Exhibit 99.64

RENEWAL
ANNUAL INFORMATION FORM

For the Year Ended December 31, 2004

Dated March 28, 2005

TABLE OF CONTENTS

Abbreviations and Conversion	5
Notes on Reserves Data	6
Special Note Regarding Forward Looking Statements	7
Definitions	8
Non-GAAP Measures	12
StarPoint Energy Trust	13
General	13
Structure	13
Development of the Business of the Trust	14
The Arrangement	14
Acquisition of Selkirk	15
Offering of Trust Units	15
Potential Acquisitions	15
Description of the Business of the Trust	15
Competition	16
Seasonal Factors	16
Environmental Regulation	16
Personnel	16
DRIP Plan	17
Industry Conditions	17
Pricing and Marketing - Oil, Natural Gas and Associated Products	17
The North American Free Trade Agreement	17
Provincial Royalties and Incentives	18
Land Tenure	18
Environmental Regulation	18
Trends	19
Oil and Natural Gas Reserves and Net Present Value of Future Net Revenue	20
Summary of Oil and Gas Reserves – Constant Prices and Costs	21
Net Present Value of Future Net Revenue – Constant Prices and Costs	22
Additional Information Concerning Future Net Revenue – Constant Prices and Costs	23
Future Net Revenue by Production Group – Constant Prices and Costs	23
Summary of Oil and Gas Reserves – Forecast Prices and Costs	25
Net Present Value of Future Net Revenue – Forecast Prices and Costs	26
Additional Information Concerning Future Net Revenue – Forecast Prices and Costs	28
Future Net Revenue by Production Group – Forecast Prices and Costs	29
Pricing Assumptions – Constant Prices and Costs	30
Pricing Assumptions – Forecast Prices and Costs	30
Undeveloped Reserves	31
Proved Undeveloped Reserves	31
Probable Undeveloped Reserves	31
Significant Factors or Uncertainties Affecting Reserves Data	31
Future Development Costs	32
Oil and Gas Properties	33
Fort St. John, British Columbia	33
Midale, Saskatchewan	33
Queensdale/Gainsborough, Saskatchewan	34
Heward/Melrose, Saskatchewan	34
Leo/Stettler, Alberta	34
Metiskow, Alberta	35
Sibbald/Acadia, Alberta	35
Selkirk Properties	35

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US Properties	36
Oil and Gas Wells	36
Properties with no Attributed Reserves	36
Drilling Activity	37
Additional Information Concerning Abandonment and Reclamation Costs	37
Tax Horizon	37
Costs Incurred	37
Production Estimates	38
Administrator Report	38
Selkirk Report	38
Production History	38
Average Daily Production Volume	38
Prices Received, Royalties Paid, Production Costs and Netback – Light and Medium Crude Oiland NGLs	38
Prices Received, Royalties Paid, Production Costs and Netback – Natural Gas	39
Production Volume by Field	39
Additional Information Concerning the Trust	39
Trust Units	39
Special Voting Units	40
Trust Unitholder Limited Liability	40
Issuance of Trust Units	41
Cash Distributions	41
Redemption Right	41
Non–Resident Trust Unitholders	42
Meetings of Trust Unitholders	43
Takeover Bids	43
The Trustee	43
Liability of the Trustee	44
Amendments to the Trust Indenture	44
Termination of the Trust	45
Exercise of Voting Rights Attached to Shares of the Administrator	45
The Administrator Share Capital	46
Common Shares	46
Exchangeable Shares	46
Voting and Exchange Trust Agreement	51
Voting Rights	51
Optional Exchange Right	52
Support Agreement	52
The Trust Support Obligation	52
Delivery of Trust Units	53
Administrator Notes	55
Terms and Issue of Notes	55
Events of Default	56
NPI Agreement	56
Directors and Officers of the Administrator	56
Audit Committee	58
Audit Committee Charter	58
Composition of the Audit Committee	58
Pre-Approval Policies	59
Auditors’ Fees	60

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Market for Securities	60
Risk Factors	60
Legal Proceedings	69
Interest of Management and Others in Material Transactions	69
Auditors, Transfer Agent and Registrar	69
Material Contracts	70
Interest of Experts	70
Additional Information	70
Schedule “A” – Reports on Reserves Data by Sproule Associates Limited
Schedule “B” – Report of Management and Directors on Reserves Data
Schedule “C” – Audit Committee Charter

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ABBREVIATIONS AND CONVERSION

In this Annual Information Form, the abbreviations set forth below have the following meanings:

Oil and Natural Gas Liquids

Bbl	barrel
Bbls	barrels
Mbbls	thousand barrels
Mmbbls	million barrels
Mstb	1,000 stock tank barrels
Bbls/d	barrels per day
BOPD	barrels of oil per day
NGLs	natural gas liquids
STB	standard tank barrels

Natural Gas

Mcf	thousand cubic feet
Mmcf	million cubic feet
Mcf/d	thousand cubic feet per day
Mmcf/d	million cubic feet per day
MMBTU	million British Thermal Units
Bcf	billion cubic feet
GJ	gigajoule

Other

AECO	EnCana Corp.’s natural gas storage facility located at Suffield, Alberta.
API	American Petroleum Institute
°API	an indication of the specific gravity of crude oil measured on the API gravity scale. Liquid petroleum with a specified gravity of 28° API or higher is generally referred to as light crude oil.
ARTC	Alberta Royalty Tax Credit
BOE	barrel of oil equivalent on the basis of 1 BOE to 6 Mcf of natural gas. BOEs may be misleading, particularly if used in isolation. A BOE conversion ratio of 1 BOE for 6 Mcf is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead.
BOE/d	barrel of oil equivalent per day
m3	cubic metres
MBOE	1,000 barrels of oil equivalent
McfGE	1,000 cubic feet of gas equivalent on the basis of 6 McfGEs to 1 bbl of crude oil. McfGEs may be misleading, particularly if used in isolation. A McfGE conversion ratio of 6 McfGEs to 1 bbl is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead.
McfGE/d	1,000 cubic feet equivalent per day
MMcfGE	1,000 McfGE
$000s	thousands of dollars
WTI	West Texas Intermediate, the reference price paid in U.S. dollars at Cushing, Oklahoma for crude oil of standard grade

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NOTES ON RESERVES DATA

The determination of oil and gas reserves involves the preparation of estimates that have an inherent degree of associated uncertainty.  Categories of proved, probable and possible reserves have been established to reflect the level of these uncertainties and to provide an indication of the probability of recovery.

The estimation and classification of reserves requires the application of professional judgment combined with geological and engineering knowledge to assess whether or not specific reserves classification criteria have been satisfied.  Knowledge of concepts including uncertainty and risk, probability and statistics, and deterministic and probabilistic estimation methods is required to properly use and apply reserves definitions.

“Reserves” are estimated remaining quantities of oil and natural gas and related substances anticipated to be recoverable from known accumulations, from a given date forward, based on (a) analysis of drilling, geological, geophysical, and engineering data;  (b) the use of established technology; and (c) specified economic conditions, which are generally accepted as being reasonable and shall be disclosed. Reserves are classified according to the degree of certainty associated with the estimates.

“Proved” reserves are those reserves that can be estimated with a high degree of certainty to be recoverable.  It is likely that the actual remaining quantities recovered will exceed the estimated proved reserves.

“Developed Producing” reserves are those reserves that are expected to be recovered from completion intervals open at the time of the estimate.  These reserves may be currently producing or, if shut-in, they must have previously been on production, and the date of resumption of production must be known with reasonable certainty.

“Developed Non-Producing” reserves are those reserves that either have not been on production, or have previously been on production, but are shut-in, and the date of resumption of production is unknown.

“Undeveloped” reserves are those reserves expected to be recovered from know accumulations where a significant expenditure (e.g., when compared to the cost of drilling a well) is required to render them capable of production.  They must fully meet the requirements of the reserves classification (proved, probable, possible) to which they are assigned.

In multi-well pools, it may be appropriate to allocate total pool reserves between the developed and undeveloped categories or to sub-divide the developed reserves for the pool between developed producing and developed non-producing.  This allocation should be based on the estimator’s assessment as to the reserves that will be recovered from specific wells, facilities and completion intervals in the pool and their respective development and production status.

“Probable” reserves are those additional reserves that are less certain to be recovered than proved reserves. It is equally likely that the actual remaining quantities recovered will be greater or less than the sum of the estimated proved + probable reserves.

“gross” means: (a) in relation to an issuer’s interest in productionor reserves, its “company gross reserves”, which are its working interest (operating or non-operating) share before deduction of royalties and without including any royalty interests of the issuer;  (b) in relation to wells, the total number of wells in which an issuer has an interest; and (c) in relation to properties, the total area of properties in which an issuer has an interest.

“net” means: (a) in relation to an issuer’s interest in productionor reserves its working interest (operating or non-operating) share after deduction of royalty obligations, plus the itsroyalty interests in productionor reserves; (b) in relation to an issuer’s interest in wells, the number of wells obtained by aggregating the issuer’s working interest in each of its grosswells; and (c) in relation to an issuer’s interest in a property, the total area in which the issuer has an interest multiplied by the working interest owned by the issuer.

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SPECIAL NOTE REGARDING FORWARD LOOKING STATEMENTS

Certain statements contained in this Annual Information Form, and in certain documents incorporated by reference into this Annual Information Form, constitute forward-looking statements. The use of any of the words “anticipate”, “continue”, “estimate”, “expect”, “may”, “will”, “project”, “should”, “believe” and similar expressions are intended to identify forward-looking statements.  These statements involve known and unknown risks, uncertainties and other factors that may cause actual results or events to differ materially from those anticipated in such forward-looking statements.  The Trust and the Administrator believe the expectations reflected in those forward-looking statements are reasonable, but no assurance can be given that these expectations will prove to be correct.  Such forward-looking statements included in, or incorporated by reference into, this Annual Information Form should not be unduly relied upon.  These statements speak only as of the date of this Annual Information Form or as of the date specified in the documents incorporated by reference into this Annual Information Form, as the case may be.

In particular, this Annual Information Form, and the documents incorporated by reference, contain forward-looking statements pertaining to the following:

•the performance characteristics of the Trust’s oil and natural gas properties;

•oil and natural gas production levels;

•capital expenditure programs;

•the size of the oil and natural gas reserves;

•projections of market prices and costs and the related sensitivity of distributions;

•supply and demand for oil and natural gas;

•expectations regarding the ability to raise capital and to continually add to reserves through acquisitions and development;

•treatment under governmental regulatory regimes and tax laws; and

•capital expenditure programs.

The actual results could differ materially from those anticipated in these forward-looking statements as a result of the risk factors set forth below and elsewhere in this Annual Information Form and the documents incorporated by reference herein:

•volatility in market prices for oil and natural gas;

•liabilities inherent in oil and natural gas operations;

•uncertainties associated with estimating oil and natural gas reserves;

•competition for, among other things, capital, acquisitions of reserves, undeveloped lands and skilled personnel;

•incorrect assessments of the value of acquisitions and exploration and development programs;

•geological, technical, drilling and processing problems;

•changes in income tax laws or changes in tax laws and incentive programs relating to the oil and gas industry and income trusts;

•failure to realize the anticipated benefits of acquisitions; and

•the other factors discussed under “Risk Factors”.

Statements relating to “reserves” or “resources” are deemed to be forward-looking statements, as they involve the implied assessment, based on certain estimates and assumptions, that the resources and reserves described can be profitably produced in the future.

Readers are cautioned that the foregoing lists of factors are not exhaustive. The forward-looking statements contained in this Annual Information Form and the documents incorporated by reference herein are expressly qualified by this cautionary statement.  Neither the Trust nor the Administrator undertake any obligation to publicly update or revise any forward-looking statements.

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DEFINITIONS

Unless the context indicates otherwise, the following terms shall have the meanings set out below when used in this Annual Information Form. Certain other terms and abbreviations used herein, but not defined herein, are defined in NI 51-101 or the COGE Handbook and, unless the context otherwise requires, shall have the same meanings herein as in NI 51-101 or the COGE Handbook.

“ABCA” means the Business Corporations Act, R.S.A. 2000, c. B-9, as amended, including the regulations promulgated thereunder;

“Administration Agreement” means the Administration Agreement dated December 6, 2004 between the Trustee and the Administrator, as successor to StarPoint;

“Administrator”means StarPoint Energy Ltd., a corporation formed by the amalgamation under the ABCA of StarPoint, E3 and StarPoint Acquisition Ltd. as a step to the Arrangement;

“Administrator Note Indenture” means the note indenture dated January 4, 2005 between the Administrator and Olympia Trust Company governing the issuance of the Administrator Notes;

“Administrator Notes” means the unsecured subordinated notes of the Administrator in the aggregate amount of $383,806,908.20 issued to the Trust in connection with the Arrangement;

“Administrator Report”means the independent engineering report dated February 24, 2005 prepared by Sproule evaluating, effective December 31, 2004, the oil and natural gas reserves held by StarPoint and E3 at the time of the Arrangement, less the properties transferred to Mission pursuant to the Arrangement;

“Arrangement”means the plan of arrangement under the section 193 of the ABCA and section 192 of the Canada Business Corporations Act involving StarPoint, E3, the Trust, Mission, StarPoint Acquisition Ltd., ExchangeCo, the securityholders of StarPoint and the securityholders of E3, which was completed on January 7, 2005;

“Board of Directors”or “Board”means the board of directors of the Administrator or its successors;

“Business Day”means a day, other than a Saturday or Sunday, or a statutory holiday, on which major Canadian chartered banks are open for business in Calgary, Alberta;

“Call Rights” means the Liquidation Call Right, the Redemption Call Right and the Retraction Call Right collectively, as such terms are defined in the Exchangeable Share provisions;

“COGE Handbook” means the Canadian Oil and Gas Evaluation Handbook prepared jointly by the Society of Petroleum Evaluation Engineers (Calgary chapter) and the Canadian Institute of Mining, Metallurgy & Petroleum;

“CRA” means the Canada Revenue Agency;

“Current Market Price of a Trust Unit” means, in respect of a Trust Unit on any date, the weighted average trading price of the Trust Units on the TSX for the five (5) trading days preceding that date, or, if the Trust Units are not then listed on the TSX, on such other stock exchange or automated quotation system on which the Trust Units are listed or quoted, as the case may be, as may be selected by the board of directors of the Administrator for such purpose; provided, however, that if in the opinion of the board of directors of the Administrator the public distribution or trading activity of Trust Units for that period does not result in a weighted average trading price which reflects the fair market value of a Trust Unit, then the Current Market Price of a Trust Unit shall be determined by the board of directors of the Administrator, in good faith and in its sole discretion, and provided further that any such selection, opinion or determination by such board of directors shall be conclusive and binding and for the purposes

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of this definition, the weighted average trading price shall be determined by dividing (a) the aggregate dollar trading value of all Trust Units sold on the TSX (or other stock exchange or automated quotation system, if applicable) over the applicable five trading days by (b) the total number of Trust Units sold on such stock exchange or system during such period;

“Distributable Cash” means all amounts available for distribution during any applicable period to holders of Trust Units;

“Distribution” means a distribution paid by the Trust in respect of the Trust Units, expressed as an amount per Trust Unit;

“Distribution Payment Date” means any date that Distributable Cash is distributed to Trust Unitholders, generally being the 15th day of the calendar month following any Distribution Record Date (or if such day is not a Business Day, on the next Business Day thereafter);

“Distribution Record Date” means the day on which Unitholders are identified for purposes of determining entitlement to a Distribution, generally being the last Business Day of each month;

“DRIP Plan” means the Trust’s premium distribution, distribution reinvestment and optional trust unit purchase plan;

“E3”means E3 Energy Inc., a corporation amalgamated under the ABCA with StarPoint and StarPoint Acquisition Ltd. to form the Administrator as a step to the Arrangement;

“Exchange Ratio”, at any time and in respect of each Exchangeable Share, shall be equal to 1.00000 as at January 7, 2005 and shall be cumulatively adjusted thereafter by: (a) increasing the Exchange Ratio on each Distribution Payment Date between the Effective Date and the time as of which the Exchange Ratio is calculated by an amount, rounded to the nearest five decimal places, equal to a fraction having as its numerator the Distribution, expressed as an amount per Trust Unit, paid on that Distribution Payment Date, multiplied by the Exchange Ratio immediately prior to the Distribution Record Date for such Distribution and having as its denominator the Current Market Price of a Trust Unit on the first Business Day following the Distribution Record Date for such Distribution; and (b) decreasing the Exchange Ratio on each dividend record date between the Effective Date and the time as of which the Exchange Ratio is calculated by an amount, rounded to the nearest five decimal places, equal to a fraction having as its numerator the dividend declared on that dividend record date, expressed as an amount per Exchangeable Share, and having as its denominator the Current Market Price of a Trust Unit on the date that is seven Business Days prior to that dividend record date;

“Exchangeable Shares” means series A exchangeable shares in the capital of the Administrator;

“ExchangeCo” means StarPoint Exchangeco Ltd., a corporation incorporated under the ABCA and a wholly-owned subsidiary of the Trust;

“Mission”means Mission Oil & Gas Inc., a corporation incorporated under the ABCA;

“NI 51-101” means National Instrument - 51-101 Standards of Disclosure for Oil and Gas Activities;

“Non-Resident” means: (i) a Person who is not a resident of Canada for the purposes of the Tax Act; or (ii) a partnership that is not a Canadian partnership for the purposes of the Tax Act;

“NPI” means the net profits interest granted to the Trust by the Partnership under the NPI Agreement;

“NPI Agreement” means the net profits interest agreement dated January 7, 2005 between the Partnership and the

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Trust;

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“Ordinary Resolution” means a resolution approved at a meeting of Unitholders and the holder of the Special Voting Right by more than 50 percent of the votes cast in respect of the resolution by or on behalf of Unitholders and the holder of the Special Voting Right present in person or represented by proxy at the meeting;

“Partnership” means StarPoint Energy Partnership, a general partnership formed under the laws of the Province of Alberta;

“Permitted Investments” means (i) loan advances to the Administrator, (ii) interest bearing accounts of certain financial institutions, including Canadian chartered banks and the Trustee; (iii) obligations issued or guaranteed by the Government of Canada or any province of Canada or any agency or instrumentality thereof; (iv) term deposits, guaranteed investment certificates, certificates of deposit or bankers’ acceptances of or guaranteed by any Canadian chartered bank or other financial institutions (including the Trustee and any affiliate of the Trustee), the short-term debt or deposits of which have been rated at least A or the equivalent by Standard & Poor’s Corporation, or the equivalent by Moody’s Investors Service, Inc. or Dominion Bond Rating Service Limited; (v) commercial paper rated at least A or the equivalent by Dominion Bond Rating Service Limited; and (vi) investments in bodies corporate, partnerships or trusts engaged in the oil and gas business, including shares of the Administrator;

“Person” means any individual, partnership, association, body corporate, trustee, executor, administrator, legal representative, government, regulatory authority or other entity;

“Selkirk”means Selkirk Energy Partnership, a general partnership formed under the laws of the Province of Alberta;

“Selkirk Properties”means the oil and gas properties described under the heading “Oil and Gas Properties – Selkirk Properties” formerly held by Selkirk;

“Selkirk Report”means the independent engineering report dated February 24, 2005 prepared by Sproule evaluating, effective December 31, 2004, the oil and natural gas reserves attributable to the Selkirk Properties;

“Special Resolution” means a resolution proposed to be passed as a special resolution at a meeting of Trust Unitholders (including an adjourned meeting) duly convened for the purpose and held in accordance with the provisions of the Trust Indenture at which two or more holders of at least 5 percent of the aggregate number of Trust Units then outstanding are present in person or by proxy and passed by the affirmative votes of the holders of not less than 66²/₃ percent of the Trust Units represented at the meeting and voted on a poll upon such resolution.  For the purposes of determining such percentage, the holder of any Special Voting Unit who is present at the meeting shall be regarded as representing outstanding Trust Units equivalent in number to the votes attaching to such Special Voting Unit;

“Special Voting Units” means the special voting units of the Trust issuable under the Trust Indenture;

“Sproule” means Sproule Associates Limited, independent oil and gas reservoir engineers.

