut its distributions.

      DBRS's long-term credit ratings are on a rating scale that ranges from AAA
to D, which represents the range from highest to lowest quality of such
securities rated. DBRS's BB (high) rating assigned is within the fifth highest
of the ten rating categories for long-term debt. Debt securities rated "BB" are
defined to be speculative and non-investment grade. Protection of interest and
principal is considered uncertain, particularly during periods of economic
recession. Entities in the BB range typically have limited access to capital
markets and additional liquidity support. In many cases, deficiencies in
critical mass, diversification, and competitive strength are additional negative
considerations. A reference to "high" or "low" reflects the relative strength
within the rating category.

                        TRUSTEES OF THE FUND AND OF CPOT

TRUSTEE OF THE FUND

      Computershare Trust Company of Canada is the sole trustee ("Trustee") of
the Fund. The Fund has no officers.

CPOT TRUSTEES

      The CPOT Indenture sets the number of Trustees at a minimum of five and a
maximum of seven Trustees, with the number of Trustees within this range to be
set from time to time by resolution of the Trustees. The Trustees have resolved
that there will be six trustees ("CPOT Trustees"), four of which are "unrelated"
and "independent" to the Administrator/Manager.

      The CPOT Trustees will hold their office until the next annual meeting of
the CPOT Unitholders or until his or her successor is duly elected or appointed,
or earlier if he dies or resigns or is removed or disqualified or his term
otherwise ends in accordance with the CPOT Indenture. The Fund currently owns
all of the issued and outstanding CPOT Units and accordingly the Fund, pursuant
to the direction of the Unitholders, elects all of the CPOT Trustees not
appointed by the Administrator/Manager, who is currently entitled to appoint Mr.
H. Allen Jackson, who also serves as Chairman of the CPOT Board of Trustees and
as Chairman of the Board of Directors of the Administrator/Manager, and one
other CPOT Trustee (the "Manager Trustees"). Mr. A. Stephen Probyn currently
serves as the second Manager Trustee.

      The names, municipalities of residence and principal occupations of the
CPOT Trustees are set out below. Unless otherwise indicated, the CPOT Trustees
have been in their principal occupations for more than five years. Units shown
are Trust Units ("TUs") and CPLP Exchangeable Class B Units ("ExUs"), which may
be voted as Trust Units.

                                     - 46 -

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------------------------------------------------------------------------------------------------------------------
                                                                                                      UNITS
                                                                                                   BENEFICIALLY
NAME AND MUNICIPALITY                                                       CPOT TRUSTEE             OWNED OR
    OF RESIDENCE                     PRINCIPAL OCCUPATION                       SINCE               CONTROLLED
------------------------------------------------------------------------------------------------------------------

SEAN G. CONWAY          Director, Queen's University Institute of         May 9, 2005                  NIL
Kingston, Ontario       Intergovernmental Relations since June 2005;      independent
(3),(4),(2)             Public Policy Advisor, Gowling Lafleur            Trustee
                        Henderson LLP (law firm) since January 2004;
                        Visiting Fellow, School of Policy Studies,
                        Queen's University from January 2004 to
                        May 2005; Member, Ontario Legislative Assembly
                        from 1975 to October 2003

JOHN C. FOX             Managing Director, Perseus, LLC (an               November 14, 2001            NIL
Washington, D.C.        investment banking company) since April,          Independent
(1),(2),(3),(4),(5)     2000; Chief Operating Officer, Ontario Power      Trustee and Lead
                        Generation Inc. (electrical utility) until        Trustee
                        April, 2000

H.ALLEN JACKSON         Private Consultant; officer and director of       April 8, 2003             10.000 TUs
Mississauga, Ontario    the Administrator and other companies in the      Manager Trustee
(5)                     Probyn Group                                      and Chairman

------------------------------------------------------------------------------------------------------------------




------------------------------------------------------------------------------------------------------------------
                                                                                                      UNITS
                                                                                                   BENEFICIALLY
NAME AND MUNICIPALITY                                                       CPOT TRUSTEE             OWNED OR
    OF RESIDENCE                     PRINCIPAL OCCUPATION                       SINCE               CONTROLLED
------------------------------------------------------------------------------------------------------------------

The Hon. DONALD S.      Senior Advisor, Public Policy, Lang Michener      November 14,2001          1.000 TUs
MACDONALD               LLP (law firm) since September, 2002; Senior      Independent
Toronto, Ontario        Advisor, UBS Bunting Warburg (investment          Trustee
(1),(2),(3),(4),(6)     bank) until December, 2002

DONALD M. MCCUTCHAN     International Policy Advisor, Gowling Lafleur     November 14,2001          1,450 TUs
Toronto, Ontario        Henderson LLP (law firm).                         Independent
(1),(4),(5)                                                               Trustee

A. STEPHEN PROBYN       Chairman, Probyn Eastman Ltd. and officer and     October 31, 2001         486,667 TUs
Toronto, Ontario (7)    director of other companies in the Probyn         Manager Trustee          451,880 ExUs
                        Group                                             and                      (7)
                                                                          Chief Executive
                                                                          Officer
------------------------------------------------------------------------------------------------------------------


 Note:    (1)   Member of the Audit Committee or which Mr. Macdonald is Chair.

          (2)   Member of the Compensation Committee, of which Mr. Conway is
                Chair.

          (3)   Member of the Nominating Committee., of which Mr. Fox is Chair.

          (4)   Member of the Review Committee, of which Mr. Fox is Chair.

          (5)   Member of the Special Committee, of which Mr. Fox is Chair.

          (6)   The Hon. Donald S. Macdonald was a director of CanEnerco Limited
                in July 2000 when it made certain filings under the insolvency
                laws of Canada.

          (7)   Mr. Probyn is employed by Probyn & Company and is Chief
                Executive Officer and a shareholder of Probyn Eastman Ltd.,
                parent company of the Probyn Group of companies. The Probyn
                Group holds a 57% interest in Canadian Environmental Energy
                Corporation ("CEEC"). The balance of the interest in CEEC is
                held by Sun Life Assurance Company (32%) and other shareholders
                (11%). The Administrator/Manager is a wholly-owned subsidiary of
                CEEC. CEEC owns 451,880 of the issued and outstanding
                Exchangeable Units, which may be voted as Trust Units of the
                Fund. As at December 31. 2005, the shareholders of Probyn
                Eastman Ltd. owned or beneficially controlled a total of
                1,015,548 Units, including Exchangeable Units.

      As of December 31, 2005, all Trust Units and Exchangeable Class B Units
owned or controlled by all CPOT Trustees are shown in the preceding table. The
total of 950,997 Units represents 2.69 percent of all outstanding Trust Units
and all of the Exchangeable Class B Units.

AUDIT COMMITTEE

      Pursuant to the CPOT Indenture, the CPOT Trustees are required to appoint
an audit committee of three Independent CPOT Trustees from among their numbers.
The audit committee members are comprised of Messrs. John Fox, Donald S.
Macdonald (Chair) and Donald M. McCutchan, all of whom are independent and

                                     - 47 -

EX-3.12 52nd Page of 80 TOC 1st Previous Next ↓Bottom Just 52nd
financially literate within the meaning of applicable securities legislation.
This committee performs its mandate in accordance with the Audit Committee
charter, attached as Appendix A hereto. Mr. Macdonald was the Minister of
Finance for the government of Canada, a Senior Advisor to UBS Warburg, and
Chairman of the Advisory Committee on Competition in Ontario's Electricity
System. Mr. Fox is a Managing Director of Perseus, LLC, an investment bank, and
was Chief Operating Officer of Ontario Power Generation Inc. Mr. McCutchan was a
senior official with the Department of Finance, government of Canada, and has
worked with the IMF, World Bank and the OECD and is President of the Canadian
Associations of Income Funds.



                               EXTERNAL AUDITOR SERVICE FEES
-------------------------------------------------------------------------------------------
                 Audit Fees(1)    Audit-Related Fees(2)    Tax Fees(3)    All Other Fees(4)
-------------------------------------------------------------------------------------------

 2005                $ 111,500                $ 232,478      $ 138,334             $ 97,202
 2004                $ 214,638                $ 139,933      $ 105,073             $ 49.371
-------------------------------------------------------------------------------------------


Notes:    (1)   Represents the aggregate fees billed by the Fund's external
                auditor for the audit services.

          (2)   Represents the aggregate fees billed for assurance and related
                services by the Fund's external auditor reasonably related to
                the performance of the audit or review of the Fund's financial
                statements and not reported under "Audit Fees". Services include
                quarterly review and translation.

          (3)   Represents the aggregate fees billed for professional services
                rendered by the Fund's external auditor for tax compliance, tax
                advice and tax planning. Services include annual tax returns.

          (4)   Represents the aggregate fees billed for products and services
                provided by the Fund's external auditor not otherwise provided
                for in this table. Services include tax services regarding
                structuring debt, equity and other investments and U.S.
                structure review.

OFFICERS OF CPOT

      As of the date of this Annual Information Form, the following individuals
serve as the senior officers of CPOT:



----------------------------------------------------------------------------------------------
NAME                  NOTES          MUNICIPALITY OF RESIDENCE           POSITION
----------------------------------------------------------------------------------------------

H. Allen Jackson        1            Mississauga, Ontario            Chairman
Rob A. Roberti          2            Toronto, Ontario                Chief Financial Officer
----------------------------------------------------------------------------------------------


1.    H. Allen Jackson also currently serves as a Manager Trustee of CPOT and as
      a director of the Administrator/Manager.

2.    Rob A. Roberti is an independent contractor under contract with CPOT since
      November l6, 2005. He served as Treasurer of CPOT before taking over the
      responsibilities of Chief Financial Officer from Mr. Peter M. Korth, an
      officer of the Administrator/Manager who served as Chief Financial Officer
      (2001 -2005) and who left to pursue other opportunities effective December
      31, 2005. Mr. Roberti also serves as a director and/or officer of CPOT
      subsidiaries and affiliates, and a member of the Disclosure Committee of
      the Administrator/Manager.

      Mr. Roberti had also served as an officer of CPOT previously, He was
      Treasurer of CPOT from December 19, 2001 -July 11, 2003 while employed as
      Senior Manager - Project Finance by the Administrator/Manager's affiliate,
      Probyn & Company Inc. (March 20, 2000-July 11, 2003). He left to become
      Manager, Financing and Development at Regional Power Inc., operator of the
      waterpower facilities wholly-owned by CPOT (July 2003-March 2005). Prior
      to joining Probyn & Company, Mr. Roberti was employed by The Canada Life
      Assurance Company (1993-2000), primarily in Ihe investment division.

                          THE ADMINISTRATOR AND MANAGER

THE ADMINISTRATION AGREEMENT

      Under the Administration Agreement, the Administrator/Manager shall
provide certain administrative and support services to the Fund, including those
necessary to: (i) ensure compliance by the Fund with continuous disclosure
obligations under applicable securities legislation; (ii) provide investor
relations services; (iii) provide or cause to be provided to Unitholders all
information to which Unitholders are entitled under the Fund Trust Indenture,
including relevant information with respect to income taxes; (iv) call and hold
meetings of Unitholders and holders of Special Trust Units and distribute
required materials, including notices of meetings and information circulars, in
respect of all such meetings; (v) provide for the calculation of distributions
to Unitholders; (vi) attend to all administrative and other matters arising in
connection with any redemptions of Trust Units; and (vii) ensure compliance with
the Fund's limitations on non-resident ownership. All reasonable out-of-pocket
expenses incurred by the Administrator/Manager in connection with the provision
of these services will be for the account of the Fund.

      The Administration Agreement has an initial ten-year term which expires on
October 31, 2011 (the "Initial Term"), and is automatically renewable for two
additional six-year terms (each a "Renewal Term") unless at the end of the
Initial Term or the first Renewal Term, as the case may be, the Administrator
provides the Fund with written notice to the contrary 180 days prior to the
expiry of the Initial Term or the first Renewal Term, respectively. After the
second Renewal Term, the Administration Agreement becomes automatically
renewable for successive periods of five years (each an "Additional Renewal
Term"), unless at the end of the second Renewal Term or the then

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current Additional Renewal Term, as the case may be, the Fund provides the
Administrator or the Administrator provides the Fund written notice to the
contrary at least one year prior to the expiry of the second Renewal Term or the
then current Additional Renewal Term, respectively. The Administration Agreement
may be terminated by either party in the event of the insolvency or receivership
of the other party or in the case of default by the other party in the
performance of a material obligation under the Administration Agreement (other
than as a result of the occurrence of a force majeure event) which is not
remedied within 30 days after notice thereof has been delivered or in the event
that the Management Agreement is terminated.

      In addition, the Administrator/Manager has implemented a disclosure policy
requiring that certain trades in the Trust Units be reported in accordance with
the insider reporting provisions of the securities legislation in each of the
provinces and territories of Canada, including trades by a CPOT Trustee, the
Administrator/Manager and its directors and senior officers (while it is
Administrator of the Fund or Manager of CPOT, or any successor thereto), and
CEEC and its directors, senior officers and significant shareholders (while the
Administrator/Manager is administrator of the Fund or Manager of CPOT, or any
successor thereto) and further requiring that such individuals or entities
comply with insider trading liability provisions of the securities legislation
in each of the provinces and territories of Canada. The covenants of the
Administrator/Manager in respect of the disclosure policy referred to above may
only be amended or waived upon receipt of prior written approval from the
Ontario Securities Commission.

THE MANAGEMENT AGREEMENT

      CPOT and the Administrator/Manager entered into the Management Agreement
pursuant to which the Administrator/Manager will be engaged by CPOT to provide
management services to CPOT. These services include: (i) supervising the
operation of the Waterpower Facilities and the Whitecourt Facility and
administering the U.S. Windpower Loan, the Chapais investments and the GRS
Loans; (ii) assisting CPOT in development, implementation and monitoring of a
strategic plan for CPOT; (iii) assisting CPOT in developing an annual business
plan which will include operational and capital expenditures budgets; (iv)
assisting CPOT in developing acquisition strategies and investigation of
potential acquisitions and analysis of feasibility of potential acquisitions;
(v) carrying out acquisitions or dispositions and related financings required
for such transactions; (vi) assisting in connection with any financing of CPOT
or the Fund; and (vii) assisting CPOT with the preparation, planning and
co-ordination of management and trustees meetings.