“StarPoint”means StarPoint Energy Ltd., a corporation amalgamated under the ABCA with E3 and StarPoint Acquisition Ltd. to form the Administrator as a step to the Arrangement;

“Subtrust” means StarPoint Commercial Trust, an unincorporated trust formed under the laws of the Province of Alberta of which the Trust is the sole beneficiary;

“Support Agreement” means the support agreement dated January 7, 2005 among the Trust, the Administrator and ExchangeCo concerning certain matters affecting the Exchangeable Shares;

“Tax Act” means the Income Tax Act (Canada), R.S.C. 1985, c. 1 (5th Supp), as amended, including the regulations promulgated thereunder;

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“Trust”means StarPoint Energy Trust, a trust formed pursuant to the laws of Alberta;

“Trust Indenture” means the trust indenture dated December 6, 2004 between Olympia Trust Company and StarPoint, pursuant to which the Trust is governed;

“Trust Units” means units of the Trust;

“Trustee” means Olympia Trust Company or its successor, as trustee of the Trust;

“TSX”means the Toronto Stock Exchange;

“Unitholder” means a holder of Trust Units;

“Voting and Exchange Agreement Trustee” means Olympia Trust Company, the initial trustee under the Voting and Exchange Trust Agreement, or such other trustee, from time to time appointed thereunder; and

“Voting and Exchange Trust Agreement” means the voting and exchange trust agreement dated January 7, 2005 among the Trust, the Administrator, ExchangeCo and the Voting and Exchange Agreement Trustee concerning certain matters affecting the Exchangeable Shares.

Words importing the singular number only include the plural, and vice versa, and words importing any gender include all genders. All dollar amounts set forth in this Annual Information Form are in Canadian dollars, except where otherwise indicated.

NON-GAAP MEASURES

In this Annual Information Form and in the documents incorporated by reference into this Annual Information Form, the Trust uses the term “cash flow from operations”, “cash flow from operations per unit” and “net backs” as indicators of financial performance and to facilitate comparative analysis. These measures are not measures recognized by Canadian generally accepted accounting principles (“GAAP”) and do not have a standardized meaning prescribed by GAAP.  Therefore, these measures, as defined by the Trust, may not be comparable to similar measures presented by other issuers.  Investors are cautioned that “cash flow from operations” and “cash flow from operations per unit” should not be construed as an alternative to net earnings, cash flow from operating activities or other measures of financial performance calculated in accordance with GAAP. The Trust considers “cash flow from operations” a key measure of performance as it demonstrates the Trust’s ability to generate the cash flow necessary to fund future distributions and capital investments. The Trust considers “net backs” a key measure as it indicates the relative performance of the crude oil and natural gas assets.  Cash flow can not be assured and future distributions may vary.  See “Risk Factors – Distributions”.

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STARPOINT ENERGY TRUST

General

The Trust is an open–ended unincorporated investment trust governed by the laws of the Province of Alberta and created pursuant to the Trust Indenture.  The head office of the Trust is located at Suite 3900, 205 - 5th Avenue S.W., Calgary, Alberta.

The Trust was formed on December 6, 2004 and commenced operations on January 7, 2005 as a result of the completion of the Arrangement.

Structure

The Trust is the sole shareholder of the common shares of the Administrator.  The head office of the Administrator is located at Suite 3900, 205 - 5th Avenue S.W., Calgary, Alberta and its registered office is located at Suite 1200, 425 – 1^st Street S.W., Calgary, Alberta.

The Administrator has generally been delegated the significant management decisions of the Trust.  In particular, pursuant to the Administration Agreement between the Trust and the Administrator, the Trustee has delegated to the Administrator responsibility for the administration and management of all general and administrative affairs of the Trust, including matters relating to the following: (i) maintaining records; (ii) preparing and filing tax returns and monitoring the tax status of the Trust;  (iii) advising the Trust with respect to compliance with applicable securities laws; (iv) ensuring compliance with all applicable laws, including in relation to an offering; (v) all matters relating to the content of any offering documents, the accuracy of the disclosure contained therein, and the certification thereof; (vi) retaining professional advisors; (vii) all matters concerning the terms of, and amendment from time to time of the material contracts of the Trust; (viii) all matters concerning any underwriting or agency agreement providing for the sale of Trust Units or rights to Trust Units; (ix) all matters relating to the redemption of Trust Units; (x) certain matters relating to the specific powers and authorities as set forth in the Trust Indenture; (xi) determining and arranging for distributions; (xii) reporting to Unitholders;  (xiii) providing management services for the efficient and economic exploitation of the assets of the Trust and (xiv) recommending, carrying out and monitoring property acquisitions and dispositions and exploitation and development programs for the Trust.

The Administrator owns all of the issued and outstanding shares of Trend Energy Inc. (“Trend”), a corporation incorporated under the ABCA, and directly and indirectly owns all of the partnership interests in the Partnership.

The Trust owns all of the issued and outstanding shares of ExchangeCo, the primary purpose of which is to accommodate certain ancillary exchange, put and call rights attaching to the Exchangeable Shares.

Subtrust is an unincorporated trust established on January 27, 2005 under the laws of the Province of Alberta pursuant to a trust indenture between the Administrator and 1149708 Alberta Ltd.  1149708 Alberta Ltd., a wholly-owned subsidiary of the Administrator incorporated under the ABCA, is the trustee of Subtrust.  The Trust is the sole beneficiary of Subtrust.  The business of Subtrust is acquiring, developing, exploiting, owning and disposing of oil and natural gas properties.

Where applicable, references to the business, assets and operations of the Trust made in this Annual Information Form should be considered by readers to refer to the business, assets and operations of the Trust and is subsidiaries on a consolidated basis.

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The following diagram shows the simplified structure of the Trust as at the date hereof:

DEVELOPMENT OF THE BUSINESS OF THE TRUST

The Arrangement

The Trust was formed on December 6, 2004 and commenced operations on January 7, 2005 as a result of the completion of the Arrangement.  The Arrangement was conducted for the purposes of reorganizing the businesses of StarPoint and E3 into two new entities; namely, the Trust and Mission.  Prior to the Arrangement, each of StarPoint and E3 were oil and natural gas exploration and production companies whose common shares were listed on the TSX.

 The Arrangement had many steps, but the net effect of the Arrangement was as follows:

•the holders of common shares of StarPoint exchanged each such share they owned for:

•0.25 of a Trust Unit or, at the election of the holder, 0.25 of an Exchangeable Share; and

•0.1111 of a common share of Mission.

•the holders of common shares of E3 exchanged each such share they owned for:

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•0.11 of a Trust Unit or, at the election of the holder, 0.11 of an Exchangeable Share; and

•0.0488 of a common share of Mission.

•certain exploration assets and undeveloped lands held by StarPoint prior to the Arrangement were transferred to Mission.

•StarPoint and E3 amalgamated with StarPoint Acquisition Ltd. to become the Administrator, a wholly-owned subsidiary of the Trust.

As a result of the Arrangement and the exercise of options to acquire Trust Units issued under the Arrangement in exchange for the outstanding options to acquire common shares of StarPoint and E3, a total of 22,151,846 Trust Units and 3,494,595 Exchangeable Shares were issued to the former holders of StarPoint and E3 common shares.

Acquisition of Selkirk

On January 28, 2005, the Administrator acquired all of the issued and outstanding shares of four private corporations for aggregate cash consideration of $63.1 million. Together, the private corporations owned 100% of the interests in Selkirk.  Selkirk was subsequently reorganized such that it was dissolved and Subtrust now holds all of the assets and liabilities of Selkirk.  The Selkirk Properties, the oil and natural gas reserves attributable to those properties and historical production volumes for the Selkirk Properties are described in detail under the applicable headings in this Annual Information Form.

Offering of Trust Units

On February 10, 2005, the Trust completed an offering of 3,760,000 trust units at a price of $18.00 each for gross proceeds of $67,680,000.

Potential Acquisitions

The Trust continues to evaluate potential acquisitions of all types of petroleum and natural gas and other energy-related assets as part of its ongoing acquisition program. The Trust is normally in the process of evaluating several potential acquisitions at any one time which, individually or together, could be material.  The Trust can not predict whether any current or future opportunities will result in one or more acquisitions for the Trust.

DESCRIPTION OF THE BUSINESS OF THE TRUST

Business of the Trust

The Trust owns all of the issued and outstanding common shares of the Administrator.  The Administrator directly or indirectly holds all of the assets held by StarPoint and E3 prior to the Arrangement, other than those assets transferred to Mission as part of the Arrangement. The Administrator has retained all of the liabilities of StarPoint and E3, including liabilities relating to corporate and income tax matters. The Administrator carries on an oil and natural gas exploration and production business similar to that carried on by StarPoint and E3 prior to the Arrangement becoming effective.  The Trust is also the sole beneficiary of Subtrust.  Subtrust holds all of the assets formerly held by Selkirk.

The Trust’s primary mandate is to focus on low cost operations, maintain and grow reserves and production and distribute approximately 75 - 85% of its available cash flow (at current commodity prices) to Unitholders in monthly distributions.  The Trust pursues an integrated strategy of acquisitions, exploitation and development of high quality, long life, light oil and natural gas reserves within its core areas of Southeast Saskatchewan, Central Alberta and the plains area of Northeast British Columbia.

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Distributions

The Trustee may declare payable to the Unitholders all or any part of the net income of the Trust.  It is currently anticipated that the only income to be received by the Trust will be from the interest received on the principal amount of the Administrator Notes, income under the NPI Agreement and income received from Subtrust.  In addition, Unitholders may, at the discretion of the Board of Directors, receive distributions in respect of prepayments of principal on the Administrator Notes made by the Administrator to the Trust before the maturity of the Administrator Notes.

The Trust expects to make monthly cash distributions to Unitholders of its income and amounts representing the repayment of principal on the Administrator Notes, after expenses and any cash redemptions of Trust Units.

It is expected that cash distributions will be made on the 15th day of each month to Unitholders of record on the immediately preceding distribution record date, generally being the last Business Day of each month.  On January 19, 2005, the Trust announced that the Board of Directors had established a distribution policy of monthly distributions of $0.20 per Trust Unit for 2005.  On February 15, 2005, a distribution of $0.20 per Trust Unit was paid to Unitholders of record on January 31, 2005. On February 9, 2005, the Trust announced that the Board of Directors had declared a distribution of $0.20 per Trust Unit to be paid on March 15, 2005 for Unitholders of record on February 22, 2005.

Competition

The oil and natural gas industry is competitive in all its phases.  The Trust competes with numerous other participants in the search for, and the acquisition of, oil and natural gas properties and in the marketing of oil and natural gas. The Trust’s competitors include resource companies which have greater financial resources, staff and facilities than those of the Trust.  Competitive factors in the distribution and marketing of oil and natural gas include price and methods and reliability of delivery.  The Trust views its competitive position as being equivalent to that of other oil and gas issuers of similar size and at a similar stage of development.

Seasonal Factors

The exploration for and development of oil and natural gas reserves is dependent on access to areas where production is to be conducted.  Seasonal weather variations, including freeze-up and break-up, affect access in certain circumstances.

Environmental Regulation

The oil and natural gas industry is currently subject to environmental regulations pursuant to a variety of provincial and federal legislation. Compliance with such legislation can require significant expenditures or result in operational restrictions. Breach of such requirements may result in suspension or revocation of necessary licenses and authorizations, civil liability for pollution damage and the imposition of material fines and penalties, all of which might have a significant negative impact on earnings and overall competitiveness.  See under the heading “Industry Conditions - Environmental Regulation”.

Personnel

As at January 7, 2005, being the date of the completion of the Arrangement, the Administrator had 27 head office employees and 14 field employees.

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DRIP Plan

The Trust has implemented the DRIP Plan for eligible Unitholders. The DRIP Plan provides Unitholders with the opportunity to reinvest monthly cash distributions to acquire additional Trust Units at 95% of the average market price, as defined in the DRIP Plan, on the applicable distribution date.  The DRIP Plan includes a feature which allows eligible Unitholders to elect to have these additional Trust Units delivered to a designated broker in exchange for a premium cash distribution equal to 102% of the cash distribution that such Unitholders would have otherwise been entitled to receive on the applicable distribution date, subject to a proration in certain events. In addition, the DRIP Plan allows participating Unitholders to purchase additional Trust Units from treasury for cash at a purchase price equal to the average market price (with no discount) in minimum amounts of $1,000 per remittance and up to $100,000 aggregate amount of remittances by a Unitholder in any calendar month, all subject to an overall annual limit of 2% of the outstanding Trust Units.  Generally, no brokerage fees or commissions will be payable by participants for the purchase of Trust Units under the Plan, but Unitholders should make inquiries with their broker, investment dealer or financial institution through which their Trust Units are held as to any policies of such party that would result in any fees or commissions being payable.

INDUSTRY CONDITIONS

The oil and natural gas industry is subject to extensive controls and regulations governing its operations (including land tenure, exploration, development, production, refining, transportation and marketing) imposed by legislation enacted by various levels of government and with respect to pricing and taxation of oil and natural gas by agreements among the governments of Canada, Alberta, British Columbia and Saskatchewan, all of which should be carefully considered by investors in the oil and gas industry. It is not expected that any of these controls or regulations will affect the operations of the Trust in a manner materially different than they would affect other oil and gas issuers of similar size.  All current legislation is a matter of public record and the Trust is unable to predict what additional legislation or amendments may be enacted.  Outlined below are some of the principal aspects of legislation, regulations and agreements governing the oil and gas industry.

Pricing and Marketing - Oil, Natural Gas and Associated Products

In the provinces of Alberta, British Columbia and Saskatchewan oil, natural gas and associated products are generally sold at market index based prices. These indices are generated at various sales points depending on the commodity and are reflective of the current value of the commodity adjusted for quality and locational differentials. While these indices tend to track industry reference prices (ie. price of West Texas Intermediate crude oil at Cushing, Oklahoma or price of natural gas at Henry Hub, Louisiana), some variances can occur due to specific supply-demand imbalances. These differentials can change on a monthly or daily basis depending on the supply-demand fundamental at each location as well as other non-related changes such as the value of the Canadian dollar and the cost of transporting the commodity to the pricing point of the particular index.

The North American Free Trade Agreement

The North American Free Trade Agreement (“NAFTA”) among the governments of Canada, United States of America and Mexico became effective on January 1, 1994. NAFTA carries forward most of the material energy terms that are contained in the Canada and United States Free Trade Agreement.  Canada continues to remain free to determine whether exports of energy resources to the United States or Mexico will be allowed, provided that any export restrictions do not: (i) reduce the proportion of energy resources exported relative to domestic use (based upon the proportion prevailing in the most recent 36 month period); (ii) impose an export price higher than the domestic price; or (iii) disrupt normal channels of supply. All three countries are prohibited from imposing minimum export or import price requirements.

NAFTA contemplates the reduction of Mexican restrictive trade practices in the energy sector and prohibits discriminatory border restrictions and export taxes. The agreement also contemplates clearer disciplines on regulators to ensure fair implementation of any regulatory changes and to minimize disruption of contractual arrangements,

17

which is important for Canadian natural gas exports.

Provincial Royalties and Incentives

In addition to federal regulation, each province has legislation and regulations which govern land tenure, royalties, production rates, environmental protection and other matters. The royalty regime is a significant factor in the profitability of crude oil, natural gas liquids, sulphur and natural gas production. Royalties payable on production from lands other than Crown lands are determined by negotiations between the mineral owner and the lessee, although production from such lands is subject to certain provincial taxes and royalties. Crown royalties are determined by governmental regulation and are generally calculated as a percentage of the value of the gross production. The rate of royalties payable generally depends in part on prescribed reference prices, well productivity, geographical location, field discovery date and the type or quality of the petroleum product produced.

From time to time, the governments of the western Canadian provinces create incentive programs for exploration and development. Such programs often provide for royalty rate reductions, royalty holidays and tax credits, and are generally introduced when commodity prices are low. The programs are designed to encourage exploration and development activity by improving earnings and cash flow within the industry.

In the Province of Alberta, a producer of oil or natural gas is entitled to a credit against the royalties payable to the Crown by virtue of the Alberta royalty tax credit (“ARTC”) program. The ARTC rate is based on a price sensitive formula and the ARTC rate varies between 75% at prices at and below $100 per m3 and 25% at prices at and above $210 per m3. The ARTC rate is applied to a maximum of $2,000,000 of Alberta Crown royalties payable for each producer or associated group of producers. Crown royalties on production from producing properties acquired from a corporation claiming maximum entitlement to ARTC will generally not be eligible for ARTC. The rate will be established quarterly based on the average “par price”, as determined by the Alberta Department of Energy for the previous quarterly period.

Crude oil and natural gas royalty programs for specific wells and royalty reductions will reduce the amount of Crown royalties paid by the Trust to the provincial governments. In general, the ARTC program provides a rebate on Alberta Crown royalties paid in respect of eligible producing properties.

Land Tenure

Crude oil and natural gas located in Western Canada is owned predominantly by the respective provincial governments. Provincial governments grant rights to explore for and produce oil and natural gas pursuant to leases, licenses and permits for varying terms from two years and on conditions set forth in provincial, legislation including requirements to perform specific work or make payments. Oil and natural gas located in such provinces can also be privately owned and rights to explore for and produce such oil and natural gas on freehold lands are granted by lease on such terms and conditions as may be negotiated.

Environmental Regulation

The oil and natural gas industry is subject to environmental regulation pursuant to a variety of international conventions and Canadian federal, provincial and municipal laws, regulations, and guidelines. Such regulation provides for restrictions and prohibitions on the release or emission of various substances produced in association with certain oil and gas industry operations. In addition, such regulation requires that well and facility sites be abandoned and reclaimed to the satisfaction of provincial authorities. Compliance with such regulation can require significant expenditures and a breach of such requirements may result in suspension or revocation of necessary licenses and authorizations, civil liability for pollution damage and the imposition of material fines and penalties.

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Environmental legislation in the Province of Alberta has been consolidated into the AEPEA, which came into force on September 1, 1993. The AEPEA imposes stricter environmental standards, requires more stringent compliance, reporting and monitoring obligations and significantly increases penalties. The Trust is committed to meeting its responsibilities to protect the environment wherever it operates and anticipates making increased expenditures of both a capital and an expense nature as a result of the increasingly stringent laws relating to the protection of the environment and will be taking such steps as required to ensure compliance with the AEPEA and similar legislation in other jurisdictions in which it operates. The Trust believes that it is reasonably likely that the trend towards stricter standards in environmental legislation and regulation will continue.

Canada is a signatory to the United Nations Framework Convention on Climate Change. Canada has ratified the Kyoto Protocol established thereunder and the Kyoto Protocol has come into force.  Annex B parties to the Kyoto Protocol, including Canada, are required to establish legally binding targets to reduce nation-wide emissions of carbon dioxide, methane, nitrous oxide and other so-called “greenhouse gases”. The Trust’s exploration and production facilities and other operations and activities will emit a small amount of greenhouse gasses which may subject the Trust to legislation in Canada regulating emissions of greenhouse gases. The Government of Canada has put forward a Climate Change Plan for Canada which suggests further legislation to set greenhouse gases emission reduction requirements for various industrial activities, including oil and gas exploration and production. Future Canadian federal legislation, together with provincial emission reduction requirements, such as those proposed in the Climate Change and Emissions Management Act (Alberta), may require the reduction of emissions or emissions intensity from the Trust’s operations and facilities. The direct and indirect costs of complying with these emissions regulations may adversely affect the business of the Trust.

Trends

There are a number of trends in the oil and natural gas industry that are shaping the near term future of the business. The first trend has been the continuation of oil and natural gas companies converting to royalty trusts. These conversions occur because the equity markets generally value trusts at higher multiples than exploration and development firms. The conversion announcement often results in the appreciation of its share price to premiums equivalent to other trusts.

Efforts of trusts to replace annual production declines have resulted in continued high levels of competition for the acquisition of oil and natural gas properties and related assets. This increased competition has raised valuation parameters for corporate and asset acquisitions. Those trusts with opportunities to economically replace production through internal development drilling should be in a favourable position relative to those more exposed to replacing production through acquisitions.

Natural gas prices have been extremely volatile over the past 12 months. With the supply and demand balance for natural gas being extremely tight, the market is experiencing a great deal of volatility in pricing due to a number of factors, including weather, drilling activity, declines, storage levels, fuel switching and demand.

Oil prices are clearly dependent on the world economy and the global supply-demand balance. The current environment of geopolitical unrest has increased prices well above those supported by current supply-demand balances. While pricing in the future may more accurately reflect supply-demand fundamentals, it would appear that the current tight supply environment is highly sensitive to political and terrorist risks as evidenced by the risk premium in the current price structure. The magnitude of this risk premium may change over time.

Although commodity prices are higher than historical levels, the appreciation of the Canadian dollar in 2003 relative to its US counterpart has offset a portion of the economic benefit of higher prices on Canadian oil and natural gas producers including trusts. The stronger Canadian dollar resulted in decreased revenues in 2004 for oil and natural gas producers on a per barrel basis, increasing pressure on the royalty trusts’ ability to maintain current distribution levels.

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OIL AND NATURAL GAS RESERVES AND NET PRESENT VALUE OF FUTURE NET REVENUE

In accordance with National Instrument 51-101 – Standards of Disclosure for Oil and Gas Activities, Sproule prepared the Administrator Report.  The Administrator Report evaluated, as at December 31, 2004, the oil, NGL and natural gas reserves attributable to the properties held by StarPoint and E3, less the properties transferred to Mission pursuant to the Arrangement.  Following the completion of the Arrangement on January 7, 2005, these properties were held, directly or indirectly, by the Administrator.  The Trust owns all of the outstanding common shares of the Administrator.  Although the Trust did not beneficially own the oil, NGL and natural gas reserves attributable to these properties until January 7, 2005, the reserves information herein has been presented as if the acquisition of these properties had been completed effective December 31, 2004.

In accordance with National Instrument 51-101 – Standards of Disclosure for Oil and Gas Activities, Sproule prepared the Selkirk Report.  The Selkirk Report evaluated, as at December 31, 2004, the oil, NGL and natural gas reserves attributable to the Selkirk Properties. The Administrator acquired Selkirk on January 28, 2005.  Subsequently, Selkirk was reorganized such that it was dissolved and the Selkirk Properties were transferred to Subtrust.  The Trust is the sole beneficiary of Subtrust.  Although the Trust did not beneficially own the oil, NGL and natural gas reserves attributable to the Selkirk Properties until January 28, 2005, the reserves information herein has been presented as if the acquisition of these properties had been completed effective December 31, 2004.

The tables below are a summary of the oil, NGL and natural gas reserves of the Trust, through its interests in the Administrator and Subtrust, and the net present value of future net revenue attributable to such reserves as evaluated in the Administrator Report and the Selkirk Report, based on constant and forecast price and cost assumptions.  The tables summarize the data contained in the Administrator Report and the Selkirk Report and, as a result, may contain slightly different numbers than such reports due to rounding.  Also due to rounding, certain columns may not add exactly.  Finally, numbers may not add due to the inclusion of Saskatchewan Corporate Capital Tax.

Information disclosed below under the “Pro Forma” subheadings refers to the applicable information under the Administrator Report and Selkirk Report presented, for ease of reference, on a pro forma basis effective December 31, 2004.

The net present value of future net revenue attributable to reserves is stated without provision for interest costs and general and administrative costs, but after providing for estimated royalties, production costs, development costs, other income, future capital expenditures, and well abandonment costs for only those wells assigned reserves by Sproule.  It should not be assumed that the undiscounted or discounted net present value of future net revenue attributable to reserves estimated by Sproule represent the fair market value of those reserves. Other assumptions and qualifications relating to costs, prices for future production and other matters are summarized herein.  The recovery and reserve estimates of oil, NGL and natural gas reserves provided herein are estimates only and actual reserves may be greater than or less than the estimates provided herein.

The values shown for income taxes and future net revenue after income taxes were calculated on a stand-alone basis in both the Administrator Report and the Selkirk Report.  The values shown may not be representative of future income tax obligations, applicable tax horizon or after-tax valuation.

The Administrator Report and Selkirk Report are based on certain factual data supplied by the Administrator and Subtrust and Sproule’s opinion of reasonable practice in the industry.  The extent and character of ownership and all factual data pertaining to the Administrator and Subtrust’s petroleum properties and contracts (except for certain information residing in the public domain) were supplied by the Administrator and Subtrust to Sproule.  Sproule accepted this data as presented and neither title searches nor field inspections were conducted.

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Summary of Oil and Gas Reserves – Constant Prices and Costs

Administrator Report

	Gross Reserves				Net Reserves
	Light and Medium Crude Oil	Heavy Crude Oil	Natural Gas Liquids	Natural Gas	Light and Medium Crude Oil	Heavy Crude Oil	Natural Gas Liquids	Natural Gas
	Mbbls	Mbbls	Mbbls	Mmcf	Mbbls	Mbbls	Mbbls	Mmcf
Proved
Developed Producing	7,234.2	2,142.0	145.8	21,795	6,112.9	2,035.7	109.7	16,649
Developed Non-Producing	0.0	91.8	13.0	618	0.0	84.4	8.7	466
Undeveloped	1,311.3	0.0	23.5	3,845	1,149.8	0.0	18.8	2,838
Total Proved	8,545.5	2,233.7	182.3	26,258	7,262.7	2,120.2	137.3	19,952
Probable	7,541.6	533.2	151.1	19,102	6,438.7	507.3	112.7	14,614
Total Proved plus Probable	16,087.1	2,766.9	333.4	45,359	13,701.5	2,627.5	250.0	34,565

Selkirk Report

	Gross Reserves			Net Reserves
	Light and Medium Crude Oil	Natural Gas Liquids	Natural Gas	Light and Medium Crude Oil	Natural Gas Liquids	Natural Gas
	Mbbls	Mbbls	Mmcf	Mbbls	Mbbls	Mmcf
Proved
Developed Producing	0.0	853.7	8,133	0.0	823.0	6,217
Developed Non-Producing	0.0	58.5	1,023	0.0	57.7	766
Undeveloped	0.0	24.0	217	0.0	23.7	166
Total Proved	0.0	936.3	9,374	0.0	904.4	7,149
Probable	0.0	453.7	5,338	0.0	440.1	4,122
Total Proved plus Probable	0.0	1,390.0	14,712	0.0	1,344.4	11,271

Pro Forma

	Gross Reserves				Net Reserves
	Light and Medium Crude Oil	Heavy Crude Oil	Natural Gas Liquids	Natural Gas	Light and Medium Crude Oil	Heavy Crude Oil	Natural Gas Liquids	Natural Gas
	Mbbls	Mbbls	Mbbls	Mmcf	Mbbls	Mbbls	Mbbls	Mmcf
Proved
Developed Producing	7,234.2	2,142.0	999.5	29,928	6,112.9	2,035.7	932.7	22,866
Developed Non-Producing	0.0	91.8	71.5	1,641	0.0	84.4	66.4	1,232
Undeveloped	1,311.3	0.0	47.5	4,062	1,149.8	0.0	42.5	3,004
Total Proved	8,545.5	2,233.7	1,118.6	35,632	7,262.7	2,120.2	1,041.7	27,101
Probable	7,541.6	533.2	604.8	24,440	6,438.7	507.3	552.8	18,736
Total Proved plus Probable	16,087.1	2,766.9	1,723.4	60,071	13,701.5	2,627.5	1,594.4	45,836

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Net Present Value of Future Net Revenue – Constant Prices and Costs

Administrator Report

	Before Future Income Tax Expenses and Discounted at		After Future Income Tax Expenses and Discounted at
	0%	10%	0%	10%
	(M$)	(M$)	(M$)	(M$)
Proved
Developed Producing	196,378	145,425	173,961	129,516
Developed Non-Producing	3,013	2,173	1,939	1,386
Undeveloped	28,554	16,997	19,774	11,183
Total Proved	227,946	164,594	195,673	142,085
Probable	183,428	83,984	122,823	54,859
Total Proved plus Probable	411,374	248,578	318,497	196,944

Selkirk Report

	Before Future Income Tax Expenses and Discounted at		After Future Income Tax Expenses and Discounted at
	0%	10%	0%	10%
	(M$)	(M$)	(M$)	(M$)
Proved
Developed Producing	58,662	40,045	41,838	28,852
Developed Non-Producing	5,792	4,328	3,897	2,861
Undeveloped	996	751	654	450
Total Proved	65,450	45,123	46,389	32,163
Probable	31,196	12,663	20,689	8,128
Total Proved plus Probable	96,647	57,786	67,078	40,292

Pro Forma

	Before Future Income Tax Expenses and Discounted at		After Future Income Tax Expenses and Discounted at
	0%	10%	0%	10%
	(M$)	(M$)	(M$)	(M$)
Proved
Developed Producing	255,040	185,470	215,799	158,368
Developed Non-Producing	8,805	6,501	5,836	4,247
Undeveloped	29,550	2,450	20,428	11,633
Total Proved	293,396	209,717	242,062	174,248
Probable	214,624	96,647	143,512	62,987
Total Proved plus Probable	508,021	306,364	385,575	237,236

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Additional Information Concerning Future Net Revenue – Constant Prices and Costs

Administrator Report

(Undiscounted)	Revenue	Royalties	Operating Costs	Development Costs	Abandonment and Reclamation Costs	Future Net Revenue Before Income Taxes	Income Taxes	Future Net Revenue After Income Taxes
	(M$)	(M$)	(M$)	(M$)	(M$)	(M$)	(M$)	(M$)
Total Proved Reserves	487,393	94,073	132,935	15,707	16,732	227,946	32,272	195,673
Total Proved plus Probable	874,279	171,006	230,862	37,299	23,739	411,374	92,877	318,497

Selkirk Report

(Undiscounted)	Revenue	Royalties	Operating Costs	Development Costs	Abandonment and Reclamation Costs	Future Net Revenue Before Income Taxes	Income Taxes	Future Net Revenue After Income Taxes
	(M$)	(M$)	(M$)	(M$)	(M$)	(M$)	(M$)	(M$)
Total Proved Reserves	90,919	11,101	12,595	1,090	683	65,450	19,062	46,388
Total Proved plus Probable	139,857	17,744	20,225	4,490	752	96,647	29,569	67,078

Pro Forma

(Undiscounted)	Revenue	Royalties	Operating Costs	Development Costs	Abandonment and Reclamation Costs	Future Net Revenue Before Income Taxes	Income Taxes	Future Net Revenue After Income Taxes
	(M$)	(M$)	(M$)	(M$)	(M$)	(M$)	(M$)	(M$)
Total Proved Reserves	578,312	105,174	145,530	16,797	17,415	293,396	51,334	242,061
Total Proved plus Probable	1,014,136	188,750	251,087	41,789	24,491	508,021	122,446	385,575

Future Net Revenue by Production Group – Constant Prices and Costs

Administrator Report

	Future Net Revenue Before Income Taxes and Discounted at 10%
	(M$)
Proved
Light and Medium Crude Oil(1)	91,867
Heavy Oil(1)	7,347
Natural Gas(2)	65,028
Proved plus Probable
Light and Medium Crude Oil(1)	143,263
Heavy Oil(1)	8,269
Natural Gas(2)	96,325

Notes:

(1)Including solution gas and other by-products.

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(2)Including by-products, but excluding solution gas from oil wells.

24

Selkirk Report

	Future Net Revenue Before Income Taxes and Discounted at 10%
	(M$)
Proved
Natural Gas(1)	45,123
Proved plus Probable
Natural Gas(1)	57,786

Notes:

(1)Including by-products, but excluding solution gas from oil wells.

Pro Forma

	Future Net Revenue Before Income Taxes and Discounted at 10%
	(M$)
Proved
Light and Medium Crude Oil(1)	91,867
Heavy Oil(1)	7,347
Natural Gas(2)	110,151
Proved plus Probable
Light and Medium Crude Oil(1)	143,263
Heavy Oil(1)	8,269
Natural Gas(2)	154,111

Notes:

(1)Including solution gas and other by-products.

(2)Including by-products, but excluding solution gas from oil wells.

Summary of Oil and Gas Reserves – Forecast Prices and Costs

Administrator Report

	Gross Reserves				Net Reserves
	Light and Medium Crude Oil	Heavy Crude Oil	Natural Gas Liquids	Natural Gas	Light and Medium Crude Oil	Heavy Crude Oil	Natural Gas Liquids	Natural Gas
	Mbbls	Mbbls	Mbbls	Mmcf	Mbbls	Mbbls	Mbbls	Mmcf
Proved
Developed Producing	7,104.9	2,781.5	142.4	21,760	6,016.1	2,613.3	107.5	16,623
Developed Non-Producing	0.0	98.7	13.0	619	0.0	87.4	8.8	466
Undeveloped	1,292.9	0.0	23.5	3,843	1,135.7	0.0	18.8	2,838
Total Proved	8,397.8	2,880.1	178.9	26,222	7,151.8	2,700.8	135.0	19,926
Probable	7,322.6	1,026.7	148.9	19,037	6,274.9	970.5	111.5	14,544
Total Proved plus Probable	15,720.5	3,906.9	327.8	45,260	13,426.7	3,671.2	246.6	34,471

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Selkirk Report

	Gross Reserves			Net Reserves
	Light and Medium Crude Oil	NaturalGasLiquids	NaturalGas	Light and Medium Crude Oil	NaturalGasLiquids	NaturalGas
	Mbbls	Mbbls	Mmcf	Mbbls	Mbbls	Mmcf
Proved
Developed Producing	0.0	855.0	8,195	0.0	824.4	6,269
Developed Non-Producing	0.0	58.5	1,023	0.0	57.7	766
Undeveloped	0.0	24.0	217	0.0	23.7	166
Total Proved	0.0	937.5	9,436	0.0	905.8	7,202
Probable	0.0	464.2	5,334	0.0	450.8	4,113
Total Proved plus Probable	0.0	1401.8	14,770	0.0	1,356.6	11,315

Pro Forma

	Gross Reserves				Net Reserves
	Light and Medium Crude Oil	Heavy Crude Oil	NaturalGasLiquids	Natural Gas	Light and Medium Crude Oil	Heavy Crude Oil	NaturalGasLiquids	NaturalGas
	Mbbls	Mbbls	Mbbls	Mmcf	Mbbls	Mbbls	Mbbls	Mmcf
Proved
Developed Producing	7,104.9	2,781.5	997.4	29,995	6,016.1	2,613.3	931.9	22,892
Developed Non-Producing	0.0	98.7	71.5	1,642	0.0	87.4	66.5	1,232
Undeveloped	1,292.9	0.0	47.5	4,060	1,135.7	0.0	42.5	3,004
Total Proved	8,397.8	2,880.1	1,116.4	35,658	7,151.8	2,700.8	1,040.8	27,128
Probable	7,322.6	1,026.7	613.1	24,371	6,274.9	970.5	562.3	18,657
Total Proved plus Probable	15,720.5	3,906.9	1,729.6	60,030	13,426.7	3,671.2	1,603.2	45,786

Net Present Value of Future Net Revenue – Forecast Prices and Costs

Administrator Report

	Before Future Income Tax Expenses and Discounted at
	0%	5%	10%	15%	20%
	(M$)	(M$)	(M$)	(M$)	(M$)
Proved
Developed Producing	226,812	196,575	173,339	156,365	143,396
Developed Non-Producing	3,496	3,026	2,687	2,432	2,233
Undeveloped	29,471	23,501	18,659	15,457	13,014
Total Proved	259,778	222,652	194,685	174,254	158,643
Probable	190,501	119,831	86,907	67,644	54,920
Total Proved plus Probable	450,279	342,484	281,592	241,898	213,564

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	After Future Income Tax Expenses and Discounted at
	0%	5%	10%	15%	20%
	(M$)	(M$)	(M$)	(M$)	(M$)
Proved
Developed Producing	193,266	167,346	147,100	132,359	121,143
Developed Non-Producing	2,252	1,941	1,717	1,548	1,417
Undeveloped	20,687	15,854	12,559	10,159	8,329
Total Proved	216,206	185,141	161,375	144,066	130,889
Probable	127,567	79,335	56,897	43,716	34,972
Total Proved plus Probable	343,773	264,476	218,273	187,782	165,861

Selkirk Report

	Before Future Income Tax Expenses and Discounted at
	0%	5%	10%	15%	20%
	(M$)	(M$)	(M$)	(M$)	(M$)
Proved
Developed Producing	49,301	40,552	34,718	30,566	27,459
Developed Non-Producing	4,977	4,323	3,815	3,412	3,086
Undeveloped	843	732	639	559	490
Total Proved	55,120	45,608	39,172	34,537	31,035
Probable	25,635	15,141	10,146	7,344	5,574
Total Proved plus Probable	80,755	60,749	49,318	41,881	36,610

	After Future Income Tax Expenses and Discounted at
	0%	5%	10%	15%	20%
	(M$)	(M$)	(M$)	(M$)	(M$)
Proved
Developed Producing	35,620	29,456	25,313	22,346	20,114
Developed Non-Producing	3,355	2,884	2,521	2,233	2,001
Undeveloped	552	455	375	309	253
Total Proved	39,528	32,795	28,209	24,888	22,368
Probable	16,998	9,883	6,458	4,514	3,273
Total Proved plus Probable	56,526	42,679	34,667	29,402	25,641

27

Pro Forma

	Before Future Income Tax Expenses and Discounted at
	0%	5%	10%	15%	20%
	(M$)	(M$)	(M$)	(M$)	(M$)
Proved
Developed Producing	276,113	237,127	208,057	186,931	170,855
Developed Non-Producing	8,473	7,349	6,502	5,844	5,319
Undeveloped	30,314	23,783	19,298	16,016	13,504
Total Proved	314,898	268,260	233,857	208,791	189,678
Probable	216,136	134,972	97,053	74,988	60,494
Total Proved plus Probable	531,034	403,233	330,910	283,779	250,174