      The Management Agreement has an initial ten-year term which expires on
October 31, 2011 (the "Initial Term"), and is automatically renewable for two
additional six-year terms (each a "Renewal Term") unless at the end of the
Initial Term or the first Renewal Term, as the case may be, the
Administrator/Manager provides the Fund with written notice to the contrary 180
days prior to the expiry of the Initial Term or the first Renewal Term,
respectively. After the second Renewal Term, the Management Agreement becomes
automatically renewable for successive periods of five years (each an
"Additional Renewal Term"), unless at the end of the second Renewal Term or the
then current Additional Renewal Term, as the case may be, the independent
Trustees of CPOT provide the Administrator/Manager or the Administrator/Manager
provides the Fund written notice to the contrary at least one year prior to the
expiry of the second Renewal Term or the then current Additional Renewal Term,
respectively. CPOT may terminate the Management Agreement earlier if a
substantial deterioration of its business occurs, taken as a whole, which is not
caused by an event of force majeure, if, within six months of the deterioration,
such termination is approved by a written resolution of holders of Trust Units
and Special Trust Units representing at least 66 2/3 percent of the votes
attached to the outstanding Trust Units and Special Trust Units or at a meeting
of holders of Trust Units and Special Trust Units by a resolution approved by
the holders representing at least 50% of all voles attached to the outstanding
Trust Units and Special Trust Units and at least 66 2/3 percent of the votes
attached to the Trust Units and Special Trust Units which are voted at the
meeting, in each case excluding votes attached to the outstanding Trust Units
and Special Trust Units held by or on behalf of the Administrator or its
affiliates.

      CPOT or the Administrator/Manager may terminate the Management Agreement
immediately in the event of the insolvency or receivership of the other party,
or in the case of a default by the other party in the performance of a material
obligation under the Management Agreement (other than as a result of the
occurrence of a force majeure event) which is not remedied within 30 days after
notice thereof has been delivered.

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NAMES, RESIDENCES AND PRINCIPAL OCCUPATIONS OF DIRECTORS AND OFFICERS OF THE
ADMINISTRATOR OF THE FUND AND ADMINISTRATOR/MANAGER OF CPOT

      The names, municipalities of residence and principal occupations of the
directors and officers of the Administrator/Manager as of December 31, 2005, are
set out below. Unless otherwise indicated, the directors and officers have been
in their principal occupations for more than five years. Units shown are Trust
Units ("TUs") and CPLP Exchangeable Class B Units ("ExUs"), which may be voted
as Trust Units.



------------------------------------------------------------------------------------------------------------------
                                                                                                        UNITS
                                                                                                    BENEFICIALLY
NAME AND MUNICIPALITY     POSITION WITH THE                                                           OWNED OR
    OF RESIDENCE        ADMINISTRATOR/MANAGER                 PRINCIPAL OCCUPATION                   CONTROLLED
------------------------------------------------------------------------------------------------------------------

H.ALLEN JACKSON         Chairman and             Private Consultant; officer and director of       10,000 TUs
Mississauga. Ontario    Director                 other companies in the Probyn Group
(1),(2)

A. STEPHEN PROBYN       President,               Chairman, Probyn Eastman Ltd.; officer and        486,667 TUs
Toronto, Ontario        Chief Executive Officer  director of other companies in the                451,880 ExUs
(1),(2)                 and Director             Probyn Group                                      (7)

DR. BARBARA C.          Director                 President, Probyn Eastman Ltd.; officer and       77,000 TUs
EASTMAN                                          director of other companies in the Probyn Group
Toronto, Ontario
(2)

PETER M. KORTH          Vice President and       Vice President of Probyn & Company                NIL
Mississauga, Ontario    Chief Financial          Inc., a member of the Probyn Group
(2),(3),(4)             Officer
------------------------------------------------------------------------------------------------------------------


(1)   As noted elsewhere in this document, Mr. H. Allen Jackson and Mr. A.
      Stephen Probyn also currently serve as Manager Trustees of CPOT. Mr.
      Jackson is Chairman of the CPOT Board of Trustees,

(2)   As Administrator of the Fund, the Administrator/Manager is responsible for
      compliance and disclosure matters. The members of the Board of Directors
      and the Chief Financial Officer of CPOT are the members of the
      Administrator/Manager's Disclosure Committee.

(3)   Mr. Korth served as Chief Financial Officer from the date of the Fund's
      IPO (November 14, 2001) until he left Probyn & Company to pursue other
      opportunities on December 31,2005.

      During his service as Chief Financial Officer, he worked first as an
      independent contractor engaged by CEEC, the owner of the
      Administrator/Manager (August 27-December 31, 2001); then, as
      Vice-President, Chief Financial Officer and full-time employee of the
      Administrator/Manager (January 1, 2002-June 30, 2004); and lastly, he
      provided these services to the Administrator/Manager and CPOT as a
      Vice-President of Administraior/Manager's affiliate, Probyn & Company Inc.
      (July 1, 2004-December 31, 2005). Previously, he was employed by TransAlta
      Corp. (1994-2001).

(4)   As previously shown for the Officers of CPOT, effective January 1, 2006,
      Mr. Rob A. Roberti was appointed as CPOTs Chief Financial Officer. Mr.
      Roberti is an independent contractor under contract with CPOT since
      November 16, 2005, serving as Treasurer of CPOT before taking over the
      responsibilities of Chief Financial Officer of CPOT from Mr. Korth.

      As of December 31, 2005, all Trust Units and Exchangeable Class B Units
owned or controlled by all directors and executive officers of the
Administrator/Manager are shown in the preceding table. The same holdings for
Mr. Jackson and Mr. Probyn were previously shown in the table of CPOT Trustees.
The total of 1,025,548 Units represents 2.9 percent of all outstanding Trust
Units and all of the Exchangeable Class B Units.

CONFLICTS OF INTEREST

      The CPOT Trust Indenture provides that if a CPOT Trustee or an officer of
CPOT is (i) a party to a contract or transaction or proposed contract or
transaction with the Fund or CPOT or any of their respective affiliates, or (ii)
a director or officer of, or otherwise has a material interest in, any person or
any person or affiliate of any person who is a party to a contract or
transaction or proposed contract or transaction with the Fund or CPOT or any of
their respective affiliates, then such individual must disclose in writing to
the CPOT Trustees the nature and extent of his interest. Except in certain
specified circumstances, a CPOT Trustee who is a party to or so interested in
such a transaction or contract will be precluded from voting on such a
transaction or contract but the presence of such CPOT Trustee at the relevant
meeting shall be counted towards any quorum requirement. In addition, the CPOT
Trast Indenture provides that a material change to the Management Agreement or
the Administration Agreement or any increase in fees or other amounts payable by
CPOT or the Fund thereunder and the terms of any agreement entered into by the
Fund with the Administrator/Manager or any affiliate of the

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Administrator/Manager must be approved by a majority of the CPOT Trustees who
are "unrelated" to the Administrator/Manager.

      The Administrator/Manager may be considered to be the promoter of the Fund
by reason of its initiative in organizing the business and affairs of the Fund.
Two affiliates of the Administrator/Manager, Probyn Power Services Inc. and
Probyn Whitecourt Management Inc., which are subsidiaries of Probyn & Company
Inc., are the operators of the Biomass Facilities.

      The Fund and certain affiliates are participants in several related party
transactions as discussed in Note 18 of the 2005 Annual Financial Statements
which is hereby incorporated by reference.

      As previously noted, A. Stephen Probyn, one of the
Administrator/Administrator/Manager's initial appointees as CPOT Trustees, owns
an indirect interest in CEEC, the Administrator/Manager and Probyn & Company.

      As noted above under the heading "General Development of the Business -
Special Committee", the special committee of CPOT is investigating unitholder
value enhancement opportunities. While this committee is initially concentrating
on the disposition of the Fund's investment in GRS, it may investigate other
opportunities which may involve a termination or assignment of the Management
Agreement and/or the Administration Agreement. If the existing Management
Agreement and/or the Administration Agreement were terminated, there is a
potential for a material conflict of interest on a valuation of the Management
Agreement and the Administration Agreement between the Independent Trustees
representing CPOT and the Manager and its officers and directors, two of whom
serve as the Manager Trustees of CPOT. Further, the Independent Trustees and the
Manager do not agree as to whether and under what circumstances CPOT is entitled
to terminate the Management and Administration Agreements.

                             DESCRIPTION OF THE FUND

GENERAL

      The Fund is an unincorporated open-ended trust created pursuant to the
Fund Trust Indenture and governed by the laws of the Province of Ontario.
Although the Fund is a "mutual fund trust" pursuant to the Tax Act, the Fund
will not be a mutual fund under applicable securities laws.

      The Fund is a limited purpose trust and its activities are restricted to:
(a) acquiring, holding, transferring, disposing of and otherwise dealing with
investments in debt or equity securities of CPOT and investments in other
corporations, partnerships, trusts or other persons involved in the business of
generating electricity and other related businesses; (b) borrowing funds for the
foregoing purposes; (c) temporarily holding cash and other short term
investments in connection with and for the purposes of the Fund's activities,
including paying administration and trust expenses, paying any amounts required
in connection with the redemption of Trust Units and making distributions to
Unitholders; (d) issuing Trust Units and other securities of the Fund (including
securities convertible into or exchangeable for Trust Units or other securities
of the Fund, or warrants, options or other rights to acquire Trust Units or
other securities of the Fund), for the purposes of (i) obtaining funds to
conduct the activities described in paragraph (a), above, including raising
funds for further acquisitions; (ii) repayment of any indebtedness or borrowings
of the Fund; (iii) implementing Unitholder rights plans or incentive option or
other compensation plans, if any, established by the Fund; and (iv) making
non-cash distributions to Unitholders as contemplated by the Fund Trust
Indenture including pursuant to distribution reinvestment plans, if any,
established by the Fund; and (e) repurchasing or redeeming Trust Units or other
securities of the Fund, subject to the provisions of the Fund Trust Indenture
and applicable law. The Fund qualifies as a mutual fund trust for the purposes
of the Tax Act. The following is a summary of certain terms of the Fund Trust
Indenture that, together with other summaries of the terms of the Fund Trust
Indenture appearing elsewhere in this annual information form, are qualified in
their entirety by reference to the text of the Fund Trust Indenture.

TRUSTEE

      Computershare is the trustee of the Fund and also acts as transfer agent
and registrar for the Trust Units. The Fund Trust Indenture provides that,
subject to the specific limitations contained in the Fund Trust Indenture, the
Trustee has full, absolute and exclusive power, control and authority over the
property of the Fund and over the affairs of the Fund to the same extent as if
the Trustee were the sole and absolute beneficial owner of such property in its
own right and may do all such acts and things as it, in its sole judgment and
discretion, deems necessary or

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incidental to, or desirable for, the carrying out of the duties of the Trustee
as established pursuant to the Fund Trust Indenture.

      The Trustee delegated the execution of many of its powers to the
Administrator/Manager, as the administrator of the Fund, pursuant to the terms
of the Administration Agreement and to such other persons as the Trustee deems
necessary or desirable. The Trustee is able to resign its trust thereunder by
giving to the Manager, in its capacity as administrator of the Fund, not less
than 90 days' prior notice. The Trustee may be removed at any time, with or
without cause, by Ordinary Resolution.

      The Trustee may also be removed at any time by the Manager, in its
capacity as administrator of the Fund, by notice in writing to the Trustee in
the event that (a) the Trustee is declared bankrupt or insolvent or shall enter
into liquidation, whether compulsory or voluntary, to wind up its affairs; (b)
the assets of the Trustee, or a substantial part thereof, shall become subject
to seizure or confiscation; (c) the Trustee shall otherwise become incapable of
performing its responsibilities under the Fund Trust Indenture; or (d) if the
Trustee at any time ceases (i) to be incorporated under the laws of Canada or a
province thereof, (ii) to be resident in Canada, (iii) to be authorized under
the laws of the Province of Ontario to carry on the business of a trust company,
or (iv) to have reported on its most recent audited consolidated financial
statements shareholders' equity of at least $50,000,000.

      Any such resignation or removal will take effect on the earlier of 90 days
after the date notice of such resignation is duly given, such Ordinary
Resolution is approved or such notice of the Administrator/Manager is given, as
the case may be, and the date a successor Trustee is appointed or elected. If no
success or Trustee has been appointed or elected within 60 days of such notice
of resignation, Ordinary Resolution or notice of the Administrator/Manager, as
the case may be, any Unitholder, the Administrator/Manager or any other
interested person may apply to a court of competent jurisdiction for the
appointment of a successor Trustee.

      The Fund Trust Indenture provides that the Trustee has no liability to any
Unitholder, holder of Special Trust Units or annuitant for (a) any action taken
in good faith in reliance on any documents that are, prima facie, properly
executed; (b) depreciation of, or loss to, the Fund incurred by reason of the
sale of any property; (c) relying on any inaccuracy in any evaluation provided
by the Administrator/Manager or any other appropriately qualified person; (d)
any action or failure to act of the Administrator/Manager; or (e) any other
action or failure to act (including, without limitation, the failure to compel
in any way any former trustee to redress any breach of trust or any failure by
the Administrator/Manager to perform its duties under the Fund Trust Indenture
or any material contract;, unless such liabilities arise out of a breach of the
Trustee's standard of care as set out in the Fund Trust Indenture or the
Administrator/Managers standard of care as provided in the Administration
Agreement or the Trustee's or such officers or agent's negligence, wilful
default or fraud. If the Trustee has retained an appropriate expert or advisor
with respect to any matter connected with its duties under the Fund Trust
Indenture or any material contract, the Trustee may act or refuse to act based
on the advice of any such expert or advisor without liability. The Trustee,
where it has met its standard of care, shall be indemnified out of the assets of
the Fund in respect of any liability and all costs, charges and expenses
relating to any action, suit or proceeding or for any taxes or other government
charges imposed upon the Trustee in consequence of its performance of its
duties, but shall have no additional recourse against Unitholders. In addition,
the Fund Trust Indenture contains other customary provisions limiting the
liability of the Trustee.

      The Fund Trust Indenture provides that the Trustee is entitled to
indemnification from the Fund in respect of the performance of its duties under
the Fund Trust Indenture in the absence of its negligence, wilful default or
fraud.

CERTAIN RESTRICTIONS ON TRUSTEE'S POWERS

      The Fund Trust Indenture provides that the Trustee may not, without
approval by Ordinary Resolution; (i) vote the CPOT Units with respect to any
matter which, under the CPOT Trust Indenture, requires or permits the approval
of the holders of CPOT Units by ordinary resolution; or (ii) except in the event
of a voluntary resignation by the auditors, appoint or change the auditors of
the Fund. Additionally, the Fund Trust Indenture provides that the Trustee may
not, without approval by Special Resolution: (i) vote the CPOT Units with
respect to any matter which, under the CPOT Trust Indenture, requires or permits
the approval by the holders of CPOT Units by special resolution; (ii) amend the
Fund Trust Indenture (except in certain limited circumstances described under
"Amendments to the Fund Trust Indenture" below); (iii) sell, lease or exchange
all or substantially all of the property of the Fund, other than (a) in the
ordinary course of business, (b) in special redemptions permitted under the Fund
Trust Indenture, and (c) in order to initially acquire the CPOT Units and CPOT
Notes; (iv) authorize the termination, liquidation or winding-up of the Fund,
other than at the end of the term of the Fund (as described under "- Term of the
Fund" below); and (v) authorize the combination or merger or similar transaction
of the Fund with any other person if following such transaction the holders of
equity interests in such other person or the

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entity resulting from such combination or merger or other transaction would
equal more than 25.0 percent of the outstanding Trust Units or other securities
resulting from such combination, merger or other transaction.

TRUST UNITS

      An unlimited number of Trust Units are issuablc pursuant to the Fund Trust
Indenture. Each Trust Unit is transferable and represents an equal undivided
beneficial interest in any distributions from the Fund whether of net income,
net realized capital gains or other amounts, and in the net assets of the Fund
in the event of termination or winding-up of the Fund. All units of the Fund,
except the Special Trust Units, are of the same class with equal rights and
privileges. Except as set out under - "Redemption at the Option of Unitholders"
below, the Trust Units have no conversion, retraction, redemption or pre-emptive
rights.

      The Fund Trust Indenture also provides for the issuance of an unlimited
number of Special Trust Units that are used solely for providing voting rights
to persons holding Class B Units of CPLP or certain other shares, units or other
securities that are exchangeable for Trust Units. Each Special Trust Unit
entitles the holder thereof to a number of votes at any meeting of Unitholders
equal to the number of Trust Units which may be obtained upon the exchange of
the exchangeable shares, units or other securities, including the Class B Units
of CPLP, to which the Special Trust Unit relates, but does not otherwise entitle
the holder to any rights with respect to the Fund's property or income. See
"Description of CPLP - Partnership Units".

ISSUANCE OF TRUST UNITS

      The Fund Trust Indenture provides that the Trust Units or rights to
acquire Trust Units may be issued at the times, to the persons, for the
consideration and on the terms and conditions that the Trustee, determines
including pursuant to any Unitholder rights plan or any incentive option or
other compensation plan established by the Fund. Trust Units may be issued in
satisfaction of any non-cash distribution by the Fund to Unitholders on a pro
rata basis. The Fund Trust Indenture also provides that immediately after any
pro rata distribution of Trust Units to all 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.

CASH DISTRIBUTIONS

      The Fund intends to make monthly distributions of Distributable Cash to
Unitholders of record on each Record Date on the last business day in each month
following the Record Date.

      Any income of the Fund that is applied to any cash redemptions of Trust
Units or is otherwise unavailable for cash distribution will be distributed to
Unitholders in the form of additional Trust Units. Such additional Trust Units
will be issued pursuant to applicable exemptions under applicable securities
laws, discretionary exemptions granted by applicable securities regulatory
authorities or a prospectus or similar filing.

      The agreements relating to the Credit Facilities and the Sun Life Facility
contain restrictions on the payment of cash distributions by CPOT to the Fund in
certain circumstances and hence could affect the ability of the Fund to pay such
distributions to Unitholders if such circumstances arise.

REDEMPTION AT THE OPTION OF UNITHOLDERS

      Trust Units are redeemable at any time on demand by the holders thereof
upon delivery to the Fund of a duly completed and properly executed notice
requesting redemption in a form reasonably acceptable to the Trustee together
with any certificates representing Trust Units to be redeemed and written
instructions as to the number of Trust Units to be redeemed. Upon tender of
Trust Units of a Unitholder for redemption, all rights to and under the Trust
Units tendered for redemption shall be surrendered and the holder thereof shall
be entitled to receive a price per Trust Unit (the "Redemption Price") equal to
the lesser of: (i) 90 percent of the weighted average price per Trust Unit at
which the Trust Units have traded on the principal exchange on which Trust Units
are listed (or, if the Trust Units are not listed on any stock exchange, on the
principal market on which the Trust Units are quoted for trading) during the
period of the last 10 days during which Trust Units traded on such exchange or
market immediately prior to the date on which the Trust Units were tendered for
redemption; and (ii) an amount equal to (a) the closing price of the Trust Units
on the date on which the Trust Units were tendered for redemption, on the
principal stock exchange on which Trust Units are listed (or, if the Trust Units
are not listed on any stock exchange, on the principal market on which the Trust
Units are quoted for trading) if there was a trade on the date on

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which the Trust Units were tendered for redemption and the stock exchange or
market provides a closing price; or (b) an amount equal to the average of the
highest and lowest prices of Trust Units on the date on which the Trust Units
were tendered for redemption, on the principal exchange on which Trust Units are
listed (or, if the Trust Units are not listed on any exchange, on the principal
market on which the Trust Units are quoted for trading) if there was trading on
the date on which the Trust Units were tendered for redemption and the exchange
or other market provides only the highest and lowest trading prices of Trust
Units traded on a particular day; or (c) the average of the last bid and ask
prices on the date on which the Trust Units were tendered for redemption, on the
principal exchange on which Trust Units are listed (or, if the Trust Units are
not listed on any exchange, on the principal market on which the Trust Units are
quoted for trading) if there was no trading on the date on which the Trust Units
were tendered for redemption.

      The aggregate Redemption Price payable by the Fund in respect of any Trust
Units surrendered for redemption during any month shall be satisfied by way of a
cash payment by the Fund within five days after the end of the calendar month in
which the Trust Units were tendered for redemption; provided that the
entitlement of Unitholders to receive cash upon the redemption of their Trust
Units is subject to the limitations that: (i) the total amount payable in cash
by the Fund in respect of such Trust Units and all other Trust Units tendered
for redemption in the same calendar month shall not exceed $250,000 (provided
that such limitation may be waived at the sole discretion of the Trustee); or
(ii) at the time such Trust Units are tendered for redemption, the outstanding
Trust Units shall be listed for trading on The Toronto Stock Exchange or traded
or quoted on any other stock exchange or market which the Trustee considers, in
its sole opinion, provides representative fair market value prices for the Trust
Units; or (iii) the normal trading of Trust Units is not suspended or halted on
any stock exchange on which the Trust Units are listed (or, if not listed on a
stock exchange, on any market on which the Trust Units are quoted for trading)
on the date that the Trust Units are tendered for redemption or for more than
five trading days during the 10-day trading period prior to the date on which
the Trust Units are tendered for redemption.

      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 shall be the fair market value thereof as determined by the
Administrator/Manager and shall, subject to all necessary regulatory approvals,
be paid and satisfied by way of a distribution in specie of CPOT Notes (each
CPOT Note in the principal amount of $100) or other assets held by the Fund
(other than CPOT Units). No fractional CPOT Notes will be distributed and where
the number of CPOT Notes to be received by a Unitholder includes a fraction,
such number shall be rounded to the next lowest whole number.

      It is anticipated that this redemption right will not be the primary
mechanism for holders of Trust Units to dispose of their Trust Units. CPOT Notes
and other assets of the Fund, which may be distributed in specie to Unitholders
in connection with a redemption, will not be listed on any stock exchange and no
market is expected to develop in such CPOT Notes and other assets of the Fund.
CPOT Notes and other Fund assets so distributed may be subject to resale
restrictions under applicable securities laws. CPOT Notes and other assets of
the Fund so distributed may not be qualified investments for trusts governed by
registered retirement savings plans, registered retirement income funds,
registered education savings plans and deferred profit sharing plans. In no
event, however, will CPOT Notes be qualified investments for a trust governed by
a deferred profit sharing plan if CPOT is an employer under the plan or does not
deal at arm's length with such an employer. See "Canadian Federal Income Tax
Considerations".

REPURCHASE OF TRUST UNITS

      The Fund is permitted, from time to time, to purchase Trust Units for
cancellation in accordance with applicable securities legislation and the rules
prescribed under applicable stock exchange or regulatory policies. Any such
purchases will constitute an "issuer bid" under Canadian provincial securities
legislation and must be conducted in accordance with the applicable requirements
thereof.

BOOK ENTRY FORM AND DEPOSITORY SERVICE

      Except as otherwise provided below, the Trust Units are issued in "book
entry only" form and must be purchased or transferred through participants
("Participants") in the depository service of The Canadian Depository for
Securities Limited or a successor (collectively "CDS"), which include securities
brokers and dealers, banks and trust companies. The Fund will cause a global
certificate or certificates representing any newly issued Trust Units to be
delivered to, and registered in the name of, CDS or its nominee. Except as
described below, no Unitholder will be entitled to a certificate or other
instrument from the Fund or CDS evidencing that Unitholder's ownership thereof,
and no Unitholders will be shown on the records maintained by CDS except through
a book entry account of a Participant acting on behalf of such Unitholder. Each
person who acquires Trust Units will receive a customer

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confirmation of purchase from the registered dealer from or through which the
Trust Unit is acquired in accordance with the practices and procedures of that
registered dealer. The practices of registered dealers may vary, but generally
customer confirmations are issued promptly after execution of a customer order.
CDS is responsible for establishing and maintaining book entry accounts for its
Participants having interests in the Trust Units.

      The ability of a beneficial owner of Trust Units to pledge the Trust Units
or otherwise take action with respect to such owner's interest therein (other
than through a Participant) may be limited due to the lack of physical
certificates.

      If: (i) the Fund determines that CDS is no longer willing or able to
discharge properly its responsibilities as depository with respect to the Trust
Units and the Fund is unable to locate a qualified successor; or (ii) the Fund
at its option elects, or is required by law, to terminate the book entry system;
or (iii) Unitholders representing beneficial interests aggregating not less than
66 percent of the outstanding Trust Units determine that the continuation of the
book entry system is no longer in the best interests of the Unitholders, then
Trust Units will be issued in fully registered form to Unitholders or their
nominees.

TRANSFER OF TRUST UNITS

      Transfers of ownership in the Trust Units are effected only through
records maintained by CDS or its nominee for such Trust Units with respect to
interests of Participants, and on the records of Participants with respect to
interests of persons other than Participants. Unitholders who are not
Participants, but who desire to purchase, sell or otherwise transfer ownership
of or other interests in the Trust Units, may do so only through Participants.

PAYMENTS OF DISTRIBUTIONS

      Payments of distributions on each Trust Unit are made by the Fund to CDS
or its nominee, as the case may be, as the registered holder of the Trust Units
and the Fund understands that such payments are forwarded by CDS or its nominee,
as the case may be, to Participants. As long as CDS or its nominee is the
registered owner of the Trust Units, CDS or its nominee, as the case may be,
will be considered the sole owner of the Trust Units for the purposes of
receiving payments on the Trust Units. The responsibility and liability of the
Fund in respect of the Trust Units is limited to making payment of any income or
capital in respect of the Trust Units to CDS or its nominee.

MEETINGS OF UNITHOLDERS

      The Fund Trust Indenture provides that there shall be an annual meeting of
the Unitholders and holders of Special Trust Units immediately prior to, and at
the same place as, each annual meeting of holders of CPOT Units for the purpose
of: (i) directing and instructing the Trustee as to the manner in which the
Trustee shall vote the Fund's CPOT Units in respect of (a) the election of the
unrelated CPOT Trustees at the corresponding annual meeting of CPOT Unitholders,
(b) the appointment of the auditors of CPOT for the ensuing year and (c)
generally, any other matter which requires a resolution of holders of CPOT
Units; (ii) appointing the auditors of the Fund for the ensuing year; and (iii)
transacting such other business as the Trustee may determine or as may be
properly brought before the meeting.

      The Fund Trust Indenture provides that meetings of Unitholders may be
convened at any time and for any purpose by the Trustee, the
Administrator/Manager or the CPOT Trustees and must be convened, except in
certain circumstances, if requisitioned in writing by the holders of Trust Units
and/or Special Trust Units representing not less than 10 percent of the
aggregate votes attached to the Trust Units and Special Trust Units then
outstanding. A requisition will be required to state in reasonable detail the
business proposed to be transacted at the meeting.