	After Future Income Tax Expenses and Discounted at
	0%	5%	10%	15%	20%
	(M$)	(M$)	(M$)	(M$)	(M$)
Proved
Developed Producing	228,886	196,802	172,413	154,705	141,257
Developed Non-Producing	5,607	4,825	4,238	3,781	3,418
Undeveloped	21,239	16,309	12,934	10,468	8,582
Total Proved	255,734	217,936	189,584	168,954	153,257
Probable	144,565	89,218	63,355	48,230	38,245
Total Proved plus Probable	400,299	307,155	252,940	217,184	191,502

Additional Information Concerning Future Net Revenue – Forecast Prices and Costs

Administrator Report

(Undiscounted)	Revenue	Royalties	Operating Costs	Development Costs	Abandonment and Reclamation Costs	Future Net Revenue Before Income Taxes	Income Taxes	Future Net Revenue After Income Taxes
	(M$)	(M$)	(M$)	(M$)	(M$)	(M$)	(M$)	(M$)
Total Proved Reserves	557,465	100,675	161,397	15,850	19,767	259,778	43,573	216,206
Total Proved plus Probable	989,287	179,411	293,029	37,766	28,803	450,279	106,506	343,773

Selkirk Report

(Undiscounted)	Revenue	Royalties	Operating Costs	Development Costs	Abandonment and Reclamation Costs	Future Net Revenue Before Income Taxes	Income Taxes	Future Net Revenue After Income Taxes
	(M$)	(M$)	(M$)	(M$)	(M$)	(M$)	(M$)	(M$)
Total Proved Reserves	80,494	9,443	14,012	1,090	828	55,120	15,593	39,527
Total Proved plus Probable	124,733	15,077	23,421	4,490	990	80,755	24,229	56,526

28

Pro Forma

(Undiscounted)	Revenue	Royalties	Operating Costs	Development Costs	Abandonment and Reclamation Costs	Future Net Revenue Before Income Taxes	Income Taxes	Future Net Revenue After Income Taxes
	(M$)	(M$)	(M$)	(M$)	(M$)	(M$)	(M$)	(M$)
Total Proved Reserves	637,959	110,118	175,409	16,940	20,595	314,898	59,166	255,733
Total Proved plus Probable	1,114,020	194,488	316,450	42,256	29,793	531,033	130,735	400,299

Future Net Revenue by Production Group – Forecast Prices and Costs

Administrator Report

	Future Net Revenue Before Income Taxes and Discounted at 10%
	(M$)
Proved
Light and Medium Crude Oil(1)	116,928
Heavy Oil(1)	20,257
Natural Gas(2)	57,185
Proved plus Probable
Light and Medium Crude Oil(1)	174,742
Heavy Oil(1)	22,414
Natural Gas(2)	83,812

Notes:

(1)Including solution gas and other by-products.

(2)Including by-products, but excluding solution gas from oil wells.

Selkirk Report

	Future Net Revenue Before Income Taxes and Discounted at 10%
	(M$)
Proved
Natural Gas(1)	39,172
Proved plus Probable
Natural Gas(1)	49,318

Notes:

(1)Including by-products, but excluding solution gas from oil wells.

29

Pro Forma

	Future Net Revenue Before Income Taxes and Discounted at 10%
	(M$)
Proved
Light and Medium Crude Oil(1)	116,928
Heavy Oil(1)	20,257
Natural Gas(2)	96,357
Proved plus Probable
Light and Medium Crude Oil(1)	174,742
Heavy Oil(1)	22,414
Natural Gas(2)	133,130

Notes:

(1)Including solution gas and other by-products.

(2)Including by-products, but excluding solution gas from oil wells.

Pricing Assumptions – Constant Prices and Costs

Sproule employed the following pricing and exchange rate assumptions as of December 31, 2004 in the Administrator Report and Selkirk Report in estimating reserves data using constant prices and costs.

Edmonton Par Price 40 API	Cromer Medium 29.3 API	AECO - C Spot	B.C. Westcoast Stn. 2	Butanes	Pentanes Plus	Exchange Rate
($/Bbl)	($/Bbl)	($/Mcf)	($/Mcf)	($/Bbl)	($/Bbl)	($US/$Cdn)
46.51	32.10	6.78	6.68	39.78	51.80	0.832

Pricing Assumptions – Forecast Prices and Costs

Sproule employed the following pricing, exchange rate and inflation rate assumptions as of December 31, 2004 in the Administrator Report and Selkirk Reports in estimating reserves data using forecast prices and costs.

	Medium and Light Crude Oil
	WTI Cushing	Edmonton	Cromer	Natural Gas
	Oklahoma	Par Price	Medium	AECO - C	Exchange
	40° API	40° API	29.3° API	Spot	Rate
Year	(US$/Bbl)	($/Bbl)	($/Bbl)	($/Mmbtu)	($US/$Cdn)
2004	41.41	52.91	45.72	6.87	0.77
2005	44.29	51.25	44.53	6.97	0.84
2006	41.60	48.03	41.87	6.66	0.84
2007	37.09	42.64	37.27	6.21	0.84
2008	33.46	38.31	33.43	5.73	0.84
2009	31.48	36.36	31.70	5.37	0.84
2010	32.32	36.91	32.22	5.47	0.84
2011	32.80	37.47	32.75	5.57	0.84
2012	33.30	38.03	33.29	5.67	0.84
2013	33.79	38.61	33.83	5.77	0.84
2014	34.30	39.19	34.38	5.87	0.84
2015	34.82	39.78	34.95	5.98	0.84

Escalated at 1.5% per year thereafter.

30

UNDEVELOPED RESERVES

The following discussion generally describes the basis on which the Trust attributes Proved and Probable Undeveloped Reserves and its anticipated plans for developing those Undeveloped Reserves.

Proved Undeveloped Reserves

Proved undeveloped reserves are generally those reserves related to wells that have been tested and not yet tied-in, wells drilled near the end of the fiscal year or wells further away from gathering systems.  In addition, such reserves may relate to planned infill drilling locations.  The majority of these reserves are planned to be on stream within a two year timeframe.

Probable Undeveloped Reserves

Probable undeveloped reserves are generally those reserves tested or indicated by analogy to be productive, infill drilling locations and lands contiguous to production.  The majority of these reserves are planned to be on stream within a two year timeframe.

SIGNIFICANT FACTORS OR UNCERTAINTIES AFFECTING RESERVES DATA

The process of estimating reserves is complex.  It requires significant judgments and decisions based on available geological, geophysical, engineering, and economic data.  These estimates may change substantially as additional data from ongoing development activities and production performance becomes available and as economic conditions impacting oil and gas prices and costs change.  The reserve estimates contained herein are based on current production forecasts, prices and economic conditions.

As circumstances change and additional data become available, reserve estimates also change.  Estimates made are reviewed and revised, either upward or downward, as warranted by the new information.  Revisions are often required due to changes in well performance, prices, economic conditions and governmental restrictions.

Although every reasonable effort is made to ensure that reserve estimates are accurate, reserve estimation is an inferential science.  As a result, the subjective decisions, new geological or production information and a changing environment may impact these estimates.  Revisions to reserve estimates can arise from changes in year-end oil and gas prices, and reservoir performance.  Such revisions can be either positive or negative.

31

FUTURE DEVELOPMENT COSTS

The table below sets out the total development costs deducted in the estimation in the Administrator Report of future net revenue attributable to proved reserves (using both constant prices and costs and forecast prices and costs) and proved plus probable reserves (using forecast prices and costs only).

	Constant Prices and	Forecast Prices and Costs
	Costs		Proved Plus
	Proved	Proved	Probable
	Reserves	Reserves	Reserves
	(M$)	(M$)	(M$)
2005	12,348	12,357	27,106
2006	2,122	2,175	4,603
2007	911	957	4,142
2008	80	86	1,620
2009	133	146	146
Remaining Years	115	129	149
Total Undiscounted	15,707	15,850	37,766
Total Discounted at 10% per year	14,398	14,508	34,312

The table below sets out the total development costs deducted in the estimation in the Selkirk Report of future net revenue attributable to proved reserves (using both constant prices and costs and forecast prices and costs) and proved plus probable reserves (using forecast prices and costs only).

	Constant Prices and	Forecast Prices and Costs
	Costs		Proved Plus
	Proved	Proved	Probable
	Reserves	Reserves	Reserves
	(M$)	(M$)	(M$)
2005	1,090	1,090	4,490
2006	0.0	0.0	0.0
2007	0.0	0.0	0.0
2008	0.0	0.0	0.0
2009	0.0	0.0	0.0
Remaining Years	0.0	0.0	0.0
Total Undiscounted	1,090	1,090	4,490
Total Discounted at 10% per year	1,079	1,079	4,459

The Trust has three sources of funding available to finance their capital expenditure programs: internally generated cash flow from operations, debt financing when appropriate and new issues of Trust Units, if available on favourable terms.  The Trust expects to fund the above future development costs primarily through internally generated cash-flow and, to a much lesser extent, debt.  The cost of the debt component for funding future development costs is expected to be minimal and to not materially impact the disclosed reserves or future net revenue.

32

OIL AND GAS PROPERTIES

The following is a description of the major oil and natural gas properties in which the Trust has an interest as at the date of this Annual Information Form.

Fort St. John, British Columbia

The Fort St. John properties are primarily located in the Fort St. John area in northeast British Columbia. The principal properties are within a 20 kilometer radius of the city of Fort St. John.  The Trust has an average working interest of 55% in 72,528 gross (40,081 net) acres of land in these areas. The wells located on the properties consist of 56 (24.0 net) producing natural gas wells, 22 (14.0 net) suspended natural gas wells.  The Trust also has 50% and 65% working interests, respectively, in 2 operated compressor stations and 38.44% and 27% working interests, respectively, in a further 2 non-operated compressor stations.

In addition to the above, the Trust is a party to a joint venture agreement with a large U.S. based independent oil and gas company providing for access to 264 (138.0 net) sections of land until April, 2005. The Trust will have access to numerous 3D seismic programs as well as over 500 miles of 2D seismic data.

For the year ended December 31, 2004, 4 (2.4 net) exploration wells and 10 (5.9 net) development wells were drilled in the area resulting in 9 (4.9 net) natural gas wells, 2 (1.5 net) oil wells and 3 (1.9 net) dry and abandoned wells.

Planned exploration and development activity in the Fort St. John area for 2005 includes the drilling of 5 (2.1 net) wells at an estimated total net cost of $1.6 million, recompletion of 6 (3.6 net) wells at an estimated total net cost of $0.45 million and tie-in of 5 (2.7 net) wells at an estimated total net cost of $0.47 million.

In March 2005, the Trust entered into a farmout arrangement with a junior exploration and production company which has committed to drill a minimum of 3 new wells and recomplete an additional 3 wells in the Fort St. John during 2005.  The arrangement covers approximately 13,000 gross undeveloped acres of land, where the Trust will retain an average of 40% of its original interest in each prospect drilled.

Midale, Saskatchewan

The Midale properties are located in southeast Saskatchewan about 50-100 kilometers north and west of Estevan.  The Trust holds an average 73% working interest in this mainly operated area comprised of 76,791 gross (56,011 net) acres.  There are 149 (125.0 net) producing oil wells and 11 (11.0 net) suspended oil wells on the properties.

The Midale area’s main producing assets include portions of the Bryant Midale Pool, Tatagwa Midale Pool, Radville Midale Pool, Midale Frobisher Pool, Innes Frobisher Pool, and the Mansur Red River Pool.  The medium oil (22-29° API) is produced from the Midale and Frobisher beds at 1,200 to 1,400 meters depth.

Substantially all of the production in which the Trust has an interest is pipelined to company owned central facilities including oil, gas and water separation and treating equipment, crude oil pipeline connection, and salt water disposal facilities. Some facilities are connected to solution gas gathering facilities resulting in small quantities of solution gas sales. Some production is produced to single well batteries where oil and water are separated and trucked to company owned facilities for processing and sale.

For the year ended December 31, 2004, 3 (1.5 net) exploration wells and 9 (8.7 net) development wells were drilled in the area resulting in 12 (10.2 net) oil wells.

Planned exploration and development activity in the Midale area for 2005 includes the drilling of 11 (7.3 net) wells at an estimated total net cost of $4.3 million.

33

Queensdale/Gainsborough, Saskatchewan

The Queensdale/Gainsborough properties are located in southeast Saskatchewan about 100-150 kilometers north and east of Estevan.  The Trust holds an average 78% working interest in this mainly operated area comprised 23,539 gross (18,264 net) acres.  There are 192 (130.0 net) producing oil wells and 85 (48.0 net) suspended oil wells on the properties.

This area’s main producing assets include portions of the Queensdale Frobisher-Alida Pool, Wauchope Tilston Pool, Glen Ewen Frobisher and Midale Pool, Gainsborough East Alida Pool, Oakley Frobisher Pool, Silverton Frobisher-Alida Pool, Souris Flats Frobisher and Midale Pool and the Alida West Alida Pool.  The light oil (30-38° API) is produced from the Frobisher-Alida beds at 1,000 to 1,400 meters depth.

Substantially all of the production in which the Trust has an interest is pipelined to company owned central facilities including oil, gas and water separation and treating equipment, crude oil pipeline connection, and salt water disposal facilities. Some facilities are connected to solution gas gathering facilities resulting in small quantities of solution gas sales. Some company production is produced to single well batteries where oil and water are separated and trucked to company owned facilities for processing and sale.

For the year ended December 31, 2004, 2 (1.7 net) exploration wells and 8 (6.7 net) development wells were drilled in the area resulting in 7 (5.7 net) oil wells and 3 (2.7 net) dry and abandoned wells.

Planned exploration and development activity in the Queensdale/Gainsborough area for 2005 includes the drilling of 5 (4.5 net) wells at an estimated total net cost of $2.5 million.

Heward/Melrose, Saskatchewan

The Heward/Melrose properties are located in southeast Saskatchewan about 100 kilometers north of Estevan. The Trust holds an average working interest of 67% in 14,942 gross (10,046 net) acres in this area.  There are 82 (52.0 net) producing oil wells and 5 (5.0 net) suspended oil wells on the properties.

This area’s main producing assets include portions of the Heward Frobisher-Alida Pool, Hartaven Alida Pool, Melrose Frobisher-Alida Pool, Star Valley Frobisher-Alida Pool, Handsworth Alida Pool and Pheasant Rump Alida Pool.  The medium to light oil (26-32° API) is produced from the Frobisher-Alida beds at 1,000 to 1,100 meters depth.

Substantially all of the production in which the Trust has an interest is pipelined to company owned central facilities including oil, gas and water separation and treating equipment, crude oil pipeline connection, and salt water disposal facilities. Some facilities are connected to solution gas gathering facilities resulting in small quantities of solution gas sales as noted. Some company production is produced to single well batteries where oil and water are separated and trucked to company owned facilities for processing and sale.

For the year ended December 31, 2004, 1 (1 net) exploration well and 9 (5.3 net) development wells were drilled in the area resulting in 9 (5.3 net) oil wells and 1 (1 net) dry and abandoned well.

Planned exploration and development activity in the Heward/Melrose area for 2005 includes the drilling of 7 (3.6 net) wells at an estimated total net cost of $2.3 million.

Leo/Stettler, Alberta

The Leo/Stettler property is located approximately 130 kilometers northeast of Calgary, Alberta.  The Trust has an average working interest of 68% in 35,172 (24,034 net) acres of land in this area.  There are 41 (32.0 net) producing gas wells and 11 (7.0 net) shut-in/suspended gas wells on the property.  The facilities on the property in which the Trust has an interest consist of 8 field compressor stations.

34

For the year ended December 31, 2004, 1 (1 net) exploration well and 6 (6 net) development wells were drilled in the area resulting in 4 (4 net) natural gas wells, 2 (2 net) suspended gas wells and 1 (1 net) dry and abandoned well.  Planned exploration and development activity in the Leo/Stettler area for 2005 includes the drilling of 3 (3 net) wells at an estimated total net cost of $0.6 million.

Metiskow, Alberta

The Metiskow property is located approximately 270 kilometers northeast of Calgary, Alberta.  The Trust has an average working interest of 90% in 10,040 (8,041 net) acres of land in this area.  There are 3 (2.5 net) producing gas wells, 23 (20.0 net) producing oil wells, 8 (7.0 net) injection wells and 19 (17.0 net) net shut-in/suspended oil wells on the property.  The facilities on the property in which the Trust has an interest consist of a multi-well oil battery and one single well oil battery.

For the year ended December 31, 2004, 3 (3 net) exploration wells and 5 (4.5 net) development wells were drilled in the area resulting in 1 (0.5 net) natural gas well, 5 (5 net) oil wells, 1 (1 net) dry and abandoned well and 1 (1 net) suspended oil well.

Planned exploration and development activity in the Metiskow area for 2005 includes the drilling of 6 (6 net) wells at an estimated total net cost of $2.3 million.

Sibbald/Acadia, Alberta

The Sibbald/Acadia property is located approximately 260 kilometers east of Calgary, Alberta.  The Trust has an average working interest of 67% in 10,250 (6,853 net) acres of land in this area.  There are 2 (1.3 net) producing gas wells, 35 (34.0 net) producing oil wells, 24 (23.0 net) injection wells and 25 (23.0 net) net shut-in/suspended oil wells on the property.  The facilities on the property in which the Trust an interest consist of 2 multi-well oil batteries and one single well oil battery.

For the year ended December 31, 2004, 7 (7 net) development wells were drilled in the area resulting in 5 (5 net) oil wells and 2 (2 net) suspended oil wells.

Planned exploration and development activity in the Sibbal/Acadia area for 2005 includes the drilling of 1 (1 net) well at an estimated total net cost of $0.4 million.

Selkirk Properties

The Selkirk Properties are located in the Deep Basin area of Alberta, approximately 75 kilometers southwest of the city of Grand Prairie.  Production is primarily from the Chinook formation at Red Rock, with minor volumes from Elmworth and Wapiti.  The Trust holds an average working interest of 63% in 19,039 gross (12,070 net) acres of land in the Deep Basin.  At Red Rock, the Trust’s interest is limited to production from certain wellbores from the Chinook Formation.  The Trust has an interest in 41 gross (16.2 net) producing natural gas wells and 10 gross (2.8 net) standing or suspended natural gas wells in this area.

Production from this area is processed through third party gas plants, with the Trust holding a 57.2% net working interest in a 400 HP booster compressor located at Wapiti.

For the year ended December 31, 2004, 5 (1.1 net) exploration wells and 8 (1.9 net) development wells were drilled in the area resulting in 13 (3.0 net) natural gas wells.

Planned exploration and development activity for 2005 includes the drilling of 3 (0.8 net) wells at an estimated total net cost of $1.1 million.

35

US Properties

The US properties are located in eastern Montana and southwest North Dakota about 200-300 kilometers south of Estevan. The Trust has working interests ranging from 19% to 100%, in 57,938 gross (42,937 net) acres.  The Trust has a working interest in 22 gross (10.5 net) producing wells in this area.