      Unitholders and holders of Special Trust Units are entitled to attend and
vote at all meetings of the Unitholders either in person or by proxy and a
proxyholder is not required to be a Unitholder or a holder of a Special Trust
Unit. Two persons present in person or represented by proxy and representing in
the aggregate at least 10 percent of the votes attached to all outstanding Trust
Units and Special Trust Units shall constitute a quorum for the transaction of
business at all such meetings. At any meeting at which a quorum is not present
within one-half hour after the time fixed for the holding of such meeting, the
meeting, if convened upon the request of the holders of Trust Units and/or
Special Trust Units, shall be dissolved, but in any other case, the meeting will
stand adjourned to a day not less than 14 days later and to a place and time as
chosen by the chairman of the meeting and if at such adjourned meeting a quorum
is not present, the holders of Trust Units and Special Trust Units present
either in person or by proxy shall be deemed to constitute a quorum.

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      The Fund Trust Indenture contains provisions as to the notice required and
other procedures with respect to the calling and holding of meetings of
Unitholders and holders of Special Trust Units.

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 Fund Trust Indenture provides that at no time may non-residents
of Canada be the beneficial owners of more than 49 percent of the Trust Units or
Special Trust Units then outstanding. The Trustee may require declarations as to
the jurisdictions in which beneficial owners of Trust Units or Special Trust
Units are resident. If the transfer agent and registrar becomes aware, as a
result of requiring such declarations as to beneficial ownership, that the
beneficial owners of at least 49 percent of the Trust Units or Special Trust
Units then outstanding are, or may be, non-residents or that such a situation is
imminent, the transfer agent and registrar will advise the Trustee and, upon
receiving a direction from the Trustee, may make a public announcement thereof
and shall not accept a subscription for Trust Units or Special Trust Units from
or issue or register a transfer of Trust Units or Special Trust Units to a
person unless the person provides a declaration that the person is not a
non-resident of Canada. If, notwithstanding the foregoing, the transfer agent
and registrar determines that 49 percent or more of the Trust Units or Special
Trust Units are held by non-residents, the transfer agent and registrar may,
upon receiving a direction and suitable indemnity from the Trustee, send a
notice to non-resident holders of Trust Units or Special Trust Units, chosen in
inverse order to the order of acquisition or registration or in such manner as
the transfer agent and registrar may consider equitable and practicable,
requiring them to sell their Trust Units or Special Trust Units or a portion
thereof within a specified period of not less than 60 days. If the persons
receiving such notice have not sold the specified number of Trust Units or
Special Trust Units or provided the transfer agent and registrar with
satisfactory evidence that they are not non-residents within such period, the
transfer agent and registrar may on behalf of such persons sell such Trust Units
or Special Trust Units and, in the interim, shall suspend the voting and
distribution rights attached to such Trust Units or Special Trust Units. Upon
such sale, the affected holders shall cease to be holders of Trust Units or
Special Trust Units and their rights shall be limited to receiving the net
proceeds of such sale.

AMENDMENTS TO THE FUND TRUST INDENTURE

      The Fund Trust Indenture contains provisions that allow it to be amended
or altered from time to time by Special Resolution. The Trustee is entitled to,
at its discretion and without the consent, approval or ratification of the
Unitholders and holders of Special Trust Units, make certain amendments to the
Fund Trust Indenture, including amendments; (i) for the purpose of ensuring
continuing compliance with applicable laws, regulations, requirements or
policies of any governmental authority having jurisdiction over the Trustee or
the Fund; (ii) which, in the bonafide opinion of the Trustee, provide additional
protection for the Unitholders and holders of Special Trust Units or to preserve
or clarify the provision of desirable tax treatment to Unitholders and holders
of Special Trust Units; (iii) to remove any conflicts or inconsistencies in the
Fund Trust Indenture or to make minor corrections which are, in the opinion of
the Trustee, necessary or desirable and not prejudicial to the Unitholders and
holders of Special Trust Units; and (iv) which, in the opinion of the Trustee,
are necessary or desirable in the interests of the Unitholders and the holders
of Special Trust Units as a result of changes in Canadian taxation laws.

TERM OF THE FUND

      The Fund has been established for a term to continue until no property of
the Fund is held by the Trustee. The termination, liquidation or winding-up of
the Fund may also be required by Special Resolution.

TAKE-OVER BIDS

      The Fund Trust Indenture contains provisions to the effect that if a
take-over bid is made for the Trust Units and not less than 90 percent 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 offerer will be entitled to acquire the
Trust Units held by Unitholders who did not accept the take-over bid on the same
terms on which the offeror acquired Trust Units from Unitholders who accepted
the take-over bid.

INFORMATION AND REPORTS

      The Fund will furnish to Unitholders such financial statements of the Fund
(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.

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Prior io each meeting of Unitholders, the Trustee will provide the Unitholders
(along with notice of such meeting) all such information as is required by
applicable law to be provided to such holders. CPOT has undertaken to provide
the Fund with: (i) a report of any material change that occurs in the affairs
of CPOT in form and content that it would file with applicable regulatory
authorities if it were a reporting issuer (or equivalent); and (ii) all
financial statements that it would be required to file with applicable
regulatory authorities if it were a reporting issuer (or equivalent) 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.

                               DESCRIPTION OF CPOT

      The CPOT Trust Indenture contains provisions substantially similar to
those of the Fund Trust Indenture. The principal differences between the CPOT
Trust Indenture and the Fund Trust Indenture are those described below. The
description below is a summary only and is qualified in its entirety by
reference to the text of the CPOT Trust Indenture and the Fund Trust Indenture.

GENERAL

      CPOT is an unincorporated open-ended trust established pursuant to the
CPOT Trust Indenture and governed by the laws of the Province of Ontario. CPOT
is a limited purpose trust and its activities are restricted to the conduct of
the business of, and the ownership, operation and lease of assets and property
in connection with, the generation, transmission, distribution and purchase and
sale of electricity, having investments and other direct or indirect rights in
companies or other entities involved in the business of the generation,
transmission, distribution, purchase and sale of electricity, and engaging in
all activities ancillary or incidental thereto.

TRUSTEES/GOVERNANCE

      The CPOT Trust Indenture, as amended by the annual and special meeting of
Unitholders on May 9, 2005, provides that there be a minimum of five and a
maximum of seven CPOT Trustees, with the number of CPOT Trustees within this
range to be set from time to time by resolution of the CPOT Trustees. The term
of office of each of the CPOT Trustees expires at each annual meeting, unless a
CPOT Trustee otherwise resigns, dies, is removed or is disqualified pursuant to
the terms of the CPOT Trust Indenture.

      A majority of the Trustees must be residents of Canada. As long as the
Fund is a reporting issuer (or equivalent) in any jurisdiction in Canada, a
majority of the CPOT Trustees must also be independent trustees "unrelated" in
respect of the Administrator/Manager and any affiliate of the
Administrator/Manager (as such term is used in relation to the definition of
"unrelated directors" in the Toronto Stock Exchange Company Manual) and
independent within the meaning of applicable securities legislation (the
"Independent Trustees").

      During the term of the Management Agreement, the Administrator/Manager is
currently entitled to appoint Mr. H. Allen Jackson and one other representative
as Manager Trustees. Following the retirement of Mr. Jackson, the Chairman will
be appointed from among the Independent Trustees. The Administrator/Manager will
retain the right to appoint one Manager Trustee and one non-voting observer to
the Board of Trustees, in consultation with the Nominating Committee. The
appointment of a Manager Trustee is by notice of the Administrator/Manager to
the Fund.

      Under the CPOT Trust Indenture, election of the other CPOT Trustees, all
of whom are Independent Trustees, is by ordinary resolution of the holders of
CPOT Units. The CPOT Board of Trustees nominates candidates from among
individuals recommended by the Nominating Committee, in consultation with the
Administraior/Manager.

      The CPOT Trust Indenture provides that the CPOT Trustees exercise their
power and carry out their functions as Trustees honestly, in good faith with a
view to the best interests of CPOT and the holders of CPOT Units and that in
connection therewith they exercise the degree of care, diligence and skill that
a reasonably prudent person would exercise in comparable circumstances. The CPOT
Trust Indenture provides that a Trustee thereunder is entitled to
indemnification from CPOT in respect of the performance of his duties under the
CPOT Trust Indenture unless it is determined by a final decision of a court
having competent jurisdiction that (i) he has not acted with prudence and
diligence and in good faith with a view to the best interests of CPOT and the
holder of CPOT Units, or (ii) in the case of a criminal or administrative
proceeding that is enforced by a monetary penalty, he did not have reasonable
grounds to believe his conduct was lawful.

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EX-3.12 63rd Page of 80 TOC 1st Previous Next ↓Bottom Just 63rd
      CPOT Trustees who do not receive a salary from the Fund are entitled to
such reasonable remuneration as the CPOT Trustees may determine. Currently all
CPOT Trustees are entitled to such reasonable remuneration, however, the CPOT
Trustees have agreed that, A. Stephen Probyn, the indirect owner of the
Administrator/Manager, will not receive any remuneration for his services as a
CPOT Trustee. See "Trustees, Management and Operations - Remuneration of Trustee
and CPOT Trustees".

RESTRICTIONS ON CPOT TRUSTEES' POWERS

      The CPOT Trust Indenture provides that the CPOT Trustees may not, without
the approval of holders of CPOT Units by ordinary resolution (as defined
therein): (i) take any action upon any matter which under applicable law
(including policies of Canadian securities commissions) or applicable stock
exchange rules would require the approval of holders of CPOT Units by ordinary
resolution had CPOT been a reporting issuer (or equivalent) in the jurisdictions
in which the Fund is a reporting issuer (or equivalent) and had the CPOT Units
been listed for trading on the stock exchanges where the Trust Units are listed
for trading, respectively; (ii) subject to certain exceptions, elect the
unrelated CPOT Trustees; and (iii) subject to certain exceptions, appoint or
change the auditors of CPOT. Furthermore, the CPOT Trust Indenture states that
the CPOT Trustees may not, without the approval of the holders of CPOT Units by
special resolution (as defined therein): (i) take any action upon any matter
which under applicable law (including policies of Canadian securities
commissions) or applicable stock exchange rules would require the approval of
holders of CPOT Units by special resolution or super-majority as defined or
described therein had CPOT been a reporting issuer (or equivalent) in the
jurisdictions in which the Fund is a reporting issuer (or equivalent) and had
the CPOT Units been listed for trading on the stock exchanges where the Trust
Units are listed for trading, respectively; (ii) amend the CPOT Trust Indenture
except in certain limited circumstances similar to those under which the Fund
Trust Indenture may be amended without consent of Unitholders and holders of
Special Trust Units; (iii) sell, lease or exchange all or substantially all of
the property of CPOT other than in the ordinary course of business; (iv)
authorize the termination, liquidation or winding-up of CPOT, other than at the
end of the term of CPOT; or (v) authorize the combination, merger or similar
transaction of CPOT with any other person.

REDEMPTION RIGHT

      The CPOT Units are redeemable at any time on demand by the holders thereof
upon delivery to CPOT of a duly completed and properly executed notice requiring
CPOT to redeem the CPOT Units, in a form reasonably acceptable to the CPOT
Trustees, together with the certificates for the CPOT Units representing the
CPOT Units to be redeemed and written instructions as to the number of CPOT
Units to be redeemed. Upon tender for redemption of CPOT Units by a holder
thereof, the holder of the CPOT Units tendered for redemption will no longer
have any rights with respect to such CPOT Units other than the right to receive
the redemption price for such CPOT Units. The redemption price for each CPOT
Unit tendered for redemption will be equal to:

                                    (A x B)-C
                                    ---------
                                        D

      A = the cash redemption price per Trust Unit of the Fund calculated as of
      the close of business on the date the CPOT Units were so tendered for
      redemption by a CPOT unitholder;

      B = the aggregate number of Trust Units of the Fund outstanding as of the
      close of business on the date the CPOT Units were so tendered for
      redemption by a CPOT unitholder:

      C = the aggregate unpaid principal amount and accrued interest thereon of
      the CPOT Notes and any other indebtedness held by or owed to the Fund and
      the fair market value of any other assets or investments held by the Fund
      (other than CPOT Units) as of the close of business on the date the CPOT
      Units were so tendered for redemption by a CPOT unitholder; and

      D = the aggregate number of CPOT Units outstanding held by the Fund as of
      the close of business on the date the CPOT Units were so tendered for
      redemption by a CPOT unitholder.

      CPOT is also entitled to call for redemption, at any time, all or part of
the outstanding CPOT Units registered in the name of holders thereof other than
the Fund at the same redemption price as described above for each CPOT Unit
called for redemption, calculated with reference to the date the CPOT Trustees
approved the redemption of CPOT Units.

      The aggregate redemption price payable by CPOT in respect of any CPOT Unit
tendered for redemption by the holders thereof during any month will be
satisfied, at the option of the CPOT Trustees: (i) in immediately available
funds by cheque; (ii) by the issuance to or to the order of the holder whose
CPOT Units are to be redeemed

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EX-3.12 64th Page of 80 TOC 1st Previous Next ↓Bottom Just 64th
of such aggregate amount of CPOT Series 2 Notes as is equal to the aggregate
redemption price payable to such holder of CPOT Units rounded down to the
nearest $100, with the balance of any such aggregate redemption price not paid
in CPOT Series 2 Notes to be paid in immediately available funds by cheque: or
(iii) by any combination of funds and CPOT Series 2 Notes as the CPOT Trustees
shall determine in their discretion, in each such case payable or issuable on
the last day of the calendar month following the calendar month in which the
CPOT Units were so tendered for redemption. A holder of CPOT Units whose CPOT
Units are tendered for redemption may elect, at any time prior to the payment of
the redemption price, to receive CPOT Series 2 Notes pursuant to (ii) above in
the place of all or part of the funds otherwise payable, the amount of such CPOT
Series 2 Notes payable to be equal to the funds otherwise payable, rounded down
to the nearest $100.

DISTRIBUTIONS

      Provided that CPOT is not in default, and after the distribution would not
be in default under the Credit Facilities or the Sun Life Facility, and certain
other covenants contained in such facilities would not be breached, CPOT intends
to make monthly cash distributions to holders of record of CPOT Units on the
last business day of each month. Such distributions are to be paid no later than
the last business day of the month following the record date and are intended to
be received by the Fund prior to its related distributions to Unitholders.
Distributable cash of CPOT in respect of a period will generally consist of
earnings of CPOT before income taxes, depreciation and amortization, as
estimated by the CPOT Trustees, less redemption prices paid in respect of such
period, capital expenditure reserves in respect of such period, principal
repayments of indebtedness during such period, the payment of any other costs of
CPOT during such period provided for by the CPOT Trustees, payments of income
tax liability in respect of such period and amounts set aside to repay principal
amounts on the CPOT Notes in respect of such period.

      If the CPOT Trustees determine that CPOT does not have cash in an amount
sufficient to make payment of the full amount of any distribution, the payment
may include the issuance of additional CPOT Units having a value equal to the
difference between the amount of such distribution and the amount of cash which
has been determined by the CPOT Trustees to be available for the payment of such
distribution. The value of each CPOT Unit so issued will be the redemption price
thereof.

      Any CPOT Notes transferred to Unitholders pursuant to a distribution in
specie may be subject to resale and transfer restrictions and cannot be resold
or transferred except as permitted by applicable securities law.

      The ability of CPOT to make distributions to the holders of CPOT Units is
limited or prohibited in certain circumstances pursuant to the Credit Facilities
and the Sun Life Facility.

UNIT CERTIFICATES

      As CPOT Units are not intended to be issued or held by any person other
than the Fund, registration of interests in, and transfers of, the CPOT Units
will not be made through the book-entry system administered by CDS. Rather,
holders of CPOT Units will be entitled to receive certificates therefore.

MEETINGS OF UNITHOLDERS

      An annual meeting of holders of CPOT Units is held at such time and place
as the CPOT Trustees shall prescribe for the purpose of electing the CPOT
Trustees, appointing the auditors of CPOT and transacting such other business as
the CPOT Trustees may determine or as may properly be brought before the
meeting. The annual meeting of Unitholders shall be held within 180 days after
the end of each fiscal year of CPOT. The Trustee is required to vote the Fund's
CPOT Units at any such meeting as directed by Unitholders and holders of Special
Trust Units as described under "Description of the Fund -- Meetings of
Unitholders".

CONFLICTS

      The CPOT Trust Indenture provides that if a CPOT Trustee or an officer of
CPOT is: (i) a party to a contract or transaction or proposed contract or
transaction with the Fund or CPOT or any of their respective affiliates; or (ii)
a director or officer of, or otherwise has a material interest in, any person or
any person or affiliate of any person who is a party to a contract or
transaction or proposed contract or transaction with the Fund or CPOT or any of
their respective affiliates, then such individual must disclose in writing to
the CPOT Trustees the nature and extent of his interest. Except in certain
specified circumstances, a CPOT Trustee who is a party to or so interested in
such a transaction or contract will be precluded from voting on such a
transaction or contract but the presence of such CPOT Trustee at the relevant
meeting shall be counted towards any quorum requirement. In addition, the CPOT
Trust indenture provides that a material change to the Management Agreement or
the

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Administration Agreement or any increase in fees or other amounts payable by
CPOT or the Fund thereunder and the terms of any agreement entered into by the
Fund with the Administrator/Manager or any affiliate of the
Administrator/Manager must be approved by a majority of the CPOT Trustees who
are "unrelated" to the Administrator/Manager.

                               DESCRIPTION OF CPLP

GENERAL

      CPLP is a limited partnership established under the laws of Ontario to
carry on the business of generation, transmission, distribution and purchase and
sale of electricity and other ancillary matters and, in connection with such
business, to own, operate and lease assets and property, to make investments and
hold other direct or indirect rights and to engage in all activities ancillary
and incidental thereto.

GENERAL PARTNER

      The sole general partner of CPLP is Albertaco which is a wholly-owned
subsidiary of CPOT.

PARTNERSHIP UNITS

      CPLP is entitled to issue various classes of partnership interests. CPLP
has outstanding one general partnership unit, which is held by Albertaco, Class
A Units, which are held solely by CPOT, and 451,880 Class B Units, which are
held by CEEC. Holders of Class A Units are entitled to notice of, and to attend
and vote at, all meetings of holders of partnership units except as required by
law and in certain specified circumstances in which the rights of a holder of
Class B Units are affected.

      CEEC acquired its Class B Units as consideration for its sale to the Fund
of all of the common shares of Whitecourt Power. Class B Units, which are
issuabie in series, may also be issued in respect of other acquisitions made by
CPLP from time to time. The Class B Units are, in all material respects,
economically equivalent to the Trust Units. The principal terms of the Class B
Units are: (i) the Class B Units are exchangeable with CPLP for Trust Units at
any time at the option of the holder, unless the exchange would jeopardize the
Fund's status as a "unit trust", "mutual fund trust" or "registered investment"
under the Tax Act; (ii) each Class B Unit entitles the holder thereof to receive
distributions from CPLP, where practicable, equal to distributions made by the
Fund on a Trust Unit; (iii) the Class B Units are accompanied by a Special Trust
Unit which entitles the holder to receive notice of, to attend and to vote at
all meetings of Unitholders: (iv) except as required by law and in certain
specified circumstances in which the rights of a holder of Class B Units are
affected, holders of the Class B Units are not entitled to vote at any meeting
of the limited partners of CPLP; and (v) CPLP is entitled to require the
redemption of the Class B Units in certain specified circumstances.

      CPLP, CPOT, the Fund and the holder of Class B Units have entered into
certain agreements to give effect to the foregoing terms of the Class B Units,
including a voting and exchange agreement specifying the procedures for voting
the Special Trust Unit and an exchange unit support agreement.

                                  RISK FACTORS

      The following are certain risk factors relating to 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 in the
Fund's filings with Canadian Securities Regulators from time to time.

DEPENDENCE UPON CPOT

      The Fund will be entirely dependent upon the operations and assets of the
Facilities through its ownership of CPOT. Accordingly, Distributable Cash will
be dependent upon the ability of CPOT to pay interest on the CPOT Notes and to
pay distributions in respect of the CPOT Units. The profitability of CPOT may be
affected by a number of factors listed in this section. Cash distributions from
CPOT to the Fund and from the Fund to Unitholders are not guaranteed and will
fluctuate with the performance of the investments owned through CPOT.

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UNITHOLDER VALUE ENHANCEMENT PROCESS

      The Fund announced on October 26, 2005 that the Trustees of CPOT had
created a special committee to investigate unitholder value enhancement
opportunities. The special committee has been concentrating its efforts to date
with respect to the investment in GRS. In doing so, it has undertaken a
competitive process to dispose of the GRS investment. On March 29, 2006, the
Fund announced that the special committee received a number of conditional bids
for this investment. While conditional bids regarding a disposition of this
investment have been received, there is no certainty that the disposition can be
completed on terms satisfactory to the special committee. Risks associated with
the potential disposition also include the ability and timing to close a
transaction and the market reaction to the disposition.

TAX RELATED RISKS

      Although the Fund is of the view that all expenses to be claimed by the
Fund, CPOT, Albertaco, CPLP, Whitecourt Power, WPLP, CPOT Title Corp., CPOT
Holdings Corp., CHESEC, CHEL, CHEL Subco Inc., CHESEC LPCO Inc., Erie Shores
Wind Farm General Partner Inc. and 2073991 Ontario Inc. should be reasonable and
deductible and that the cost amount and capital cost allowance claims of such
entities' depreciable properties will have been correctly determined, there can
be no assurance that the Canada Revenue Agency ("CRA") will agree. If CRA
successfully challenges the deducibility of such expenses or the correctness of
such cost amounts or capital cost allowance claims, the return to Unitholders
may be adversely affected.

      Under current legislation, payments of principal and interest on the loans
made by the Fund in connection with the GRS Loans and on the U.S. Windpower Loan
should not be subject to United States withholding taxes. If payments on such
loans were to become subject to United States withholding taxes in the future,
whether as a result of a change in legislation or for other reasons, the Fund's
Distributable Cash could be adversely affected.

      In addition, the Fund expects that borrowers from the Fund under the GRS
Loans will claim various deductions for tax purposes, including deductions for
interest payable on such loans; however there can be no assurance that
applicable taxation authorities will agree that such deductions are permissible,
in whole or in part. If deducibility of such amounts were restricted or denied,
or if a change in legislation were to occur that adversely affected
deducibility, the Fund's Distributable Cash could be adversely affected.

RESOURCE AVAILABILITY AND CONSTANCY

      The revenue generated by the Facilities is proportional to the amount of
electrical energy generated by them. The amount of energy generated at the
Facilities is dependent upon the availability of water flows, wind, biomass or
methane, as the case may be. There can be no assurance that the long-term
availability of such resources will remain unchanged. The U.S. Windpower
Facilities or the Erie Shores Wind Farm may be affected by abnormal weather
conditions or changing wind patterns. Revenues in respect of the Waterpower
Facilities may be significantly affected by hydrological events that impact the
hycirological conditions of the Waterpower Facilities such as low and high water
flows within the watercourses on which the facilities are located. In the event
of severe flooding, the Waterpower Facilities may be damaged. The Biomass
Facilities may be affected by the availability, or lack of availability, of a
stable supply of wood waste from forest product operations. The Landfill Gas
Facilities may be affected by the composition of waste at a landfill site,
including waste added over time, and the size, depth, age, moisture content,
exposure to air, temperature and compaction of that waste and whether a landfill
is "open" or "closed". The potential impacts of any climate change are unknown.
See "Industry Overview" and "The Facilities".

LEGAL PROCEEDINGS

      The Fund is from time to time the subject of claims, lawsuits and other
proceedings in the ordinary course of its business, and the entities in which
the Fund has investments may also be the subject of such claims, lawsuits and
other proceedings. The results of these proceedings cannot be predicted with
certainty. There can be no assurance that these matters will not have a material
adverse effect on the Fund's results of operations or the market price of its
securities in any future period, and a substantial judgment could have a
material adverse impact on the Fund's business, financial condition, liquidity,
results of operations and market price of its securities.

CONSTRUCTION RISK

      The Fund will be exposed to a variety of risks as a result of its
involvement or contemplated involvement in the development of certain energy
projects including the Erie Shores Wind Farm and expansions at GRS, These

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risks will vary depending on the particular project and the Fund's involvement,
but may include construction risk, financing and credit risk, environmental
liability, regulatory risk, and permitting risk.

DEPENDENCE UPON KEY CUSTOMERS

      The customers that purchase most of the power generated by the Facilities
are typically large utilities that purchase power under long-term PPAs. Although
the Fund has attempted to ensure that such customers have acceptable credit
ratings, if for any reason such customers were unable or unwilling to fulfil
their contractual obligations under the relevant PPAs, Distributable Cash could
decline.

LOAN DEFAULT

      The Fund currently has third party debt service obligations under the Sun
Life Facility and under the Credit Facilities that increases the level of
financial risk to the Fund. The Sun Life Facility and the Credit Facilities
impose covenants and obligations on the Fund. There is a risk that such credit
facilities may go into default if there is a breach in complying with such
covenants and obligations which could result in the Fund being unable to pay
distributions to holders of Trust Units, the lenders realizing on their security
and the Fund losing some or all of its assets, including its investments in the
Facilities.

      In addition, the Senior Loan ranks ahead of the U.S. Windpower Loan. The
terms of the Senior Loan and related security impose many covenants and
obligations on the part of CWWH and the owners of the U.S. Windpower Facilities.
There is a risk that such loan financing and security arrangements may go into
default if there is a breach in complying with such covenants and obligations
which may result in the lenders realizing on their security and causing the Fund
to lose all or a part of its investment in the U.S. Windpower Loan. In addition,
if there occurs a default under the U.S. Windpower Loan, there are restrictions
on the remedies available to the Fund under such loan. See "The Existing
Investments - Investments in the U.S. Windpower Facilities".

      Upon termination of the Chapais Refinancing Arrangement, the Fund acquired
term debt and subordinated debt of CHESEC, owner of the Chapais Facility. Such
indebtedness imposes many covenants and obligations on the part of CHESEC, and
there is a risk that such indebtedness may go into default if there is a breach
in complying with such covenants and obligations. Such a default may adversely
affect the Fund's Distributable Cash. The ability of CHESEC to make required
payments is dependent in large part on the operations and performance of the
Chapais Facility. See "The Existing Investments - Investment in the Chapais
Facility".

      The Fund advanced approximately US$100 million as at December 31, 2005 and
following a December 2005 amendment may advance up to a total of US$109 million
to PEET Canada and PEET U.S. under the GRS Loans. The terms of the definitive
loan agreements for the GRS Loans impose many covenants and obligations on the
part of the borrowers with principal repayments being made in amounts expected
to require a period longer than the term of the GRS Loans for full repayment.
Accordingly, at the end of the term of each GRS Loan the remaining outstanding
principal amount of such GRS Loan will be required to be repaid or refinanced.
There is a risk that the Fund will have to note PEET Canada or PEET U.S. in
default if there is a breach in complying with such covenants and obligations or
if PEET U.S. or PEET Canada are unable to make required payments. Such a default
may adversely affect the Fund's Distributable Cash. The ability of PEET Canada
and PEET U.S. to make required payments to the Fund is dependent in large part
on the operations and performance of GRS and the Landfill Gas Facilities. See
"The GRS Loans" and "The Facilities - Landfill Gas Facilities".

EXCHANGE RATES

      A substantial portion of the Fund's investments generates revenues in U.S.
dollars. Changes in the value of the Canadian dollar relative to the U.S. dollar
can and will impact the performance of the Fund in two ways-translational
losses or gains, and transactional losses or gains.