This area’s main producing assets include portions of the Brush Mountain Ratcliffe Pool, Tracy Mountain Tyler Pool and Davis Creek Madison Pool.  The light oil (35-42° API) is produced from the Mississippian Madison and Pennsylvanian Tyler beds at 2,500 to 3000 meters depth.

Substantially all of the production in which the Trust has an interest is produced to single well batteries where oil, water and gas are separated; gas is consumed as wellsite fuel or flared, oil and water are trucked for sale and disposal respectively.

Planned exploration and development activity for 2005 includes the drilling of 2 (1.0 net) wells at an estimated total net cost of $1.6 million.

OIL AND GAS WELLS

The following table sets forth the number and status of wells, effective December 31, 2004, in which the Trust has a working interest, presented as if the Arrangement and the acquisition of Selkirk had occurred at that date.

	Producing Wells				Non-Producing Wells
	Oil		Natural Gas		Oil		Natural Gas
	Gross	Net	Gross	Net	Gross	Net	Gross	Net
Alberta	69	56	47	33	44	40	13	9
British Columbia	6	2	60	26	2	1	22	14
Saskatchewan	437	315	—	—	101	65	1	—
U.S.A.	25	12	—	—	1	1	—	—
Total	537	385	107	59	148	107	36	23

PROPERTIES WITH NO ATTRIBUTED RESERVES

The following table summarizes the gross and net acres of unproved properties, effective December 31, 2004, in which the Trust has an interest and also the number of net acres for which the Trust’s rights to explore, develop or exploit will, absent further action, expire within one year, presented as if the Arrangement and the acquisition of Selkirk had occurred at December 31, 2004.

	Gross Acres	NetAcres	Net Acres Expiring Within One Year
Alberta	88,392	51,670	10,884
Saskatchewan	87,433	70,012	13,831
British Columbia	41,830	24,584	2,107
USA	49,626	38,756	7,807
Total	267,281	185,022	34,629

36

DRILLING ACTIVITY

The following table sets forth the gross and net exploratory and development wells on the Trust’s properties during the year ended December 31, 2004.

	Exploratory Wells		Development Wells
	Gross	Net	Gross	Net
Light and Medium Oil	5	3.5	30	24.7
Heavy Oil	—	—	7	7.0
Natural Gas	8	4.1	22	12.3
Dry	6	4.1	3	2.5
Total:	19	11.7	62	46.5

ADDITIONAL INFORMATION CONCERNING ABANDONMENT AND RECLAMATION COSTS

The Trust typically estimates well abandonment costs area by area.  Such costs are included in the Administrator Report and Selkirk Report as deductions in arriving at future net revenue.

The expected total abandonment costs, net of estimated salvage value, included in the Administrator Report for 560 net wells under the proved reserves category is $16.7 million undiscounted ($7.1 million discounted at 10%), of which a total of $2.2 million is estimated to be incurred in 2005, 2006 and 2007.  This estimate does not include expected reclamation costs for surface leases of $5.6 million undiscounted ($2.4 million discounted at 10%).

The expected total abandonment costs, net of estimated salvage value, included in the Selkirk Report for 43 net wells under the proved reserves category is $0.7 million undiscounted ($0.3 million discounted at 10%), none of which are estimated to be incurred in 2005, 2006 and 2007.  This estimate does not include expected reclamation costs for surface leases of $0.6 million undiscounted ($0.3 million discounted at 10%).

The Trust will be liable for its share of ongoing environmental obligations and for the ultimate reclamation of the properties held by it upon abandonment.  Ongoing environmental obligations are expected to be funded out of cash flow.

TAX HORIZON

The Trust will not be taxable provided all income is otherwise paid or payable to Unitholders every year.

COSTS INCURRED

The following table summarizes capital expenditures (net of incentives and net of certain proceeds and including capitalized general and administrative expenses) incurred for the year ended December 31, 2004 with respect to the Trust’s properties.

	Property Acquisition Costs
	Proved Properties	Unproved Properties	Exploration Costs	Development Costs
Total (M$)	10,737	4,419	54,322	15,124

37

PRODUCTION ESTIMATES

Administrator Report

The following table discloses for each product type the total volume of production estimated by Sproule in the Administrator Report for 2005 in the estimates of future net revenue from proved reserves disclosed above.

	Light and Medium Crude Oil	Heavy Oil	Natural Gas	Natural Gas Liquids	BOE	%
	(Bbls/d)	(Bbls/d)	(Mcf/d)	(Bbls/d)	(BOE/d)
Alberta	299	711	3,659	63	1,683	21
Saskatchewan	4,421	0	458	0	4,497	56
British Columbia	72	0	7,958	32	1,430	18
U.S.A.	385	0	41	0	392	5
Estimated Total Production	5,177	711	12,116	95	8,002	100

Selkirk Report

The following table discloses for each product type the total volume of production estimated by Sproule in the Selkirk Report for 2005 in the estimates of future net revenue from proved reserves disclosed above.

	Light and Medium Crude Oil	Natural Gas	Natural Gas Liquids	BOE	%
	(Bbls/d)	(Mcf/d)	(Bbls/d)	(BOE/d)
Alberta	0	4,924	458	1,279	100

PRODUCTION HISTORY

The following table discloses, on a quarterly basis for the year ended December 31, 2004, certain information in respect of production, product prices received, royalties paid, operating expenses and resulting netback for the Trust’s properties.

Average Daily Production Volume

	Three Months Ended
	Mar. 31, 2004	June 30, 2004	Sept. 30, 2004	Dec. 31, 2004	Total
Natural gas (Mcf/d)	18,027.0	17,952.2	16,639.8	15,824.1	17,110.8
Light and Medium Crude Oil (Bbl/d)	5,871.6	5,744.7	6,204.6	6,374.0	6,048.7
NGL (Bbl/d)	547.0	425.8	568.9	475.3	504.3
Total (BOE/d)	9,423.1	9,162.5	9,546.8	9,486.7	9,404.8

Prices Received, Royalties Paid, Production Costs and Netback – Light and Medium Crude Oiland NGLs

	Three Months Ended
($ per Bbl)	Mar. 31, 2004	June 30, 2004	Sept. 30, 2004	Dec. 31, 2004	Total
Prices Received	37.58	40.85	40.19	36.74	38.81
Royalties Paid	7.81	9.31	8.55	8.47	8.53
Production Costs	5.62	6.14	6.34	5.86	5.99
Netback(1)	24.15	25.40	25.30	22.41	24.29

38

Note:

(1)Netback is calculated by deducting royalties paid and production costs from prices received.

Prices Received, Royalties Paid, Production Costs and Netback – Natural Gas

	Three Months Ended
($ per Mcf)	Mar. 31, 2004	June 30, 2004	Sept. 30, 2004	Dec. 31, 2004	Total
Prices Received	6.28	6.97	5.78	6.45	6.38
Royalties Paid	1.62	1.65	1.41	1.45	1.54
Production Costs	0.71	0.87	1.16	1.74	1.10
Netback(1)	3.95	4.45	3.21	3.26	3.74

Note:

(1)Netback is calculated by deducting royalties paid and production costs from prices received.

Production Volume by Field

The following table indicates the average daily production from the important fields comprising the Trust’s properties for the year ended December 31, 2004.

Field	Light and MediumCrude Oil	Natural Gas	Natural Gas Liquids	BOE	%
	(Bbls/d)	(Mcf/d)	(Bbls/d)	(BOE/d)
Fort St. John	59.8	7,370.0	26.5	1,314	14.0
Midale	1,624.0	134.9	—	1,647	17.5
Queensdale/Gainsborough	1,010.5	149.0	—	1,035	11.0
Heward/Melrose	1,675.0	50.0	—	1,683	17.9
Metiskow	243.0	190.0	—	275	2.9
Sibbald	619.0	117.0	—	639	6.8
Selkirk Properties	—	4,937.9	404.0	1,227	13.0
Total	5,231.3	12,948.8	430.5	7,820	83.1

ADDITIONAL INFORMATION CONCERNING THE TRUST

Trust Units

An unlimited number of Trust Units may be created and issued pursuant to the Trust Indenture.  Each Trust Unit will entitle the holder thereof to one vote at any meeting of the holders of Trust Units and represents an equal fractional undivided beneficial interest in any distribution from the Trust (whether of net income, net realized capital gains or other amounts) and in any net assets of the Trust in the event of termination or winding–up of the Trust.  All Trust Units outstanding from time to time shall be entitled to an equal share of any distributions by the Trust, and in the event of termination or winding-up of the Trust, in any net assets of the Trust.  All Trust Units shall rank among themselves equally and rateably without discrimination, preference or priority.  Each Trust Unit is transferable subject to compliance with applicable securities laws, is not subject to any conversion or pre-emptive rights and entitles the holder thereof to require the Trust to redeem any or all of the Trust Units held by such holder (see ”Redemption Right” below).

The Trust Units do not represent a traditional investment and should not be viewed by investors as “shares” in the Trust.  As holders of Trust Units in the Trust, the Trust Unitholders will not have the statutory rights normally associated with ownership of shares of a corporation including, for example, the right to bring “oppression” or “derivative” actions.  The price per Trust Unit will be a function of anticipated distributable income from the Administrator, the NPI and Subtrust and the ability of the Administrator and Subtrust to effect long term growth in the value of the Trust.  The market price of the Trust Units will be sensitive to a variety of market conditions

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including, but not limited to, interest rates, commodity prices and the ability of the Trust to acquire additional assets. Changes in market conditions may adversely affect the trading price of the Trust Units.

The Trust Units are not “deposits” within the meaning of the Canada Deposit Insurance Corporation Act (Canada) and are not insured under the provisions of that Act or any other legislation.  Furthermore, the Trust is not a trust company and, accordingly, is not registered under any trust and loan company legislation as it does not carry on or intend to carry on the business of a trust company.

Special Voting Units

In order to allow the Trust flexibility in pursuing corporate acquisitions, the Trust Indenture allows for the creation of Special Voting Units which will enable the Trust to provide voting rights to holders of Exchangeable Shares and, in the future, to holders of other exchangeable shares that may be issued by the Administrator or other subsidiaries of the Trust in connection with other exchangeable share transactions.

An unlimited number of Special Voting Units may be created and issued pursuant to the Trust Indenture.  Holders of Special Voting Units shall not be entitled to any distributions of any nature whatsoever from the Trust and shall be entitled to such number of votes at meetings of Trust Unitholders as may be prescribed by the board of directors of the Administrator in the resolution authorizing the issuance of any Special Voting Units.  Except for the right to vote at meetings of the Trust Unitholders, the Special Voting Units shall not confer upon the holders thereof any other rights.

Under the terms of the Voting and Exchange Trust Agreement, the Trust issued a Special Voting Unit to the Voting and Exchange Trust Agreement Trustee for the benefit of every person who received Exchangeable Shares pursuant to the Arrangement.  See “Voting and Exchange Trust Agreement - Voting Rights” below.

Trust Unitholder Limited Liability

The Trust Indenture provides that no Trust Unitholder will be subject to any liability in connection with the Trust or its obligations and affairs and, in the event that a court determines Trust Unitholders are subject to any such liabilities, the liabilities will be enforceable only against, and will be satisfied only out of the Trust’s assets.

If any portion or all of the Trust’s assets should be distributed or declared to be distributable to Unitholders contrary to the provisions of any subordination agreement (each a “Subordination Agreement”) between the Trust and the persons entitled to enforce any of the indebtedness of the Administrator, other than the Trust, or contrary to the terms of the Administrator Notes or the subordination provisions of the Administrator Note Indenture, then the persons entitled to enforce such Subordination Agreements or subordination provisions shall be entitled to pursue whatever remedies may be available to them to enforce such Subordination Agreements or provisions and the limitations described above shall not apply to any judgment rendered in respect of a distribution made contrary to such Subordination Agreements or provisions, provided that the liability of a Unitholder in respect of any such judgment shall be limited to the amount of such contrary distribution, and no Unitholder shall have the right to enforce any distribution contrary to such Subordination Agreements or provisions

The Trust Indenture provides that all contracts signed by or on behalf of the Trust must contain a provision to the effect that such obligation will not be binding upon Trust Unitholders personally. Personal liability may also arise in respect of claims against the Trust that do not arise under contracts, including claims in tort, claims for taxes and possibly certain other statutory liabilities. The possibility of any personal liability of this nature arising is considered unlikely.

The operations of the Trust will be conducted, upon the advice of counsel, in such a way and in such jurisdictions as to avoid as far as possible any material risk of liability on the Trust Unitholders for claims against the Trust. In addition, the Income Trust Liability Act (Alberta) was proclaimed in force in Alberta on June 30, 2004. The Income Trust Liability Act (Alberta) provides that the beneficiary of a trust that is (a) created by a trust instrument governed

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by the laws of Alberta, and (b) a reporting issuer as defined in the Securities Act (Alberta), is not liable as a beneficiary for any act, default, obligation or liability of the trustee.

Issuance of Trust Units

The Trust Indenture provides that Trust Units, including rights, warrants and other securities to purchase, to convert into or to exchange into Trust Units, may be created, issued, sold and delivered on such terms and conditions and at such times as the Trustee, upon the recommendation of the board of directors of the Administrator, may determine.

The Trust Indenture also provides that the Administrator may authorize the creation and issuance of debentures, notes and other evidences of indebtedness of the Trust which debentures, notes or other evidences of indebtedness may be created and issued from time to time on such terms and conditions to such persons and for such consideration as the Administrator may determine.

Cash Distributions

The Trustee may declare payable to the Trust Unitholders all or any part of the net income of the Trust, including income earned from interest income on the Administrator Notes, repayments of principal on the Administrator Notes, income generated under the NPI Agreement and income from any dividends paid on the common shares of the Administrator, less all expenses and liabilities of the Trust which have been incurred or may reasonably be expected to be incurred and are chargeable to the net income of the Trust.

Redemption Right

Trust Units are redeemable at any time on demand by the holders thereof upon delivery to the Trust of the certificate or certificates representing such Trust Units, accompanied by a duly completed and properly executed notice requiring redemption.  Upon receipt of the notice to redeem Trust Units by the Trust, the holder thereof shall only be entitled to receive a price per Trust Unit (the “Market Redemption Price”) equal to the lesser of: (i) 90 percent of the market price (as calculated pursuant to the Trust Indenture) of the Trust Units on the principal market on which the Trust Units are quoted for trading during the 10 trading day period commencing immediately prior to the date on which the Trust Units are tendered to the Trust for redemption, unless the Trust Units are tendered for redemption before the Trust Units have been quoted for trading for 10 trading days following listing, in which case the 10 trading period shall commence on the date of such listing; and (ii) the closing market price on the principal market on which the Trust Units are quoted for trading on the date that the Trust Units are so tendered for redemption.

The Market Redemption Price payable by the Trust in respect of any Trust Units surrendered for redemption during any calendar month shall be satisfied by way of a cash payment on the last day of the following month.  The entitlement of Trust Unitholders to receive cash upon the redemption of their Trust Units is subject to the limitation that the total amount payable by the Trust in respect of such Trust Units and all other Trust Units tendered for redemption in the same calendar month and in any preceding calendar month during the same year shall not exceed $50,000; provided that the Trust may, in its sole discretion, waive such limitation in respect of any calendar month. If this limitation is not so waived, the Market Redemption Price payable by the Trust in respect of Trust Units tendered for redemption in such calendar month shall be paid on the last day of the following month by the Trust either distributing promissory notes, with the terms provided for in the Trust Indenture, or other property of the Trust having an aggregate principal amount or value equal to the aggregate Market Redemption Price of the Trust Units tendered for redemption. In the case of any Unitholder whose Trust Units are to be redeemed and which is a trust or plan governed by a registered retirement savings plan, registered retirement income fund, registered education savings plan or registered pension plan (collectively, a “Plan”), it shall be entitled to elect, either in the notice requiring the Trust to redeem the Trust Units or in another instrument delivered to the Trust any time prior to payment of the in specie Market Redemption Price, to request that the Trust make payment by the distribution of property that would be a “qualified investment” to the Plan within the meaning of the Tax Act.

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If at the time Trust Units are tendered for redemption by a Trust Unitholder, the outstanding Trust Units are not listed for trading on the TSX and are not traded or quoted on any other stock exchange or market which the Administrator considers, in its sole discretion, provides representative fair market value price for the Trust Units or trading of the outstanding Trust Units is suspended or halted on any stock exchange on which the Trust Units are listed for trading or, if not so listed, on any market on which the Trust Units are quoted for trading, on the date such Trust Units are tendered for redemption or for more than five trading days during the 10 trading day period, commencing immediately after the date such Trust Units were tendered for redemption then such Trust Unitholder shall, instead of the Market Redemption Price, be entitled to receive a price per Trust Unit (the “Appraised Redemption Price”) equal to 90 percent of the fair market value thereof as determined by the Administrator as at the date on which such Trust Units were tendered for redemption.  The aggregate Appraised Redemption Price payable by the Trust in respect of Trust Units tendered for redemption in any calendar month shall be paid on the last day of the third following month as described above.

It is anticipated that this redemption right will not be the primary mechanism for holders of Trust Units to dispose of their Trust Units.  Promissory notes which may be distributed in specie to Trust Unitholders in connection with a redemption will not be listed on any stock exchange and no market is expected to develop in such notes. Such notes may not be qualified investments for trusts governed by registered retirement savings plans, registered retirement income funds, deferred profit sharing plans and registered education savings plans.

Non–Resident Trust Unitholders

It is in the best interest of Unitholders that the Trust qualify as a “unit trust” and a “mutual fund trust” under the Tax Act.  Certain provisions of the Tax Act require that the Trust not be established nor maintained primarily for the benefit of Non-Residents. Under certain proposed amendments to the Tax Act, the Trust will cease to qualify as mutual fund trust at the time Trust Units having more than 50% of the fair market value of all issued Trust Units are held by one or more Non-Residents.

Accordingly, in order to comply with such provisions, the Trust Indenture contains restrictions on the ownership of Trust Units by Trust Unitholders who are Non–Residents.  The Trust Indenture provides that at no time may Non-Residents be the beneficial owners of more than 49 percent of the Trust Units then outstanding and the Trustee shall inform the transfer agent of the Trust Units (the “Transfer Agent”) of this restriction.  To monitor compliance with this requirement, the Administrator may require the Trustee or Transfer Agent to obtain declarations as to the jurisdictions in which beneficial owners of Trust Units are resident.

If the Administrator becomes aware that the beneficial owners of 40 percent or more of the Trust Units then outstanding are, or may be, Non-Residents or that such a situation is imminent, the Administrator will advise the Trustee and may make a public announcement thereof and may require the Trustee to refuse to accept a subscription for Trust Units from or issue or register a transfer of Trust Units to a person unless the person provides a declaration, in form and content specified by the Administrator, that the person is not a Non-Resident.  The Administrator may require the Trustee to refuse to make payment of any Distributable Cash of the Trust to a person until the person provides a declaration with respect to that person’s residency.