      From period to period, the Fund must adjust the reported value of its
foreign assets into Canadian dollars. This can result in translational foreign
exchange losses or gains. These losses or gains are recorded on the income
statement to reflect the corresponding adjustment to the book value of the
assets from one reporting period to the next. While translational foreign
exchange adjustments can have a significant impact on the Fund's reported net
income, they have no impact on the actual cash flow generated by the Fund's
operations. Because they do not affect cash flow, the Fund's translational
foreign exchange risks have not been hedged.

      A transactional exchange loss or gain occurs when U.S. dollar income from
the Fund's U.S. investments or U.S. dollar equipment purchases are converted
into Canadian dollars. This creates a transactional foreign exchange adjustment
that can impact cash flow. A portion of this transactional risk is hedged to
reduce the impact of a

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significant change in the Canadian dollar equivalent of income generated or
equipment purchases in U.S. dollars. See the discussion of hedging under the
heading "Financial Instruments" in the Fund's Management Discussion and Analysis
for the year ended December 31, 2005 which is hereby incorporated by reference.
However, hedging will only shield the Fund's income against changes in the
relative value of the Canadian and U.S. dollar for the duration of the hedging
contract. If there is a long-term shift in the exchange rate, this will
eventually have a direct and permanent impact on the cash flow generated by the
Fund's U.S. dollar denominated investments.

REGULATORY REGIME AND PERMITS

      The profitability of the Facilities 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
industry and environmentally preferred energy sources. In addition, PPAs in
certain jurisdictions are subject to approval by local, state, provincial or
national utilities commissions or other regulatory authorities. Should the
regulatory regime in an applicable jurisdiction be modified in a manner which
adversely affects the Facilities, including increases in taxes and permit fees,
Distributable Cash may be adversely affected. The failure to obtain all
necessary approvals, licences or permits, including renewals thereof or
modifications thereto, may adversely affect Distributable Cash and the value of
the facilities.

      The Facilities encompass operations that are subject to environmental and
safety standards and regulations imposed by regulatory bodies. Although the
Administrator/Manager believes that the operations of the Facilities are in
compliance in all material respects with such standards and regulations, failure
to operate the Facilities in strict compliance with applicable regulations and
standards may expose owners or operators of the Facilities to claims and
clean-up costs and possible enforcement actions. Any new law or regulation could
require significant additional expenditures to achieve or maintain compliance.

      The operation of the Waterpower Facilities is highly regulated. Water
rights are generally owned by governments that reserve the rights to control
water levels. The Biomass Facilities are subject to government regulations,
including environmental regulations / approvals relating to the operations,
biomass supply, and wood ash disposal. Landfill Gas Facilities are also subject
to government regulations, including environmental laws relating to emission
levels, by-product disposal and landfill gas condensate disposal. Any new law or
regulation could require significant additional expenditures to achieve or
maintain compliance.

      The operation of the Erie Shores Wind Farm is highly regulated. Government
regulations and incentives such as the WPPI currently is expected to have a
favourable impact on windpower facilities in Canada. The Fund expects to receive
the WPPI upon completion of the construction of the Erie Shores Wind Farm.
Should the current governmental incentives be modified, the Erie Shores Wind
Farm may be adversely affected, which may have a material adverse effect on
Distributable Cash.

      The operation of the U.S. Windpower Facilities and Landfill Gas Facilities
is highly regulated. Government regulations and incentives such as production
tax credits in the United States and Emission Production Credits in some states
of the United States currently have a favourable impact on windpower and
landfill gas facilities. The owners of the U.S. Windpower Facilities currently
receive production tax credits in the United States. Should the current
governmental regulations or incentive programs be modified, the U.S. Windpower
Facilities and the Landfill Gas Facilities may be adversely affected, which may
have a material adverse effect on Distributable Cash. In particular, if such
production tax credits were to become unavailable to the owners of the U.S.
Windpower Facilities as a result of a change in applicable legislation, the
ability of the owners of the U.S. Windpower Facilities and/or the borrowers
under the U.S. Windpower Loan to pay interest and principal on the U.S.
Windpower Loan may be adversely affected, which could adversely affect
Distributable Cash.

      In the United States, FERC issues licences for the construction, operation
and maintenance of power generation facilities, including windpower and landfill
gas facilities. Such facilities are required to be licensed or have valid
exemptions from FERC. Failure to maintain such licences or exemptions could
result in a breach of regulatory requirements that may preclude the owner from
operating the licensed facility and could adversely affect Distributable Cash.

      Some of the U.S. Windpower Facilities and most of the Landfill Gas
Facilities obtain certain benefits and exemptions because of their Qualifying
Facility status ("QF Status") under PURPA and in the case of the Landfill Gas
Facilities located in Illinois, because each is a Qualified Solid Waste Energy
Facility ("QSW Status") under the Illinois Public Utilities Act. If any facility
were to lose its QF Status or QSW Status, the facility would no longer be
entitled to the exemptions and benefits thereof. Loss of QF Status or QSW Status
may also require the facility to cease selling electricity at the rates set
forth in the existing PPAs to the extent they exceed current

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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.

LABOUR RELATIONS

      White labour relations at the Facilities 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 labour environment
cannot be assured. In the event of a labour disruption such as a strike or lock
out, the ability of the Facilities to generate income, and consequently the
ability of the Fund to generate Distributable Cash, may be impaired. Employees
of the Administrator/Manager, Regional Power, Probyn & Company, Albertaco and
GRS are currently non-unionized. In September 2002, the 36 hourly employees of
the Chapais Facility elected to become members of la Confederation des syndicats
nationaux, a labour union within the province of Quebec.

RELIANCE ON THE ADMINISTRATOR/MANAGER AND THE OPERATORS AND POTENTIAL CONFLICTS
OF INTEREST

      Unitholders are dependent upon the Administrator/Manager for the
administration of the Fund and management of CPOT and upon the various operators
of the Facilities for the management and operation of the Facilities. See also
above under the heading "The Administrator and Manager-Conflict of Interest".

      There may be situations in which conflicts of interest may arise between
the Administrator/Manager, the Facility operators and their respective officers
and directors in relation to the interests of the Fund. The
Administrator/Manager and its affiliated entities may engage in activities
similar to the activities of the Fund. The Administrator/Manager or affiliated
entities currently own, manage, and administer other facilities, and may in the
future acquire, own, manage and administer other facilities in the independent
power generation industry and, in particular, in the biomass segment of the
industry. Provisions in the CPOT Trust Indenture (which are similar to business
corporations act legislation) provide certain procedures to be followed in the
event of such conflicts of interests, and certain remedies may be available to
the Fund where such procedures are not followed.

DELAYS IN DISTRIBUTIONS

      Payments by CPOT to the Fund may be delayed by restrictions imposed by
lenders, disruptions in service, recovery by the Administrator/Manager of its
expenses or the establishment of reserves for expenses. Any such delay could
have an adverse effect on Distributable Cash.

NATURE OF TRUST UNITS

      Each Trust Unit represents an equal undivided beneficial interest in the
Fund. The Fund's sole assets are CPOT Notes and CPOT Units and other permitted
investments. The Trust Units do not represent debt instruments and there is no
principal amount owing to Unitholders under the Trust Units. The Trust Units do
not represent shares in the Administrator/Manager, CEEC, Probyn & Company,
Regional Power, GRS, their affiliates or any other company.

RESTRICTIONS ON REDEMPTIONS

      It is anticipated that the redemption right will not be the primary
mechanism for holders of Trust Units to liquidate their investments. CPOT Notes
and other assets which may be distributed in specie to holders of Trust Units in
connection with a redemption will not be listed on any stock exchange and no
established market is expected to develop for such securities, and such
securities may be subject to an indefinite "hold period" or other resale
restrictions under applicable securities laws. CPOT Notes and other assets so
distributed may not be qualified investments for Plans, depending upon the
circumstances at the time. Regulatory approvals will be required in connection
with the distribution of CPOT Notes and other assets in specie to holders of
Units in connection with a redemption.

      The entitlement of Unitholders to receive cash upon the redemption of
their Trust Units is subject to certain limitations. See "Description of the
Fund - Redemption at the Option of Unitholders".

EQUIPMENT FAILURE

      With respect to each of the Facilities, 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.

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COMMODITY PRICES

      Although most electricity generated by the Facilities is sold pursuant to
long term PPAs, certain excess power capacity of certain of the Facilities may
be sold in the open market. As a result, Distributable Cash will, in part,
depend upon prices paid for energy sold in the open market. Such commodity
pricing wiil vary over time. Over the long term, fluctuations in market prices
may impact Distributable Cash.

RESERVE ACCOUNT

      The Reserve Account is available to be used to support cash distributions,
in the discretion of the CPOT Trustees, and to fund working capital. There can
be no assurance that amounts in the Reserve Account and the return on investment
of such amounts will be sufficient to fund intended distributions and working
capital. The Fund may invest a portion of the funds in the Reserve Account in
securities of income funds with a rating equivalent to or better than that of
the Fund. Such investments and all other permitted investments by the Fund will
be subject to all risks applicable to such securities. The Fund may lose all or
part of its investments due to factors that are beyond the control of the Fund.
Although the Administrator/Manager will seek professional investment advice in
situations where it deems it necessary or prudent or in situations where it is
otherwise required by law to do so, it is expected that the Fund's investments
will not provide a rate of return equal to the rate paid out by the Fund to
Unitholders.

WEATHER

      Some of the Fund's operations can be affected by adverse variances in
weather patterns from seasonal or regional norms. For example, in the summer of
2005, below average precipitation at the Wawatay facility - less than 40% of
average precipitation for July and less than 60% of average precipitation for
August - reduced expected water flow levels, thus reducing power generation and,
ultimately, cash flow from the Fund's Wawatay facility. To mitigate exposure to
this type of risk, the Fund's assets are not only distributed across North
America in different climate zones, but also diversified among four distinct
technologies that vary significantly in their dependence on weather.

GENERAL ECONOMIC CONDITIONS

      Changes in general economic conditions can impact the Fund's value and
performance in various ways, including changes in operating costs, credit risks
and the results of financing efforts, the timing and extent of capital
expenditures, and prices received for non-contracted revenue.

                               DISTRIBUTABLE CASH

      Distributable Cash is not a measure recognized under Canadian generally
accepted accounting principles ("GAAP") and does not have a standardized meaning
prescribed by GAAP. Distributable Cash is discussed in this Annual Information
Form because pursuant to the Fund Indenture the Fund is required to distribute
all of its Distributable Cash. Distributable Cash is defined as all amounts
received by the Fund including amounts paid on the CPOT Units and CPOT Notes
held by the Fund and the income, interest, dividends, return of capital or other
amounts, if any, from other permitted investments held by the Fund, less amounts
that may be paid by the Fund in connection with any cash redemptions or
repurchases of Trust Units and amounts which the Administrator/Manager or the
CPOT Trustees may reasonably consider necessary to provide for payment of any
costs or expenses required for the operation of the Fund and for reasonable
reserves. Distributable Cash is not intended to be a representation of earnings
or cash flows or of the Fund's financial performance on a consolidated basis.
The Fund's method of calculating Distributable Cash differs from similarly
titled amounts of other issuers and, accordingly, Distributable Cash is not
comparable to measures used by other issuers.

           INTEREST OF MANAGEMENT AND OTHERS IN MATERIAL TRANSACTIONS

      Other than as disclosed in the consolidated financial statements for the
fiscal period ended December 31, 2005 and elsewhere in this Annual Information
Form, the Fund is not aware of any material interest of any current or proposed
CPOT Trustee or officer of the Administrator in any transaction since the
creation of the Fund, or in any proposed transaction that has materially
affected or will materially affect the Fund.

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                     AUDITORS, REGISTRAR AND TRANSFER AGENT

      The auditors of the Fund are Ernst & Young LLP, Chartered Accountants,
Toronto, Ontario.

      The registrar and transfer agent for the Trust Units is Computershare
Trust Company of Canada, at its principal offices in Toronto.

                               INTEREST OF EXPERTS

      Ernst & Young LLP. chartered accountants, have audited the consolidated
balance sheets of the Fund as at December 31, 2005, 2004, and 2003 and the
consolidated statements of income (loss) and retained earnings (deficit) and
cash flows for the years then ended.

      Ernst & Young LLP is independent with respect to the Fund within the
meaning of the Rules of Profession Conduct of the Institute of Chartered
Accountants of Ontario.

                             ADDITIONAL INFORMATION

      Additional information relating to the Fund may be found on SEDAR at
www.sedar.com.

      Additional information, including executive compensation, trustees'
remuneration and indebtedness, principal holders of Units is contained in the
Fund's information circular for the annual meeting of Unitholders to be held on
June 27, 2006. Additional financial information is provided in the Fund's
consolidated financial statements and MD&A for the period 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 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 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 consolidated financial
                    statements of the Fund for its most recently completed
                    financial period 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 period;

            (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

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.

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                                    GLOSSARY

      In this Annual information Form, unless the context otherwise requires:

"ACQUISITIONS" means indirect acquisitions by the Fund of the Whitecourt
Facility and She Waterpower Facilities;

"ADMINISTRATION AGREEMENT" means the agreement between the Administrator/Manager
and the Fund dated October 31, 2001. as amended on May 20, 2004. pursuant to
which the Administrator/Manager has agreed to provide administrative services to
the Fund, as the same may be amended, supplemented or restated from time to
time;

"AFFILIATE" means an affiliate within the meaning of the Securities Act
(Ontario);

"ALBERTACO" means Clean Power Income Fund (Alberta) Inc., a wholly-owned
subsidiary of CPOT;

"AVOIDED COST" means a cost a utility does not incur to add new generating
capacity to the system by purchasing electricity from an independent or parallel
generator;

"BC HYDRO" means British Columbia Hydro and Power Authority;

"BIG SPRING" means the 34.32 MW windpower facility located near the town of Big
Spring, Texas, and owned by Texas Big Spring, L.P., a wholly-owned subsidiary of
CWWH.

"BIOMASS FACILITIES" means the Chapais Facility and the Whitecourt Facility;

"BUSINESS DAY" means any day that is not a Saturday, Sunday or civic or
statutory holiday in Ontario:

"CEEC" means Canadian Environmental Energy Corporation, a corporation
principally owned, directly or indirectly, by Probyn Eastman Ltd. and Sun Life
Assurance Company of Canada;

"CHANDLER" means the 1.98 MW windpower facility located near Buffalo Ridge,
Minnesota, and owned by Chandler Wind Partners, LLC, a wholly-owned subsidiary
of CWWH.

"CHAPAIS FACILITY" means the 31.0 MW wood waste fired electricity-generating
station located northwest of Quebec City, Quebec;

"CHEL" means Chapais Electrique Limitee;

"CHESEC" means Chapais Energie, Societe en Commandite:

"CLEAN POWER" means power generated from water, biomass, solar, wind and
geothermal facilities and other facilities that use environmentally preferred
energy sources in the production of power;

"CLOSING" means November 14, 2001, the closing of the offering of Trust Units
under the prospectus dated November 2, 2001 pursuant to which the Fund issued
Trust Units;

"COMPUTERSHARE" means Computershare Trust Company of Canada;

"CPLP" means Clean Power Limited Partnership, a limited partnership established
under the laws of Ontario;

"CPOT" means Clean Power Operating Trust, an unincorporated open-ended trust
established under the laws of Ontario;

"CPOT NOTES" means the secured notes issued by CPOT from time to time in
accordance with the Note Indenture;

"CPOT TRUST INDENTURE" means the trust indenture made as of October 31, 2001
between A. Stephen Probyn, R.W. Harmer and the settlor of CPOT pursuant to which
CPOT was established, as amended and restated by the amended and restated trust
indenture dated July 16, 2003 between A. Stephen Probyn, H. Allen Jackson, John
Fox, Donald S. Macdonald, Donald M. McCutchan and the Unitholders. as amended
restated by the amended and restated trust indenture dated May 9, 2005 between
A. Stephen Probyn, H. Allen Jackson, John Fox, Donald S. Macdonald, Donald M.
McCutchan and the Unitholders, as the same may be amended, supplemented or
restated from time to time;

"CPOT TRUSTEES" means the trustees of CPOT as appointed by the
Administrator/Manager or elected by the holder of CPOT Units pursuant to the
direction of the Unitholders, as applicable, from time to time;

"CPOT UNITS" means the units of CPOT, each of which represents an equal
undivided beneficial interest in the distributions and the net assets of CPOT,
and includes a fraction of a unit of CPOT;

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"CREDIT FACILITIES" means (i) a $80 million credit facility: and (ii) a $17,75
million working capital line with a syndicate of Canadian banks;

"CWWH" means Caithness Western Wind Holdings, LLC. a wholly-owned subsidiary of
Caithness Energy, LLC;

"DISTRIBUTABLE CASH" means all amounts received by the Fund including amounts
paid on the CPOT Units and CPOT Notes held by the Fund and the income, interest,
dividends, return of capital or other amounts, if any, from other permitted
investments held by the Fund, less amounts that may be paid by the Fund in
connection with any cash redemptions or repurchases of Trust Units and amounts
which the Administrator/Manager or the CPOT Trustees may reasonably consider
necessary to provide for payment of any costs or expenses required for the
operation of the Fund and for reasonable reserves;

"DRYDEN FACILITY" means collectively the 1.25 MW Eagle River generating station,
the 0.95 MW McKenzie Falls generating station and the 1.05 MW Wainwright
generating station, each of which is located near Dryden, Ontario;

"ECOLOGO PROGRAM" has the meaning ascribed thereto under "Industry Overview -
The Environmental Choice(M) Program";

"ENXCO" means enXco, Inc.;

"ERIC SHORES WIND FARM" means the 99 MW windpower facility currently under
construction, located near Port Burwell, Ontario, on the north shore of Lake
Erie;

"FACILITIES" means the Landfill Gas Facilities, the Waterpower Facilities, the
Biomass Facilities, the Erie Shores Wind Farm and the U.S. Windpower Facilities;

"FERC" means the United States Federal Energy Regulatory Commission, an
independent regulatory agency within the United States Department of Energy
that, among other things, oversees regulatory matters relating to electricity
projects;

"FOOTE CREEK II" means the 1.8 MW windpower facility located on Foote Creek Rim
in Carbon County. Wyoming and owned by Foote Creek II, LLC. a wholly-owned
subsidiary of CWWH;

"FOOTE CREEK III" means the 24.75 MW windpower facility located on Foote Creek
Rim in Carbon County, Wyoming, and owned by Foote Creek III, LLC, a wholly-owned
subsidiary of CWWH;

"FOOTE CREEK IV" means the 16.8 MW windpower facility located on Foote Creek Rim
in Carbon County, Wyoming, and owned by Foote Creek IV, LLC, a wholly-owned
subsidiary of CWWH;

"FUND" means Clean Power Income Fund, an unincorporated open-ended trust
established under the laws of Ontario and, unless the context otherwise
requires, includes CPOT and other entities owned directly or indirectly by CPOT:

"FUND TRUST INDENTURE" means the trust indenture made as of October 31, 2001
between Computershare and the settlor of the Fund pursuant to which the Fund was
established, as amended and restated by the amended and restated trust indenture
dated July 16, 2003 between Computershare and the Unitholders, as the same may
be amended, supplemented or restated from time to time;

"GIGAWATT HOUR" or "GWH" means one million kWh of electrical power;

"GRS" means Gas Recovery Systems, LLC and unless the context otherwise requires,
includes its predecessors and subsidiaries:

"GRS LOANS" means the loans by the Fund to PEET Canada and PEET U.S. in
connection with the purchase by PEET U.S. of all of the outstanding shares of
GRS, as described under "The Investments - The GRS Loans".

"GRSM" means GRS Management Services, LLC, the independent contract
Administrator/Manager of GRS landfill gas facilities until December 31,2004:

"HLUEY LAKES FACILITY" means the 3.0 MW waterpower generating station located in
the Dease Lake area in northern British Columbia;

"HYDROELECTRIC FACILITIES" (see "WATERPOWER FACILITIES")

"KILOWATT HOUR" or "KWH" means an hour during which one kilowatt of electrical
power has been continuously produced;

"KILOWATTS" or "KW" means 1,000 watts of electrical power;

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"LANDFILL Gas FACILITIES" means 26 completed landfill gas electricity generating
stations, and three completed gas distribution stations, each of which is wholly
or partly owned by GRS, as described under "The Facilities - Landfill Gas
Facilities".

"MANAGEMENT AGREEMENT" means the agreement between the Administrator/Manager and
CPOT dated October 31, 2001, as amended on May 20, 2004, pursuant to which the
Administrator/Manager has agreed to provide management services to CPOT, as the
same may be amended, supplemented or restated from time to time;

"ADMINISTRATOR/MANAGER" means Clean Power Inc., a corporation wholly owned by
CEEC;

"MEGAWATT HOUR" or "MWH" means one thousand kWh of electrical power;

"MEGAWATTS" or "MW" means 1,000 kilowatts of electrical power;

"NOTE INDENTURE" means the amended and restated secured note indenture dated as
of December 7, 2001, between CPOT and Computershare, as trustee thereunder,
pursuant to which CPOT has issued and may issue the CPOT Notes, as the same may
be amended, supplemented or restated from time to time;

"OEFC" means Ontario Electricity Financial Corporation;

"PEET" means the Probyn Eastman Environmental Trust, a charitable trust
originally settled by A. Stephen Probyn and Dr. Barbara Eastman (collectively,
the "Settlors"), whose trustees are Dr. Barbara Eastman, Ellen Desmarais and
John C. Beichman and will in the future be required to continue to include at
least a majority of trustees who are individuals not related to either Settlor,
and whose beneficiaries are: (a) The University of Toronto; (b) The University
of Trinity College; (c) any one or more other corporation that is a charity or
non-profit organization as described in the Tax Act or any charity or non-profit
organization that may qualify as such in any other jurisdiction whose purposes
or activities include, in whole or part, the promotion of a clean environment
including, without limiting the generality of the foregoing, by supporting or
conducting research on the environment, and the respective successors of any
such organization which is also a charity or a non-profit organization under the
foregoing provisions of the Tax Act or applicable law of such other
jurisdiction, whose objects include those described above; and (d) any person
who in the opinion of the trustees of PEET has made a significant contribution
to the promotion of a clean environment including, without limiting the
generality of the foregoing, by supporting or conducting research on the
environment, as may be designated in writing by the trustees of PEET from time
to time or upon the termination of the Trust, other than the Settlors or persons
related to either Settlor, and, unless the context otherwise requires, includes
PEET Canada and PEET U.S.;

"PEET CANADA" means PEET Canadian Holdings Inc.;

"PEET CANADA LOAN" means the loan by CPOT to PEET Canada, as described under
"The Investments - The GRS Loans";

"PEET U.S." means PEET U.S. Holdings, Inc.;

"PEET U.S. LOAN" means the loan by Albertaco to PEET U.S., as described under
"The Investments - The GRS Loans";

"PEETZ TABLE" means the 29.7 MW windpower facility located near Peetz Table,
Logan County, Colorado, and owned by Ridge Crest Wind Partners, LLC, a
wholly-owned subsidiary of CWWH;

"PPA" means power purchase agreement;

"PROBYN & COMPANY" means Probyn & Company Inc., a member of the Probyn Group, or
a wholly-owned subsidiary thereof:

"PROBYN GROUP" means Probyn Eastman Ltd. and its subsidiaries;

"PURPA" means the Public Utility Regulatory Policies Act:

"RECORD DATE" means the last business day of each month:

"REFINANCING ARRANGEMENT" has the meaning ascribed thereto under "Description
of the Business - The Facilities -The Biomass Facilities";

"REGIONAL POWER" means Regional Power Inc., a subsidiary of Manulife Financial
Corporation and, unless the context otherwise requires, includes its predecessor
corporations and certain of the predecessors in title to the Waterpower
Facilities;

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"RESERVE ACCOUNT" means certain funds of the Fund available to the Fund for
distribution to the Unitholders, in the discretion of the CPOT Trustees, to
support distributions to Unitholders in the event that Distributable Cash for
any period is less than the desired level of such distributions and for the
purpose of funding working capital:

"RUN-OF-THE-RIVER" means a mode of operation of a waterpower generating facility
where there is a continuous discharge of water from the facility with no long
term storage and release of water;

"SEAWEST" means AES SeaWest, Inc.;

"SECHELT FACILITY" means the 16.0 MW waterpower generating station located near
Sechelt, British Columbia, approximately 70 kilometres northwest of Vancouver;

"SENIOR LOAN" means the senior secured loan that provides debt financing for
the acquisition, ownership and operation of the U.S. Windpower Facilities
pursuant to a senior financing agreement between, among others, CWWH, as
borrower, and Sun Life Assurance Company of Canada as agent to certain financial
institutions:

"SPECIAL TRUST UNITS" means the units of the Fund issued to represent voting
rights in the Fund and which accompany certain securities convertible into or
exchangeable for Trust Units;

"SUN LIFE FACILITY" means, collectively, the $12 million secured term loan, the
$13 million secured term loan and the $10 million subordinated secured bridge
loan of CPOT outstanding with Sun Life Assurance Company of Canada;

"TRUST UNITS" means the units of the Fund other than Special Trust Units, each
of which represents an equal undivided beneficial interest in the distributions
and the net assets of the Fund, and includes a fraction of such a unit of the
Fund;

"TRUSTEE" means the trustee of the Fund, which is currently Computershare;

"UNITHOLDERS" means the holders of Trust Units from time to time;

"WATERPOWER FACILITIES" means the Sechelt Facility, the Wawatay Facility, the
Dryden Facility and the Hluey Lakes Facility:

"WATERPOWER O&M AGREEMENT" means the agreement between Regional Power and CPOT
dated November 14, 2001, pursuant to which Regional Power has agreed to provide
operations, maintenance and management services in respect of the Waterpower
Facilities;

"WAWATAY FACILITY" means the 13.5 MW waterpower generating station located on
the Black River near Marathon, Ontario;

"WAWATAY LOAN" has the meaning ascribed thereto under "The Investments -
Acquisition of the Waterpower Facilities";

"WHITECOURT FACILITY" means the 28 MW wood waste fired electricity generating
station located north of Whitecourt, Alberta;

"WHITECOURT POWER" means Whitecourt Power Corp., a corporation incorporated
under the laws of Alberta;

"U.S. WINDPOWER FACILITIES" mean Foote Creek II, Foote Creek III, Foote Creek
IV, Peetz Table, Big Spring and Chandler;

"U.S. WINDPOWER LOAN" means the loan by CPOT to CWWH pursuant to a loan
agreement dated October 8, 2003, as described under "The Investments--
Investments in the U.S. Windpower Facilities";

"WPLP" means Whitecourt Power Limited Partnership, a limited partnership
established under the laws of Alberta; and

"WPPI" means the Wind Power Production Incentive.

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                                   APPENDIX A

                                 AUDIT COMMITTEE
                               TERMS OF REFERENCE

I.    COMMITTEE PURPOSE

The Audit Committee (the "Committee") is a committee of the Board of Trustees
(the "Board") of Clean Power Operating Trust ("CPOT") whose primary function is
to manage and maintain the effectiveness of the financial aspects of the
governance structure of CPOT and ensuring its credibility and providing the same
functions for Clean Power Income Fund (the "Fund") on a voluntary basis.

II.   COMMITTEE COMPOSITION, APPOINTMENT AND PROCEDURES

1.    Composition of Committee

      The Committee shall be comprised of not less than three CPOT Trustees, all
      of whom must be Independent Trustees (as defined by CPOT's Amended and
      Restated Declaration of Trust dated May 9, 2005, the "Declaration of
      Trust") and in accordance with applicable regulatory and stock exchange
      requirements.