If, notwithstanding the foregoing, the Administrator determines that 49 percent or more of the Trust Units are held by Non-Residents, the Administrator may require the Trustee, in the manner specified by the Administrator, to send a notice to Non-Resident holders of Trust Units, as applicable, chosen in inverse order to the order of acquisition or registration or in such other manner as the Administrator may consider equitable and practicable, requiring such Non-Resident holders to sell their Trust Units or a specified portion thereof within a specified period of not less than 60 days.  If the Unitholders receiving such notice have not sold the specified number of Trust Units or provided the Trustee and the Administrator with satisfactory evidence that they are not Non-Residents within such period, the Administrator may require the Trustee on behalf of such Unitholders to sell such Trust Units and, in the interim, shall suspend the voting and distribution rights attached to such Trust Units. Upon such sale the Unitholders thereby affected shall cease to be holders of Trust Units and their rights shall be limited to receiving the net proceeds of sale of such Trust Units.  Notwithstanding the foregoing, the Trustee, upon direction of the Administrator, may take such

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other action as specified by the Administrator to ensure compliance with the Tax Act.

No liability shall accrue to the Trust or the Trustee if the Trust Units of Non-Resident Unitholders are sold at a loss to such Unitholder.

Meetings of Trust Unitholders

The Trust Indenture provides that meetings of Trust Unitholders must be called and held for, among other matters, the election or removal of the Trustee, the appointment or removal of the auditors of the Trust, the approval of amendments to the Trust Indenture (except as described under “Amendments to the Trust Indenture”), the sale of the property of the Trust as an entirety or substantially as an entirety, and the commencement of winding–up the affairs of the Trust.  Meetings of Trust Unitholders will be called and held annually for, among other things, the election of the directors of the Administrator and the appointment of the auditors of the Trust.

A meeting of Trust Unitholders may be convened at any time and for any purpose by the Trustee and must be convened, except in certain circumstances, if requisitioned by the holders of not less than 20 percent of the Trust Units then outstanding by a written requisition.  A requisition must, among other things, state in reasonable detail the business purpose for which the meeting is to be called.

Trust Unitholders may attend and vote at all meetings of Trust Unitholders either in person or by proxy and a proxyholder need not be a Trust Unitholder.  Two persons present in person or represented by proxy and representing in the aggregate at least 5 percent of the votes attaching to all outstanding Trust Units shall constitute a quorum for the transaction of business at all such meetings.  For the purposes of determining such quorum, the holders of any issued Special Voting Units who are present at the meeting shall be regarded as representing outstanding Trust Units equivalent in number to the votes attaching to such Special Voting Units.

The Trust Indenture contains provisions as to the notice required and other procedures with respect to the calling and holding of meetings of Trust Unitholders in accordance with the requirements of applicable laws.

Takeover Bids

The Trust Indenture contains provisions to the effect that if a takeover 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 takeover bid by or on behalf of the offeror or associates or affiliates of the offeror) are taken up and paid for by the offeror, the offeror will be entitled to acquire the Trust Units held by Trust Unitholders who did not accept the takeover bid on the terms offered by the offeror.

The Trustee

Olympia Trust Company is the initial trustee of the Trust.  The Trustee is responsible for, among other things, accepting subscriptions for Trust Units and issuing Trust Units pursuant thereto and maintaining the books and records of the Trust and providing timely reports to holders of Trust Units.  The Trust Indenture provides that the Trustee shall exercise its powers and carry out its functions thereunder as Trustee honestly, in good faith and in the best interests of the Trust and the Trust Unitholders and, in connection therewith, shall exercise that degree of care, diligence and skill that a reasonably prudent trustee would exercise in comparable circumstances.

The initial term of the Trustee’s appointment is until the third annual meeting of Trust Unitholders.  The Trust Unitholders shall, at the third annual meeting of the Trust Unitholders, re-appoint, or appoint a successor to the Trustee for an additional three year term, and thereafter, the Trust Unitholders shall reappoint or appoint a successor to the Trustee at the annual meeting of Trust Unitholders three years following the reappointment or appointment of the successor to the Trust.  The Trustee may also be removed by a Special Resolution of the Trust Unitholders.  Such resignation or removal becomes effective upon the acceptance or appointment of a successor trustee.

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Liability of the Trustee

The Trustee, its directors, officers, employees, shareholders and agents shall not be liable to any Trust Unitholder or any other person, in tort, contract or otherwise, in connection with any matter pertaining to the Trust or the property of the Trust, arising from the exercise by the Trustee of any powers, authorities or discretion conferred under the Trust Indenture, including, without limitation, entering into the Administration Agreement and relying on the Administrator thereunder, any action taken or not taken in good faith in reliance on any documents that are, prima facie, properly executed, any depreciation of, or loss to, the property of the Trust incurred by reason of the sale of any asset, any inaccuracy in any evaluation provided by any appropriately qualified person, any reliance on any such evaluation, any action or failure to act of the Administrator, or any other person to whom the Trustee has, with the consent of the Administrator, delegated any of its duties thereunder, or any other action or failure to act (including failure to compel in any way any former trustee to redress any breach of trust or any failure by the Administrator to perform its duties under or delegated to it under the Trust Indenture or any other contract), including anything done or permitted to be done pursuant to, or any error or omission relating to, the rights, powers, responsibilities and duties conferred upon, granted, allocated and delegated to the Administrator thereunder or under the Administration Agreement, or the act of agreeing to the conferring upon, granting, allocating and delegating any such rights, powers, responsibilities and duties to the Administrator in accordance with the terms of the Trust Indenture or under the Administration Agreement, unless and to the extent such liabilities arise out of the gross negligence, wilful misconduct or fraud of the Trustee or any of its directors, officers, employees, shareholders, or agents.  If the Trustee has retained an appropriate expert or adviser or legal counsel with respect to any matter connected with its duties under the Trust Indenture or any other contract, the Trustee may act or refuse to act based on the advice of such expert, adviser or legal counsel, and notwithstanding any other provision of the Trust Indenture, the Trustee shall not be liable for and shall be fully protected from any loss or liability occasioned by any action or refusal to act based on the advice of any such expert, adviser or legal counsel.  In the exercise of the powers, authorities or discretion conferred upon the Trustee under the Trust Indenture, the Trustee is and shall be conclusively deemed to be acting as Trustee of the assets of the Trust and shall not be subject to any personal liability for any debts, liabilities, obligations, claims, demands, judgments, costs, charges or expenses against or with respect to the Trust or the property of the Trust. In addition, the Trust Indenture contains other customary indemnities and provisions limiting the liability of the Trustee.

Amendments to the Trust Indenture

The Trust Indenture may be amended or altered from time to time by Special Resolution.

The Trustee and the Administrator may, without the approval of any of the Trust Unitholders, amend the Trust Indenture for the purpose of:

(a)ensuring the Trust’s continuing compliance with applicable laws or requirements of any governmental agency or authority of Canada or of any province;

(b)ensuring that the Trust will satisfy the provisions of each of subsections 108(2) and 132(6) of the Tax Act as from time to time amended or replaced and will not be foreign property for the purposes of the Tax Act;

(c)making amendments which, in the opinion of the Trustee, are necessary or desirable as a result of changes in taxation laws or policies of any governmental authority having jurisdiction over the Trustee or the Trust, including to ensure the Trust’s continued compliance with proposed amendments to subsection 132(7) of the Tax Act or any legislative amendments to subsection 132(7) of the Tax Act as finally enacted;

(d)ensuring that such additional protection is provided for the interests of Trust Unitholders as the Trustee may consider expedient;

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(e)removing or curing any conflicts or inconsistencies between the provisions of the Trust Indenture or any supplemental indenture, the Administration Agreement and any other agreement of the Trust or any offering document pursuant to which securities of the Trust are issued with respect to the Trust, or any applicable law or regulation of any jurisdiction, provided that in the opinion of the Trustee the rights of the Trustee and of the Trust Unitholders are not prejudiced thereby;

(f)providing for the electronic delivery by the Trust to Trust Unitholders of documents relating to the Trust (including annual and quarterly reports, including financial statements, notices of Trust Unitholder meetings and information circulars and proxy related materials) at such time as applicable securities laws have been amended to permit such electronic delivery in place of normal delivery procedures, provided that such amendments to the Trust Indenture are not contrary to or do not conflict with such laws;

(g)curing, correcting or rectifying any ambiguities, defective or inconsistent provisions, errors, mistakes or omissions, provided that in the opinion of the Trustee the rights of the Trustee and of the Trust Unitholders are not prejudiced thereby;

(h)making any modification in the form of Trust Unit certificates to conform with the provisions of the Trust Indenture, or any other modifications, provided the rights of the Trustee and of the Trust Unitholders are not prejudiced thereby; and

(i)changing the situs of the Trust or the governing laws of the Trust which, in the opinion of the Trustee, are necessary or desirable in order to provide Trust Unitholders with the benefit of any legislation limiting their liability.

Termination of the Trust

The Trust Unitholders may vote to terminate the Trust at any meeting of the Trust Unitholders duly called for that purpose, subject to the following: (a) a vote may only be held if requested in writing by the holders of not less than 20 percent of the outstanding Trust Units; (b) a quorum of 50 percent of the issued and outstanding Trust Units is present in person or by proxy; and (c) the termination must be approved by Special Resolution of Trust Unitholders.

Unless the Trust is earlier terminated or extended by vote of the Trust Unitholders, the Trustee shall commence to wind-up the affairs of the Trust on December 31, 2099.  In the event that the Trust is wound–up, the Trustee will sell and convert into money the property of the Trust in one transaction or in a series of transactions at public or private sale and do all other acts appropriate to liquidate the property of the Trust, and shall in all respects act in accordance with the directions, if any, of the Trust Unitholders in respect of termination authorized pursuant to the Special Resolution authorizing the termination of the Trust.  After paying, retiring or discharging or making provision for the payment, retirement or discharge of all known liabilities and obligations of the Trust and providing for indemnity against any other outstanding liabilities and obligations, the Trustee shall distribute the remaining part of the proceeds of the sale of the assets together with any cash forming part of the property of the Trust pro rata among the Trust Unitholders.

Exercise of Voting Rights Attached to Shares of the Administrator

Except in accordance with an Ordinary Resolution adopted at an annual meeting of Trust Unitholders, the Trust Indenture prohibits the Trustee from voting the shares of the Administrator with respect to: (i) the election of directors of the Administrator; (ii) the appointment of auditors of the Administrator; or (iii) the approval of the Administrator’s financial statements.

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Without the approval of the Trust Unitholders by Special Resolution at a meeting of Trust Unitholders called for that purpose, the Trustee is also prohibited from voting the shares to authorize:

(a)any sale, lease or other disposition of, or any interest in, all or substantially all of the assets of the Administrator, except in conjunction with an internal reorganization of the direct or indirect assets of the Administrator as a result of which either the Administrator or the Trust has the same interest, whether direct or indirect, in the assets as the interest, whether direct or indirect, that it had prior to the reorganization;

(b)any statutory amalgamation of the Administrator with any other corporation, or any amalgamation, merger or transaction, as the case may be, of the Administrator with any other entity, except in conjunction with an internal reorganization as referred to in paragraph (a) above;

(c)any statutory arrangement involving the Administrator except in conjunction with an internal reorganization as referred to in paragraph (a) above;

(d)any amendment to the articles of the Administrator to increase or decrease the minimum or maximum number of directors; or

(e)any material amendment to the articles of the Administrator to change the authorized share capital or amend the rights, privileges, restrictions and conditions attaching to any class of the Administrator’s shares in a manner which may be prejudicial to the Trust other than the creation of additional classes or series of exchangeable shares.

THE ADMINISTRATOR SHARE CAPITAL

The Administrator is authorized to issue an unlimited number of common shares and an unlimited number of exchangeable shares issuable in series, of which an unlimited number of Exchangeable Shares have been designated.  The Trust is the sole holder of the issued and outstanding common shares of The Administrator. The Trust is also the sole holder of the Administrator Notes.

Common Shares

Each common share will entitle its holder to receive notice of and to attend all meetings of the shareholders of the Administrator and to one vote at such meetings. The holders of common shares will be, at the discretion of the board of directors of the Administrator and subject to applicable legal restrictions, and subject to certain preferences of holders of Exchangeable Shares, entitled to receive any dividends declared by the board of directors on the common shares to the exclusion of the holders of Exchangeable Shares, subject to the proviso that no dividends shall be paid on the common shares unless all declared dividends on the outstanding Exchangeable Shares have been paid in full. The holders of common shares will be entitled to share equally in any distribution of the assets of the Administrator upon the liquidation, dissolution, bankruptcy or winding–up of the Administrator or other distribution of its assets among its shareholders for the purpose of winding–up its affairs. Such participation is subject to the rights, privileges, restrictions and conditions attaching to the Exchangeable Shares and any other shares having priority over the common shares.

Exchangeable Shares

The following is a summary description of the material provisions of the Exchangeable Shares and the related ancillary and indirect rights of holders of Exchangeable Shares under the terms of the Voting and Exchange Trust Agreement and the Support Agreement. This summary is qualified in its entirety by reference to the full text of: (i) the Exchangeable Share provisions; (ii) the Support Agreement; and (iii) the Voting and Exchange Trust Agreement.

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Each Exchangeable Share has economic rights (including the right to have the Exchange Ratio adjusted to account for distributions paid to Unitholders) and voting attributes (through the benefit of the Special Voting Units granted to the Voting and Exchange Trust Agreement Trustee) as set forth in the Exchangeable Share provisions, the Support Agreement and the Voting and Exchange Trust Agreement. In addition, holders of Exchangeable Shares will have the right to receive Trust Units at any time in exchange for their Exchangeable Shares, on the basis of the Exchange Ratio in effect at the time of the exchange. Fractional Trust Units will not be delivered on any exchange of Exchangeable Shares. In the event that the Exchange Ratio in effect at the time of an exchange would otherwise entitle a holder of Exchangeable Shares to a fractional Trust Unit, the number of Trust Units to be delivered will be rounded to the nearest whole number of Trust Units.

Holders of Exchangeable Shares will not receive cash distributions from the Trust or the Administrator in respect of Distributions on Trust Units.  On each Distribution Payment Date, the Exchange Ratio will be increased, on a cumulative basis, in respect of the Distribution on such date by an amount which assumes the reinvestment of such Distribution in Trust Units at he Current Market Price of a Trust Unit on the first Business Day following the Distribution Record Date for such Distribution.  The Exchange Ratio will be decreased in respect of any dividends paid on the Exchangeable Shares by an amount of such dividend by the then–prevailing Current Market Price of a Trust Unit.

Ranking

The Exchangeable Shares rank rateably with shares of any other series of exchangeable shares of the Administrator and prior to any common shares of the Administrator and any other shares ranking junior to the Exchangeable Shares with respect to the payment of dividends, if any, that have been declared and the distribution of assets in the event of the liquidation, dissolution or winding–up of the Administrator.

Dividends

Holders of Exchangeable Shares, in priority to the common shares and any other class of shares of the Administrator ranking junior to the Exchangeable Shares with respect to the payment of dividends, are entitled to receive cumulative preferential cash dividends if, as and when declared by the board of directors of the Administrator in its sole discretion, from time to time, out of the money, assets or property of the Administrator properly applicable to the payment of dividends (which may include Trust Units). Such dividends, in the amounts set out in the Exchangeable Share provisions, whether declared or not, shall accrue and be cumulative.

Certain Restrictions

The Administrator will not, without obtaining the approval of the holders of the Exchangeable Shares as set forth below under the subheading “Amendment and Approval”:

(a)pay any dividend on the common shares or any other shares ranking junior to the Exchangeable Shares, other than stock dividends payable in common shares or any other shares ranking junior to the Exchangeable Shares;

(b)redeem, purchase or make any capital distribution in respect of the common shares or any other shares ranking junior to the Exchangeable Shares;

(c)redeem or purchase any other shares of the Administrator ranking equally with the Exchangeable Shares with respect to the payment of dividends or on any liquidation distribution; or

(d)amend the articles or by-laws of the Administrator in any manner that would affect the rights or privileges of the holders of Exchangeable Shares.

The above restrictions in (a), (b) and (c) shall not apply if all declared dividends on the outstanding Exchangeable

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Shares have been paid in full.

Liquidation or Insolvency of the Administrator

In the event of the liquidation, dissolution or winding–up of the Administrator or any other distribution of the assets of the Administrator among its shareholders for the purpose of winding up its affairs, a holder of Exchangeable Shares will be entitled to receive from the Administrator, in respect of each such Exchangeable Share, that number of Trust Units equal to the Exchange Ratio as at the effective date of such event.

Upon the occurrence of such an event, the Trust and ExchangeCo will each have the overriding right to purchase all but not less than all of the Exchangeable Shares then outstanding (other than Exchangeable Shares held by the Trust or any subsidiary of the Trust) at a purchase price per Exchangeable Share to be satisfied by the issuance or delivery, as the case may be, of that number of Trust Units equal to the Exchange Ratio at such time and, upon the exercise of this right, the holders thereof will be obligated to sell such Exchangeable Shares to the Trust or ExchangeCo, as applicable. This right may be exercised by either the Trust or ExchangeCo.

Upon the occurrence of an Insolvency Event, or if the Trust and ExchangeCo are entitled to exercise any Call Right, but elect not exercise such Call Right, the Voting and Exchange Trust Agreement Trustee on behalf of the holders of the Exchangeable Shares will have the right to require the Trust or ExchangeCo to purchase any or all of the Exchangeable Shares then outstanding and held by such holders at a purchase price per Exchangeable Share to be satisfied by the issuance or delivery, as the case may be, of that number of Trust Units equal to the Exchange Ratio at such time, as described under the subheading “Voting and Exchange Trust Agreement – Optional Exchange Rights”.

Automatic Exchange Right on Liquidation of the Trust

The Voting and Exchange Trust Agreement provides that in the event of a Trust liquidation event, as described below, the Trust or ExchangeCo will be deemed to have purchased all outstanding Exchangeable Shares and each holder of Exchangeable Shares will be deemed to have sold their Exchangeable Shares immediately prior to such Trust liquidation event at a purchase price per Exchangeable Share to be satisfied by the issuance or delivery, as the case may be, of that number of Trust Units equal to the Exchange Ratio at such time. “Trust liquidation event” means:

(a)any determination by the Trust to institute voluntary liquidation, dissolution or winding–up proceedings in respect of the Trust or to effect any other distribution of assets of the Trust among the Unitholders for the purpose of winding up its affairs; or

(b)the earlier of the Trust or the Administrator receiving notice of and the Trust or the Administrator otherwise becoming aware of, any threatened or instituted claim, suit, petition or other proceedings with respect to the involuntary liquidation, dissolution or winding up of the Trust or to effect any other distribution of assets of the Trust among the Unitholders for the purpose of winding up its affairs in each case where the Trust has failed to contest in good faith such proceeding within 30 days of becoming aware thereof.

Retraction of Exchangeable Shares by Holders and Retraction Call Right

Subject to the Retraction Call Right of the Trust and ExchangeCo described below, a holder of Exchangeable Shares will be entitled at any time to require the Administrator to redeem any or all of the Exchangeable Shares held by such holder for a retraction price (the “Retraction Price”) per Exchangeable Share equal to the amount determined by multiplying the Exchange Ratio on the last Business Day prior to the Retraction Date (as defined below) by the Current Market Price of a Unit on the last Business Day prior to the Retraction Date, which payment of the Retraction Price shall be satisfied in full by the Administrator delivering or causing to be delivered to such holder that number of Units equal to the Exchange Ratio as at the last Business Day prior to the Retraction Date for each Exchangeable Share presented and surrendered by the holder. Fractional Trust Units will not be delivered. Any amount payable on account of the Retraction Price that includes a fractional Trust Unit will be rounded to the

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nearest whole number of Trust Units.