2.    Financial Literacy

      All members of the Committee shall have the ability to read and understand
      a set of financial statements that present a breadth and level of
      complexity of accounting issues that are generally comparable to the
      breadth and complexity of the issues that can reasonably be expected to be
      raised by the consolidated financial statements of the Fund.

3.    Appointment of Committee Members

      Members of the Committee shall be appointed from time to time and shall
      hold office at the pleasure of the Board.

4.    Vacancies

      Where a vacancy occurs at any time in the membership of the Committee, it
      may be filled by the Board. The Board shall fill any vacancy if the
      membership of the Committee is less than three Trustees.

5.    Committee Chairman

      The Board shall appoint a Chairman for the Committee.

6.    Absence of Committee Chairman

      If the Chairman of the Committee is not present at any meeting of the
      Committee, one of the other members of the Committee who is present at the
      meeting shall be chosen by the Committee to preside at the meeting.

7.    Secretary of Committee

      The Committee shail appoint a Secretary who need not be a CPOT Trustee.

8.    Meetings

      The Chairman of the Committee or the Chairman of the Board, or any member
      of the Committee may call a meeting of the Committee. The Committee shall
      meet at such times during each year as it deems appropriate.

9.    Quorum

      A majority of the members of the Committee shall constitute a quorum.

10.   Notice of Meetings

      Notice of the time and place of every meeting shall be given in writing
      (including by way of written facsimile communication) to each member of
      the Committee at least 48 hours prior to the time fixed for such meeting;
      provided, however, that a member may in any manner waive a notice of a
      meeting. Attendance of a member at a meeting constitutes a waiver of
      notice of the meeting except where a member

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      attends a meeting for the express purpose of objecting to the transaction
      of any business on the grounds that the meeting is not lawfully called.

11.   Procedure. Records and Reporting

      Subject to any statute or the Declaration of Trust, the Committee shall
      fix its own procedures at meetings, keep records of its proceedings and
      report to the Board when the Committee may deem appropriate (but not later
      than the next meeting of the Board). The minutes of its meetings shall be
      tabled at the next meeting of the Board.

12.   Special Powers of Auditors

      The Auditors of the Fund and CPOT are entitled to receive notice of every
      meeting of the Committee and to attend and be heard there at and, if so
      requested by a member of the Committee, shall attend any meeting of the
      Committee held during the term of office of the Auditors of the Fund and
      CPOT. The Auditors of the Fund and CPOT may call a meeting of the
      Committee on not less than 48 hours prior notice.

13.   Review of Terms of Reference

      The Committee shall review its performance and these Terms of Reference
      annually or otherwise as it deems appropriate and propose recommended
      changes to the Board.

III.  RESPONSIBILITIES OF THE COMMITTEE

14.   The Committee shall:

      (a)   Review with management and the Fund's external auditors the Fund's
            financial reporting in connection with the annual audit and the
            preparation of the financial statements, including, without
            limitation, the judgment of the external auditors as to the quality
            and appropriateness of the Fund's accounting principles as applied
            in its financial reporting;

      (b)   Review with the external auditors, before completion of the annual
            audit of the Fund, the financial statements and the report of the
            auditors thereon, in order to ensure that the auditors are satisfied
            with the disclosure made to them of the required information and
            with the content of the financial statements;

      (c)   Review and discuss with management and the external auditors all
            quarterly unaudited and annual audited consolidated financial
            statements and accompanying reports to the unitholders, MD&A,
            related annual and interim earnings press releases, earnings
            guidance disclosure or any other forward-looking information or any
            other disclosure based on the Fund's consolidated financial
            statements prior to the public release of those statements;

      (d)   Fulfill its responsibilities pursuant to the Fund's disclosure
            policies and procedures;

      (e)   Supervise the correction process to be undertaken with respect to
            any misrepresentations or omissions in the Fund's continuous
            disclosure filings;

      (f)   Make annual recommendations to the Board for approval with respect
            to the annual audited consolidated financial statements, and, in
            each case, review:

            (i)     the appropriateness of the Fund's significant accounting
                    principles and practices, including acceptable alternatives,
                    and the appropriateness of any significant changes in
                    accounting principles and practices;

            (ii)    the existence and substance of significant accruals,
                    estimates, or accounting judgements;

            (iii)   unusual or extraordinary items, transactions with related
                    parties, and adequacy of disclosures;

            (iv)    asset and liability carrying values;

            (v)     income tax status and related reserves;

            (vi)    qualifications contained in letters of representation;

            (vii)   assurances of compliance with covenants in trust deeds or
                    loan agreements;

            (viii)  business risks, uncertainties, commitments, and contingent
                    liabilities; and

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            (ix)    the adequacy of explanations for significant financial
                    variances between years.

      (g)   Be satisfied that adequate procedures are in place for the review of
            the Fund's public disclosure of financial information extracted or
            derived from the Fund's financial statements, other than the public
            disclosure referred to in paragraph (c) above, and must periodically
            assess the adequacy of those procedures;

      (h)   Review the Fund's Annual Information Form and make a recommendation
            for approval thereof to the board of directors of Clean Power Inc.,
            as administrator of the Fund:

      (i)   Oversee the external audit process, including:

            (i)     the selection and appointment of an external auditing firm
                    to conduct the annual audit of the Fund's annual
                    consolidated financial statements and review of the Fund's
                    quarterly consolidated financial statements (and related
                    notes and management's discussion and analysis in each case)
                    on the basis that the auditing firm is ultimately
                    accountable to the Board and the Committee as
                    representatives of the unitholders of the Fund;

            (ii)    assessing the independence of appointed auditing firm;

            (iii)   reviewing of the external audit plan comprising a fee
                    estimate, objectives, scope, materiality, timing, locations
                    to be visited, areas of audit risk, and co-ordination with
                    the internal audit:

            (iv)    reviewing of audit reports and reviews and findings,
                    including corresponding management responses;

            (v)     approving the audit fee;

            (vi)    approving any non-audit services provided by the auditing
                    firm to the Fund or its subsidiary entities, the fees
                    charged by the firm for such services and the impact on the
                    independence of the auditor provided that the auditing firm
                    is prohibited from providing appraisal or valuation
                    services, fairness opinions, actuarial services, internal
                    audit outsourcing services, management functions or human
                    resources, bookkeeping or other services relating to the
                    accounting records or financial statements of the Fund or
                    financial information systems designed in implementation.
                    The Committee shall be entitled to establish, from time to
                    time, pre-approval arrangements for specific categories of
                    permitted audit related services;

            (vii)   private discussions regarding the quality of the Fund's
                    significant accounting principles and practices, the
                    financial personnel, the level of co-operation received,
                    unresolved material differences of opinion or disputes, and
                    the effectiveness of the work of the internal audit; and

            (viii)  resolve disagreements between management and the external
                    auditor regarding financial reporting.

      (j)   Oversee the internal audit function including:

            (i)     reviewing the annual audit plan including risk assessment,
                    the location and activities selected to ensure appropriate
                    involvement in the control systems and financial reporting,
                    time and cost budgets, resources (both personnel and
                    technological), and organizational reporting structure;

            (ii)    reviewing audit progress, findings, recommendations,
                    responses, and follow up actions;

            (iii)   review management's plans regarding any changes in
                    accounting practices or policies and the financial impact
                    thereof;

            (iv)    private discussions as to internal audit independence,
                    co-operation received from management, interaction with
                    external audit, and any unresolved material disagreements
                    with management;

            (v)     annual approval of internal audit mandate; and

            (vi)    monitoring of compliance with the Fund's code of financial
                    conduct.

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      (k)   Review the effectiveness of control and control systems utilized by
            the Fund in connection with financial reporting and other identified
            business risks;

      (l)   Review incidents of fraud, illegal acts and conflicts of interest;

      (m)   Review documents filed with securities commissions, including the
            Fund's Annual Information Form and Annual Report:

      (n)   Review the types of financial information and earnings guidance
            provided to analysts and rating agencies. It is not expected that
            the Committee will pre-approve all such guidance;

      (o)   Review material valuation issues;

      (p)   Review the quality and accuracy of computerized accounting systems,
            the adequacy of the protection against damage and disruption, and
            security of confidential information through information systems
            reporting;

      (q)   Review current and outstanding litigation;

      (r)   Review the expenses and perquisites, including the use of company
            assets, by senior officers;

      (s)   Review cases where management has sought accounting advice on a
            specific issue from an accounting firm other than the one appointed
            as the Auditor:

      (t)   Establish procedures for:

            (i)     the receipt, retention and treatment of complaints received
                    by the Fund regarding accounting, internal accounting
                    controls, or auditing matters;

            (ii)    the confidential, anonymous submission by employees of the
                    Fund of concerns regarding questionable accounting or
                    auditing matters: and

      (u)   Review and approve hiring policies regarding partners, employees and
            former partners and employees of the present and former external
            auditor of the Fund.

15.   The Committee shall make regular reports to the Board on its activities,
      including reviewing any issues that arise respecting the quality and
      integrity of the Fund's public reporting, the Fund's compliance with legal
      and regulatory requirement, the performance and independence of the Fund's
      independent auditors, the performance of the Fund's internal process and
      the effectiveness of the Fund's disclosure controls and procedures.

16.   The Committee may, at the request of the Board, investigate such other
      matters as the Board considers appropriate in the circumstances.

IV.   RESOURCES, MEETINGS AND REPORTS

17.   The Committee shall have adequate resources to discharge its
      responsibilities. The Committee may, for and on behalf of the Fund and at
      the Fund's sole expense, engage such consultants as it considers in its
      sole discretion necessary to assist it in fulfilling its duties and
      responsibilities, including external legal, accounting and other advisors,
      and the Fund shall provide appropriate funding for the Committee to retain
      any such advisors without requiring the Committee to seek Board approval.

18.   The Committee shall meet not less than four times per year.

19.   The Committee may request the attendance of other trustees, officers or
      employees of CPOT or Clean Power Inc., as administrator of the Fund, or
      other persons whose advice and counsel are sought by the Committee, attend
      any meeting to provide such information as the Committee requests from
      time to time.

20.   The Board shall be kept informed of the Committee's activities by a report
      presented at the Board meeting Following each Committee meeting.

21.   The Committee shall keep minutes of its meetings in which shall be
      recorded all actions taken by the Committee which minutes shall be made
      available to the Board and which such minutes shall be maintained with the
      books and records of CPOT and the Fund.

22.   The members of the Committee shall have the right, for the purposes of
      discharging the powers and responsibilities of the Committee, to inspect
      any relevant records of the Fund and its subsidiaries.

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23.   The Committee may delegate from time to time to any person or committee of
      persons any of the foregoing responsibility that lawfully may be
      delegated.

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Dates Referenced Herein and Documents Incorporated by Reference

		Referenced-On Page
This ‘F-8’ Filing	Date	First	Last	Other Filings

	9/27/25	17
	9/30/24	14
	1/25/24	21
	12/31/22	28
	3/31/22	14
	11/1/20	28
	1/31/20	30
	11/30/16	22
	10/31/11	52	53
	4/1/11	39		40-F
	4/1/10	39		40-F, F-X
	7/1/09	9
	6/30/07	9
	4/11/07	13
Filed on / Effective on:	3/26/07			F-X
	6/27/06	71
	5/1/06	40
	3/31/06	2	39
	3/29/06	9	66
	3/16/06	35
	1/1/06	55
	12/31/05	6	71
	12/22/05	17
	12/7/05	14
	11/16/05	55
	10/26/05	66
	8/23/05	49
	8/8/05	42
	6/29/05	13	43
	5/9/05	6	76
	3/10/05	14
	3/6/05	14
	12/31/04	48	71
	12/15/04	16	49
	12/9/04	40
	11/25/04	13
	11/15/04	15
	10/22/04	42
	10/12/04	43
	9/27/04	17
	7/30/04	16
	7/1/04	55
	6/30/04	55
	6/18/04	9
	5/20/04	72	74
	4/1/04	40
	12/31/03	32	71
	10/8/03	14	75
	7/16/03	72	73
	7/15/03	6
	7/11/03	52
	6/30/03	6
	6/1/03	39
	5/28/03	48
	1/1/03	38
	12/31/02	36	48
	12/9/02	40
	9/30/02	48
	7/31/02	41
	5/1/02	40
	2/22/02	16
	1/1/02	26	55
	12/31/01	55
	12/19/01	52
	12/7/01	74
	11/14/01	48	75
	11/2/01	72
	10/31/01	72	74
	4/17/01	24
	1/1/01	39
	5/29/00	31
	3/20/00	52
	1/15/00	29	30
	12/13/99	30
	4/1/99	40
	2/27/99	31
	5/23/97	30
	3/1/97	24
	10/10/95	24
	8/11/95	24
	8/1/95	31
	4/1/95	24
	12/31/94	32
	7/19/94	24
	11/1/93	30
	7/2/92	25
	6/23/92	27
	6/18/92	27
	5/1/92	27
	4/1/92	25
	3/30/92	33
	1/1/92	27
				List all Filings

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Filing Submission 0000950136-07-001878 – Alternative Formats (Word / Rich Text, HTML, Plain Text, et al.)

Algonquin Power & Utilities Corp. – ‘F-8’ on 3/26/07 – ‘EX-3.12’

On: Monday, 3/26/07, at 3:18pm ET · Effective: 3/26/07 · Accession #: 950136-7-1878 · File #: 333-141569

Registration Statement by a Foreign Private Issuer for Securities Offered Pursuant to a Transaction — Form F-8Filing Table of Contents

EX-3.12 — Annual Information Form 3/31/2006Exhibit Table of Contents

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Dates Referenced Herein and Documents Incorporated by Reference

Registration Statement by a Foreign Private Issuer for Securities Offered Pursuant to a Transaction — Form F-8
Filing Table of Contents

EX-3.12 — Annual Information Form 3/31/2006
Exhibit Table of Contents