Holders of the Exchangeable Shares may request redemption by presenting to the Administrator or the transfer agent for the Exchangeable Shares a certificate or certificates representing the number of Exchangeable Shares the holder desires to have redeemed, together with a duly executed retraction request and such other documents as may be reasonably required to effect the redemption of the Exchangeable Shares. Subject to extension as described below, the redemption will become effective on the date that is three Business Days after the date on which the Administrator or the transfer agent receives the retraction notice (the “Retraction Date”).

When a holder requests the Administrator to redeem the Exchangeable Shares, the Trust and ExchangeCo will have an overriding right (the “Retraction Call Right”) to purchase on the Retraction Date all but not less than all of the Exchangeable Shares that the holder has requested the Administrator to redeem at a purchase price per Exchangeable Share equal to the Retraction Price, which payment of the Retraction Price shall be satisfied in full by the Administrator delivering or causing to be delivered to such holder that number of Units equal to the Exchange Ratio as at the last Business Day prior to the Retraction Date for each Exchangeable Share presented and surrendered by the holder. At the time of a Retraction Request by a holder of Exchangeable Shares, The Administrator will immediately notify the Trust and ExchangeCo. The Trust or ExchangeCo must then advise the Administrator on or before 4:30 p.m. (Calgary time) on the date of notification as to whether the Retraction Call Right will be exercised.

A holder may revoke his or her Retraction Request at any time prior to the close of business on the last Business Day immediately preceding the Retraction Date, in which case the holder’s Exchangeable Shares will neither be purchased by the Trust or ExchangeCo nor be redeemed by the Administrator. If the holder does not revoke his or her Retraction Request, the Exchangeable Shares that the holder has requested the Administrator to redeem will on the Retraction Date be purchased by the Trust or ExchangeCo or redeemed by the Administrator, as the case may be, in each case at a purchase price per Exchangeable Share equal to the Retraction Price.  In addition, a holder of Exchangeable Shares may elect to instruct the Voting and Exchange Trust Agreement Trustee to exercise the optional exchange right (the “Optional Exchange Right”) to require the Trust or ExchangeCo to acquire such holder’s Exchangeable Shares in circumstances where neither the Trust nor ExchangeCo have exercised the Retraction Call Right.  See “Voting and Exchange Trust Agreement – Optional Exchange Right”.

The Retraction Call Right may be exercised by either the Trust or ExchangeCo.  If, as a result of solvency provisions of applicable law, The Administrator is not permitted to redeem all Exchangeable Shares tendered by a retracting holder, the Administrator will redeem only those Exchangeable Shares tendered by the holder as would not be contrary to such provisions of applicable law. The holder of any Exchangeable Shares not redeemed by the Administrator will be deemed to have required the Trust to purchase such unretracted Exchangeable Shares in exchange for Trust Units on the Retraction Date pursuant to the Optional Exchange Right. See “Voting and Exchange Trust Agreement – Optional Exchange Right”.

Redemption of Exchangeable Shares

Subject to applicable law and the Redemption Call Right (as defined below) of the Trust and ExchangeCo, the Administrator:

(a)will, on the fifth anniversary of the effective date of the Arrangement, subject to extension of such date by the board of directors of the Administrator (the “Automatic Redemption Date”), redeem all but not less than all of the then outstanding Exchangeable Shares;

(b)may, on the second anniversary of the effective date of the Arrangement (the “Optional Redemption Date”), redeem all but not less than all outstanding Exchangeable Shares;

(c)may, on any date that is within the first 90 days of any calendar year commencing in 2005 (the “Annual Redemption Date”), redeem up to that number of Exchangeable Shares equal to 25% of the Exchangeable Shares outstanding on the Effective Date (an “Annual Redemption”); and

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(d)may, at any time when the aggregate number of issued and outstanding Exchangeable Shares is less than 1,600,000 (other than Exchangeable Shares held by the Trust and its subsidiaries and as such shares may be adjusted from time to time) (the “De Minimus Redemption Date” and, collectively with the Automatic Redemption Date, optional Redemption Date and Annual Redemption Date, a “Redemption Date”), redeem all but not less than all of the then outstanding Exchangeable Shares;

in each case for a price per Exchangeable Share equal to the amount determined by multiplying the Exchange Ratio on the last Business Day prior to the Redemption Date by the Current Market Price of a Unit on the last Business Day prior to the Redemption Date (the “Redemption Price”), such payment of the Redemption Price per Exchangeable Share to be satisfied in full in all cases by the Administrator delivering or causing to be delivered, at the election of the Administrator, either that number of Trust Units equal to the Exchange Ratio as at the last Business Day prior to the applicable Redemption Date or an amount in cash equal to the Redemption Price.

The Administrator will, at least 90 days prior to any Redemption Date, provide the registered holders of the Exchangeable Shares with written notice of the prospective redemption of the Exchangeable Shares by the Administrator.

The Trust and ExchangeCo will have the right (the “Redemption Call Right”), notwithstanding a proposed redemption of the Exchangeable Shares by the Administrator on the applicable Redemption Date, pursuant to the Exchangeable Share Provisions, to, in the case of any redemption other than an Annual Redemption, purchase from all but not less than all of the holders of Exchangeable Shares (other than the Trust or ExchangeCo) on the applicable Redemption Date all but not less than all of the Exchangeable Shares held by each such holder or to, in the case of an Annual Redemption, purchase from all but not less than all of the holders of Exchangeable Shares (other than the Trust or ExchangeCo) on the applicable Redemption Date the designated percentage of the Exchangeable Shares held by each such holder, on payment by whichever of the Trust or ExchangeCo is exercising such right to each such holder of an amount per Exchangeable Share equal to the Redemption Price, which payment of the Redemption Price shall be satisfied in full by the party exercising the Redemption Call Right delivering or causing to be delivered to such holder, at the election of the exercising party, either that number of Trust Units equal to the Exchange Ratio as at the last Business Day prior to the applicable Redemption Date or an amount in cash equal to the Redemption Price.  If either the Trust or ExchangeCo exercises the Redemption Call Right, then The Administrator’s right to redeem the Exchangeable Shares on the applicable Redemption Date will terminate. The Redemption Call Right may be exercised by either the Trust or ExchangeCo.

Voting Rights

Except as required by applicable law, the holders of the Exchangeable Shares are not entitled as such to receive notice of or attend any meeting of the shareholders of the Administrator or to vote at any such meeting. Holders of Exchangeable Shares will have the notice and voting rights respecting meetings of the Trust that are provided in the Voting and Exchange Trust Agreement.  See “Voting and Exchange Trust Agreement – Voting Rights”.

Amendment and Approval

The rights, privileges, restrictions and conditions attaching to the Exchangeable Shares may be changed only with the approval of the holders thereof. Any such approval or any other approval or consent to be given by the holders of the Exchangeable Shares will be sufficiently given if given in accordance with applicable law and subject to a minimum requirement that such approval or consent be evidenced by a resolution passed by not less than two-thirds of the votes cast thereon (other than shares beneficially owned by the Trust, or any of its subsidiaries and other affiliates) at a meeting of the holders of the Exchangeable Shares duly called and held at which holders of at least 10 percent of the then outstanding Exchangeable Shares are present in person or represented by proxy.  In the event that no such quorum is present at such meeting within one-half hour after the time appointed therefor, then the meeting will be adjourned to such place and time (not less than ten days later) as may be determined at the original meeting and the holders of Exchangeable Shares present in person or represented by proxy at the adjourned meeting will

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constitute a quorum thereat and may transact the business for which the meeting was originally called. At the adjourned meeting, a resolution passed by the affirmative vote of not less than two-thirds of the votes cast thereon (other than shares beneficially owned by the Trust or any of its subsidiaries and other affiliates) will constitute the approval or consent of the holders of the Exchangeable Shares.

Actions by the Trust under the Support Agreement and the Voting and Exchange Trust Agreement

Under the Exchangeable Share provisions, the Administrator will agree to take all such actions and do all such things as are necessary or advisable to perform and comply with its obligations under, and to ensure the performance and compliance by the Trust and ExchangeCo with its obligations under, the Support Agreement and the Voting and Exchange Trust Agreement.

Non-Resident and Tax-Exempt Holders

Exchangeable Shares will not be issued to persons who are Non-Residents or who are exempt from tax under Part I of the Tax Act. The obligation of the Administrator, the Trust or ExchangeCo to deliver Trust Units to a Non-Resident holder in respect of the exchange of such holder’s Exchangeable Shares may be satisfied by delivering such Trust Units to the transfer agent who shall sell such Trust Units on the stock exchange on which they are listed and deliver the proceeds of sale to the Non-Resident holder.

VOTING AND EXCHANGE TRUST AGREEMENT

Voting Rights

In accordance with the Voting and Exchange Trust Agreement, the Trust has issued a Special Voting Unit to Olympia Trust Company, the Voting and Exchange Trust Agreement Trustee, for the benefit of the holders (other than the Trust and ExchangeCo) of the Exchangeable Shares.  The Special Voting Unit carries a number of votes, exercisable at any meeting at which Trust Unitholders are entitled to vote, equal to the number of Trust Units (rounded down to the nearest whole number) into which the Exchangeable Shares are then exchangeable multiplied by the number of votes to which the holder of one Trust Unit is then entitled. With respect to any written consent sought from the Trust Unitholders, each vote attached to the Special Voting Unit will be exercisable in the same manner as set forth above.

Each holder of an Exchangeable Share on the record date for any meeting at which Trust Unitholders are entitled to vote will be entitled to instruct the Voting and Exchange Trust Agreement Trustee to exercise that number of votes attached to the Special Voting Unit which relate to the Exchangeable Shares held by such holder. The Voting and Exchange Trust Agreement Trustee will exercise each vote attached to the Special Voting Unit only as directed by the relevant holder and, in the absence of instructions from a holder as to voting, will not exercise such votes.

The Voting and Exchange Trust Agreement Trustee will send to the holders of the Exchangeable Shares the notice of each meeting at which the Trust Unitholders are entitled to vote, together with the related meeting materials and a statement as to the manner in which the holder may instruct the Voting and Exchange Trust Agreement Trustee to exercise the votes attaching to the Special Voting Unit, at the same time as the Trust sends such notice and materials to the Trust Unitholders. The Voting and Exchange Trust Agreement Trustee will also send to the holders copies of all information statements, interim and annual financial statements, reports and other materials sent by the Trust to the Trust Unitholders at the same time as such materials are sent to the Trust Unitholders. To the extent such materials are provided to the Voting and Exchange Trust Agreement Trustee by the Trust, the Voting and Exchange Trust Agreement Trustee will also send to the holders all materials sent by third parties to Trust Unitholders, including dissident proxy circulars and tender and exchange offer circulars, as soon as possible after such materials are first sent to Trust Unitholders. The Voting and Exchange Trust Agreement Trustee will also make copies of all such materials available for inspection by Trust Unitholder at the trustee’s principal transfer office in the City of Calgary.

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All rights of a holder of Exchangeable Shares to exercise votes attached to the Special Voting Unit will cease upon the exchange of all such holder’s Exchangeable Shares for Trust Units. With the exception of administrative changes for the purpose of adding covenants for the protection of the holders of the Exchangeable Shares, making necessary amendments or curing ambiguities or clerical errors (in each case provided that the board of directors of ExchangeCo and the Administrator are of the opinion that such amendments are not prejudicial to the interests of the holders of the Exchangeable Shares), the Voting and Exchange Trust Agreement may not be amended without the approval of the holders of the Exchangeable Shares.

Optional Exchange Right

Upon the occurrence and during the continuance of:

(a)an Insolvency Event; or

(b)circumstances in which the Trust or ExchangeCo may exercise a Call Right, but elect not to exercise such Call Right,

a holder of Exchangeable Shares will be entitled to instruct the Voting and Exchange Trust Agreement Trustee to exercise the Optional Exchange Right (as defined above under the heading “The Administrator Share Capital – Exchangeable Shares - Retraction of Exchangeable Shares by Holders and Retraction Call Right”) with respect to any or all of the Exchangeable Shares held by such holder, thereby requiring the Trust or ExchangeCo to purchase such Exchangeable Shares from the holder for a price per Exchangeable Share equal to the amount determined by multiplying the Exchange Ratio on the last Business Day prior to the closing of the purchase and sale of the Exchangeable Share pursuant to the Optional Exchange Right by the Current Market Price of a Unit on such date.  Payment of such price shall be satisfied in full by the Trust or ExchangeCo, as applicable, delivering or causing to be delivered to such holder that number of Units equal to the Exchange Ratio on the last Business Day prior to the closing of the purchase and sale of the Exchangeable Share pursuant to the Optional Exchange Right.

Immediately upon the occurrence of (i) an Insolvency Event, (ii) any event which will, with the passage of time or the giving of notice, become an Insolvency Event, or (iii) the election by the Trust and ExchangeCo not to exercise a Call Right which is then exercisable by the Trust and ExchangeCo, the Administrator, the Trust or ExchangeCo will give notice thereof to the Voting and Exchange Trust Agreement Trustee. As soon as practicable thereafter, the Voting and Exchange Trust Agreement Trustee will then notify each affected holder of Exchangeable Shares (who has not already provided instructions respecting the exercise of the Optional Exchange Right) of such event or potential event and will advise such holder of its rights with respect to the Optional Exchange Right.

If, as a result of solvency provisions of applicable law, the Administrator is unable to redeem all of a holder’s Exchangeable Shares which such holder is entitled to have redeemed in accordance with the Exchangeable Share Provisions, the holder will be deemed to have exercised the Optional Exchange Right with respect to the unredeemed Exchangeable Shares and the Trust or ExchangeCo will be required to purchase such shares from the holder in the manner set forth above.

SUPPORT AGREEMENT

The Trust Support Obligation

Under the Support Agreement, the Trust will agree that, the Trust will not:

(a)issue or distribute Trust Units (or securities exchangeable for or convertible into or carrying rights to acquire Trust Units) to the holders of all or substantially all of the then outstanding Trust Units by way of stock distribution or other distribution, other than an issue of Trust Units (or securities exchangeable for or convertible into or carrying rights to acquire Trust Units) to holders of Trust Units who exercise an option to receive distributions in Trust Units (or securities exchangeable for

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or convertible into or carrying rights to acquire Trust Units) in lieu of receiving cash distributions;

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(b)issue or distribute rights, options or warrants to the holders of all or substantially all of the then outstanding Trust Units entitling them to subscribe for or to purchase Trust Units (or securities exchangeable for or convertible into or carrying rights to acquire Trust Units);

(c)issue or distribute to the holders of all or substantially all of the then outstanding Trust Units: (A) securities of the Trust of any class other than Trust Units (other than securities convertible into or exchangeable for or carrying rights to acquire Trust Units);  (B) evidences of indebtedness of the Trust; or (C) assets of the Trust other than Distributions which result in an adjustment to the Exchange Ratio;

(d)subdivide, redivide or change the then outstanding Trust Units into a greater number of Trust Units;

(e)reduce, combine or consolidate or change the then outstanding Trust Units into a lesser number of Trust Units; or

(f)reclassify or otherwise change the Trust Units or effect an amalgamation, merger, reorganization or other transaction affecting the Trust Units,

unless, the same or an economically equivalent change is simultaneously made to, or in the rights of the holders of, the Exchangeable Shares or it has received the prior written approval of the Administrator and the approval of the holders of the Exchangeable Shares at a meeting of holders of Exchangeable Shares.

In the event of any proposed take-over bid, issuer bid or similar transaction affecting the Trust Units, the Trust will use reasonable efforts to take all actions necessary or desirable to enable holders of Exchangeable Shares to participate in such transaction to the same extent and on an economically equivalent basis as the Trust Unitholders.

The Support Agreement also provides that, as long as any outstanding Exchangeable Shares are owned by any person or entity other than the Trust or any of its respective subsidiaries and other affiliates, the Trust will, unless approval to do otherwise is obtained from the holders of Exchangeable Shares, remain the direct or indirect beneficial owner collectively of more than 50 percent of all of the issued and outstanding voting securities of the Administrator, provided that the Trust will not be in violation of this obligation if a party acquires all or substantially all of the assets of the Trust. With the exception of administrative changes for the purpose of adding covenants for the protection of the holders of the Exchangeable Shares, making certain necessary amendments or curing ambiguities or clerical errors (in each case provided that the board of directors of the Administrator and the Trustee are of the opinion that such amendments are not prejudicial to the interests of the holders of the Exchangeable Shares), the Support Agreement may not be amended without the approval of the holders of the Exchangeable Shares.

Under the Support Agreement, the Trust will agree to not exercise any voting rights attached to the Exchangeable Shares owned by it or any of its respective subsidiaries and other affiliates on any matter considered at meetings of holders of Exchangeable Shares (including any approval sought from such holders in respect of matters arising under the Support Agreement).

Delivery of Trust Units

The Trust will agree to make such filings and seek such regulatory consents and approvals as are necessary so that the Trust Units issuable upon the exchange of Exchangeable Shares will be issued in compliance with applicable securities laws in Canada and may be traded freely on the TSX or such other exchange on which the Trust Units may be listed, quoted or posted for trading from time to time.

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ADMINISTRATOR NOTES

The following summary of the material attributes and characteristics of the Administrator Notes does not purport to be complete and is qualified in its entirety by reference to the provisions of the Administrator Note Indenture, which contains a complete statement of such attributes and characteristics. The Administrator Notes are issued under the Administrator Note Indenture.  The Trust is the sole holder of the Administrator Notes.

Terms and Issue of Notes

The Administrator Notes are unsecured and bear interest at a rate which may be adjusted from time to time in the circumstances provided in the Administrator Note Indenture.  Interest is payable for each month during the term, on the 10th day of the month following such month, or the next Business Day if such day is not a Business Day.  The Administrator Notes rank pari passu with all other unsecured indebtedness of the Administrator, but subordinate to all secured debt. The Administrator Notes are payable on December 31, 2035, subject to extension in the limited circumstances provided in the Administrator Note Indenture.

The Administrator may prepay all or any portion of the Administrator Notes and in that case the Administrator shall pay any accrued and unpaid interest on the Administrator Notes to be prepaid to the date of prepayment.  However, the payment of the principal of, any interest on, and all other indebtedness, obligations and liabilities evidenced by each and all of the Administrator Notes and all other obligations of the Administrator under the Administrator Note Indenture (other than ordinary and regularly scheduled fees and out–of–pocket expenses of the Trustee) are expressly subordinated, in right of payment to the prior indefeasible payment in full and in cash of all Senior Debt outstanding or incurred; except that the Administrator is not precluded from paying principal and regularly scheduled interest on the Administrator Notes as long as at the relevant interest payment date and immediately after the making of such payment no Senior Debt Default has occurred and is continuing.

For these purposes, “Senior Debt” means (a) all indebtedness, obligations and liabilities of the Administrator in respect of Borrowed Money (as defined in the Administrator Note Indenture) excluding (i) the indebtedness, obligations or liability created under or evidenced by the Administrator Notes or the Administrator Note Indenture; and (ii) any indebtedness that by its terms or by the terms of the instrument evidencing or creating it ranks or in respect of which the holders thereof have agreed that it shall rank pari passu with or subordinate to the Administrator Notes; and (b) from and after the commencement of, and during the continuance of, any creditor proceedings (including bankruptcy, liquidation, winding–up, dissolution, restructuring or arrangement proceedings), all indebtedness, obligations and liabilities of the Administrator other than indebtedness obligations and liabilities to the holders of Administrator Notes and “Senior Debt Default” means and includes any event of default under any Senior Debt and any event or circumstance which, with the passage of time or the giving of notice, or both, would constitute an event of default under Senior Debt.

In contemplation of the possibility that Administrator Notes may be distributed to Trust Unitholders upon the redemption of their Trust Units, the Administrator Note Indenture will provide that if persons other than the Trust (the “Non-Trust Holders”) own Administrator Notes having an aggregate principal amount in excess of $1,000,000, either the Trust or the Non-Trust Holders shall be entitled, among other things, to require the Note Trustee to exercise the powers and remedies available under the Administrator Note Indenture upon an event of default and, with the Trust, the Non-Trust Holders may provide consents, waivers or directions relating generally to the variance of the Administrator Note Indenture and the rights of noteholders. The Administrator Note Indenture will allow the Trust flexibility to delay payments of interest or principal otherwise due to it while payment is made to other noteholders, and to allow other noteholders to be paid out before the Trust.  Any delayed payments will be due five days after demand.

Principal and interest on the Administrator Notes is payable in lawful money of Canada directly to the holders of Administrator Notes and at their address set forth in the register of holders of Administrator Notes.

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Events of Default

The Administrator Note Indenture provides that any of the following shall constitute an Event of Default: (i) default in payment of the principal of the Administrator Notes when required; (ii) the failure by the Administrator to pay all accrued interest on the Administrator Notes in full within twelve (12) months of the payment date of the same; (iii) if the Administrator has defaulted and a demand for payment has been made under any material instrument, indenture or document evidencing indebtedness of more than $50 million and the Administrator has failed to remedy such default within applicable curative periods; (iv) certain events of winding–up, liquidation, bankruptcy, insolvency, receivership or seizure; (v) default in the observance or performance of any other covenant or condition of the Administrator Note Indenture and continuance of such default for a period of 30 days after notice in writing has been given by the trustee to the Administrator specifying such default and requiring the Administrator to rectify the same; (vi) any proceedings concerning the Administrator are taken with respect to a compromise or arrangement under the Companies’ Creditors Arrangement Act (or any act substituted therefor) or similar legislation of any other jurisdiction; and (vii) any encumbrancer takes possession of all or substantially all of the property of the Administrator or if a distress or execution or any similar process is enforced against such property and remains unsatisfied for so long as would permit any part of such property to be sold thereunder, or if a custodian or sequestrator or a receiver or receiver and manager or any other officer with similar powers is appointed for the Administrator or for all or substantially all of the Administrator’s property.

NPI AGREEMENT

Pursuant to the NPI Agreement, the Partnership has granted and set over to the Trust the NPI on petroleum and natural gas rights held by the Partnership from time to time (the “Property Interests”).

Pursuant to the terms of the NPI Agreement, the Trust is entitled to a payment from the Partnership for each month equal to the amount by which ninety-nine (99%) percent of the gross proceeds from the sale of production attributable to the Property Interests for such month exceed ninety–nine (99%) percent of certain deductible production costs for such period.

If the Partnership wishes to dispose of any Property Interests which will result in proceeds in excess of a threshold amount, the board of directors of the Administrator, as the managing partner of the Partnership, shall approve such disposition, however, if the asset value (calculated in accordance with the terms of the NPI Agreement) of any interests included in such disposition is greater than a threshold percentage of the asset value of all the Property Interests held by the Partnership, such disposition must be approved by a special resolution of the Unitholders.  The term of the NPI Agreement will be for so long as there are petroleum and natural gas rights to which the NPI applies.

DIRECTORS AND OFFICERS OF THE ADMINISTRATOR

The name, municipality of residence, principal occupation for the prior five years and proposed position, of each of the directors and officers of the Administrator are as follows:

Name and Residence	Position	Principal Occupation During Previous Five Years
Paul Colborne Calgary, Alberta	President, CEO, Director	President and Chief Executive Officer of the Administrator. From September, 2003 to January, 2005, President and Chief Executive Officer of StarPoint. From June, 2001 to September, 2003, President, Chief Executive Officer and director of Crescent Point Energy Ltd. From 1993 to February, 2001, President and Chief Executive Officer of Startech Energy Inc.

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Name and Residence	Position	Principal Occupation During Previous Five Years
Brett Herman Calgary, Alberta	Vice-President, Finance and Chief Financial Officer	Vice-President, Finance and Chief Financial Officer of the Administrator. From September, 2003 to January, 2005, Vice-President, Finance and Chief Financial Officer of StarPoint. From April, 2003 to August, 2003, independent businessman. From September, 2001 to March, 2003, Vice-President and Controller of Navigo Energy Ltd. (formerly Ventus Energy Ltd.). From June, 1999 to August, 2001, Controller of Ventus Energy Ltd.
Graham Kidd, Calgary Alberta	Vice-President, Corporate Development	Vice-President, Corporate Development of the Administrator.  From January, 2001 to February, 2005, Vice-President, Engineering of Collins Barrow Securities Inc. From June, 2000 to December, 2000, independent businessman. From June, 1995 to May, 2000, Acquisitions Engineer at Ulster Petroleums Ltd.
Murray Mason Calgary, Alberta	Vice-President, Production	Vice-President, Production of the Administrator. From May, 2004 to January, 2005, independent businessman. From January, 2001 to April, 2004, Vice-President, Production of Impact Energy Inc. From October, 1993 to January, 2001, Vice-President, Production of Startech Energy Inc.
Jim Pasieka Calgary, Alberta	Director and Corporate Secretary	Partner with Heenan Blaikie LLP, a national law firm. From January, 2000 to September, 2001, Vice President, Corporate Development - Venture Capital with Cavendish Investing Ltd., a private investment company. From August, 1995 to December, 1999, lawyer with Code Hunter.
Jim Bertram Calgary, Alberta	Director	President and CEO of Keyera Facilities Income Fund and its predecessor companies.
Fred Coles Calgary, Alberta	Director	President of Menehune Resources Ltd., a private oil and gas company. From 1994 to March, 2002, Executive Chairman of Applied Terravision Systems Inc., a computer software development company.
Robert G. Peters Calgary, Alberta	Director	President of Black Diamond Land Cattle Co. since October, 2002. From February, 1971 until September, 2002, Chairman of the Board of Peters & Co. Limited, an investment company founded by Mr. Peters.

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Name and Residence	Position	Principal Occupation During Previous Five Years
Paul Starnino Bragg Creek, Alberta	Director	President and Chief Executive Officer of P3 Energy Inc., a private oil and natural gas company. President and Chief Executive Officer of E3 from October, 2002 to January, 2005. From January, 2002 to March, 2002, President and a consultant to Enerstar Resources. From January, 2001 to January, 2002, Chief Geophysicist at Richland Petroleum. From May, 2000 to December, 2000, President and a consultant to Enerstar Resources. From November 1996 to April 2000, Vice-President of Exploration of CrownJoule Exploration Ltd.

The Board of Directors of the Administrator has an audit committee, a compensation committee, a reserves committee and an environmental, health and safety committee.  The members of the audit committee are Jim Bertram, Robert G. Peters and Paul Starnino. The members of the compensation committee are Robert G. Peters, Jim Bertram and Jim Pasieka.  The members of the reserves committee are Fred Coles, Paul Starnino and Jim Pasieka. The members of the environmental, health and safety committee are Jim Bertram, Paul Starnino and Paul Colborne.

Each of the directors has been a director of the Administrator since the date of its amalgamation on January 7, 2005. Each of the directors of the Administrator hold will hold office until first annual meeting of the Trust Unitholders or until his successor is duly elected or appointed, unless his office be earlier vacated in accordance with the Administrator’s articles or by-laws.

The directors and officer of the Administrator, as a group, beneficially own, directly or indirectly, or exercise control or direction over 704,436 Trust Units and 685,486 Exchangeable Shares.  This represents approximately 4.7% of the number of Trust Units outstanding on a fully diluted basis.

The directors and officers of the Administrator are engaged in and will continue to engage in other activities in the oil and natural gas industry and, as a result of these and other activities, the directors and officers of the Administrator may become subject to conflicts of interest. The ABCA provides that, in the event that a director has an interest in a contract or proposed contract or agreement, the director shall disclose his interest in such contract or agreement and shall refrain from voting on any matter in respect of such contract or agreement unless otherwise provided under the ABCA. To the extent that conflicts of interest arise, such conflicts will be resolved in accordance with the provisions of the ABCA.

As at the date hereof neither the Trust nor the Administrator is aware of any existing or potential material conflicts of interest between the Trust and the Administrator and a director or officer of the Administrator.

AUDIT COMMITTEE

Audit Committee Charter

The audit committee of the Board of Directors of the Administrator operates under a written charter that sets out its responsibilities and composition requirements.  A copy of the charter is attached to this Annual Information Form as Schedule “C”.

Composition of the Audit Committee

The members of the audit committee are Jim Bertram, Robert G. Peters and Paul Starnino. The audit committee charter requires all members to be financially literate and independent within the meaning of applicable securities laws.  All members of the audit committee meet these requirements.

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The following sets out the education and experience of each director relevant to the performance of his duties as a member of the audit committee.

Jim Bertram

Mr. Bertram graduated in 1981 from the University of Calgary with a Bachelor of Commerce.

He is currently the President and Chief Executive Officer of Keyera Facilities Income Fund, an integrated energy company focused on the Canadian natural gas midstream and NGL marketing business.  Mr. Bertram has held this position with Keyera and its predecessor companies since 1998.  Keyera has significant interests in Canadian natural gas gathering systems, gas and NGL processing plants, pipelines, terminals and other midstream facilities.  Keyera is listed on the TSX.

From 1996 to 1998, Mr. Bertram was employed as Vice-President, Marketing for Gulf Canada Resources Limited’s worldwide operations.  Prior to joining Gulf, Mr. Bertram was Vice-President, Marketing at Amerada Hess Canada Ltd. for a period of seven years.

Currently, Mr. Bertram also sits on the board of directors of Keyera Facilities Income Fund and Mission Oil & Gas Inc.

Robert G. Peters

Until his retirement from the firm in September, 2002, Mr. Peters was Chairman of the Board of Peters & Co. Limited, an investment leader headquartered in Calgary. The company, which Mr. Peters founded, commenced operations in 1971. The firm specializes in investments in western Canada, with particular emphasis on the energy industry.  Prior to founding Peters & Co., Mr. Peters was the Alberta Manager of Nesbitt Thomson Bongard Inc.

Over the years, Mr. Peters has been an investor and held board positions with numerous Canadian exploration companies. For two years he served on the IDA’s Board of Directors and in 1979 and again in 1980 he was Chairman of the Alberta Stock Exchange. He also served a term as Member of the Board of Management and Executive Committee with the Foothills Hospital, as President of the Foothills Hospital Foundation, and a board member of the Alberta College of Art.

Currently, Mr. Peters also sits on the board of directors of Mission Oil & Gas Inc., Titan Exploration Ltd., GMP Capital Corp., Big Rock Brewery, Airborne Energy Solutions Ltd., Odorchem Manufacturing Corp.

Paul Starnino

Mr. Starnino graduated from the University of Waterloo with an Honours Bachelor of Science Degree in applied physics in 1985.

Mr. Starnino is the President and Chief Executive Officer of P3 Energy Inc. and E4 Energy Inc., each a private oil and natural gas company. Mr. Starnino was the President and Chief Executive Officer of E3 prior to the Arrangement.  For the period from October, 1996 to April, 2000, Mr. Starnino was Vice-President of Exploration of CrownJoule Exploration Ltd., an oil and gas company listed on the TSX prior to being sold in April, 2000. Mr. Starnino previously held senior exploration and management positions with Richland Petroleum, AEC West Ltd, Texaco Canada Petroleum Inc., Amerada Hess Canada Ltd., Home Oil Company and Enerstar Resources Ltd.

Pre-Approval Policies

The audit committee charter provides that non-audit services by the Trust’s auditors must be pre-approved by the audit committee.  The audit committee also pre-approves any audit services and the fees to be paid.

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Auditors’ Fees

KPMG LLP are the auditors of the Trust.  KPMG LLP also served as the auditors of StarPoint prior to the completion of the Arrangement.  The table below sets out the aggregate fees billed by KPMG LLP to the Trust and StarPoint in each of the last two fiscal years.

	Year ended December 31, 2004		Year ended December 31, 2003
Audit fees	$	292,000	$	47,500
Audit-related fees(1)	171,000		47,500
	$	463,000	$	95,000

Notes:

(1)These fees relate to services consisting of the preparation of prospectus documents and other required securities filings.

MARKET FOR SECURITIES

The Trust Units have been listed and posted for trading on the TSX under the trading symbol “SPN.UN” since January 14, 2005.  The following table sets forth the reported market price ranges and the trading volumes for the Trust Units for the periods indicated, as reported by the TSX.

	Price Range ($)
Period	High		Low		Trading Volume
January 14 to 31, 2005	$	19.25	$	18.22	6,530,482
February, 2005	$	20.99	$	18.55	6,436,468
March 1 to 28, 2005	$	21.49	$	18.75	3,755,500

RISK FACTORS

An investment in the Trust Units or securities exchangeable into Trust Units, such as the Exchangeable Shares, would be subject to certain risks.  Investors should carefully consider the following risk factors:

Dependence on the Administrator and Subsidiaries

The Trust is an open-end, limited purpose trust that is entirely dependent upon the operations and assets of its direct and indirect subsidiaries.  Accordingly, any cash distributions to the Unitholders are dependent upon (i) the ability of the Administrator to meet its interest and principal repayment obligations on the Administrator Notes, to declare and pay distributions or dividends on its common shares and to pay the NPI and (ii) the ability of Subtrust to distribute income to the Trust.  Income is received from the production of oil and natural gas from resource properties and is susceptible to the risks and uncertainties associated with the oil and natural gas industry generally. The Trust, through is subsidiaries, currently conducts oil and natural gas exploration and development activities.  If the Administrator is unsuccessful in these activities, the ability of the Administrator to meet its obligations to the Trust may be adversely affected.

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Exploration and Development

Exploration and development risks are due to the uncertain results of searching for and producing oil and natural gas using imperfect scientific methods. These risks are mitigated by using skilled staff, focusing exploration efforts in areas in which the Administrator and Subtrust have existing knowledge and expertise or access to such expertise, using up-to-date technology to enhance methods and controlling costs to maximize returns. Advanced oil and natural gas related technologies such as three-dimensional seismography and reservoir simulation studies have been used by the Administrator and may, if deemed appropriate, be used in the future to improve the ability of the Administrator and Subtrust to find, develop and produce oil and natural gas.

Operations

The operations of the Administrator and the Subtrust are subject to all of the risks normally incident to the operation and development of oil and natural gas properties and the drilling of oil and natural gas wells, including encountering unexpected formations or pressures, blow-outs, craterings and fires, all of which could result in personal injuries, loss of life and damage to the property of the Administrator, Subtrust and others. In particular, the Administrator and Subtrust explore for and produce sour natural gas in populated areas, including Northeastern British Columbia.  An unintentional leak of sour natural gas could result in personal injury, loss of life or damage to property and may necessitate an evacuation of populated areas, all of which could result in liability to the Administrator or Subtrust.  The Administrator and Substrust have safety and environmental policies in place to protect their operators and employees, as well as to meet the regulatory requirements in those areas where they operate. In addition, the Administrator and Subtrust have liability insurance policies in place, in such amounts as they consider adequate. The Administrator and Subtrust will not be fully insured against all of these risks, nor are all such risks insurable.  See “Risk Factors – Insurance”.

Continuing production from a property, and/or, to some extent the marketing of production therefrom, are largely dependent upon the ability of the operator of the property.  To the extent the operator fails to perform these functions properly, revenue may be reduced. Payments from production generally flow through the operator and there is a risk of delay and additional expense in receiving such revenues if the operator becomes insolvent. Although satisfactory title reviews are generally conducted in accordance with industry standards, such reviews do not guarantee or certify that a defect in the chain of title may not arise to defeat the claim of the Administrator or Subtrust to certain properties.  A reduction of the income from the NPI could result in such circumstances.

Oil and Natural Gas Prices

The price of oil and natural gas will fluctuate and price and demand are factors beyond the Trust’s control. These factors include demand for oil and natural gas, market fluctuations, the proximity and capacity of oil and natural gas pipelines and processing equipment and government regulations, including regulations relating to environmental protection, royalties, allowable production, pricing, importing and exporting of oil and natural gas.  Fluctuations in price will have a positive or negative effect on the revenue to be received by it. Such fluctuations will also have an effect on the acquisition costs of any future oil and natural gas properties that the Administrator or Subtrust may acquire.  As well, cash distributions from the Trust will be highly sensitive to the prevailing price of crude oil and natural gas.

Hedging

From time to time the Administrator and Subtrust may enter into agreements to receive fixed prices on their oil and natural gas production to offset the risk of revenue losses if commodity prices decline; however, if commodity prices increase beyond the levels set in such agreements, the Administrator and Subtrust will not benefit from such increases. Similarly, from time to time, the Administrator and Subtrust may enter into agreements to fix the exchange rate of Canadian to United States dollars in order to offset the risk of revenue losses if the Canadian dollar increases in value compared to the United States dollar; however, if the Canadian dollar declines in value compared to the United States dollar, the Administrator and Subtrust will not benefit from the fluctuating exchange rate. 

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Accordingly, the ability of the Administrator to meet its obligations to the Trust or Subtrust to distribute income to the Trust, and the Trust’s corresponding ability to make timely cash distributions to the Unitholders, may be adversely affected.

Capital Investment

The timing and amount of capital expenditures will directly affect the amount of income for distribution to Unitholders. Distributions may be reduced, or even eliminated, at times when significant capital or other expenditures are made.

Reserves

There are numerous uncertainties inherent in estimating quantities of oil, natural gas and natural gas liquids, reserves and cash flows to be derived therefrom, including many factors beyond the Trust’s control.  The reserve and associated cash flow information set forth herein represent estimates only.  In general, estimates of economically recoverable oil and natural gas reserves and the future net cash flows therefrom are based upon a number of variable factors and assumptions, such as historical production from the properties, production rates, ultimate reserve recovery, timing and amount of capital expenditures, marketability of oil and natural gas, royalty rates, the assumed effects of regulation by governmental agencies and future operating costs, all of which may vary from actual results.  All such estimates are to some degree speculative, and classifications of reserves are only attempts to define the degree of speculation involved.  For those reasons, estimates of the economically recoverable oil and natural gas reserves attributable to any particular group of properties, classification of such reserves based on risk of recovery and estimates of future net revenues expected therefrom prepared by different engineers, or by the same engineers at different times, may vary. The Trust’s actual production, revenues and development and operating expenditures with respect to its reserves will vary from estimates thereof and such variations could be material.

Estimates of proved reserves that may be developed and produced in the future are often based upon volumetric calculations and upon analogy to similar types of reserves rather than actual production history. Estimates based on these methods are generally less reliable than those based on actual production history. Subsequent evaluation of the same reserves based upon production history and production practices will result in variations in the estimated reserves and such variations could be material.

In accordance with applicable securities laws, the applicable independent reserves consultants have used both constant and forecast price and cost estimates in calculating reserve quantities for the Trust. Actual future net cash flows will be affected by other factors such as actual production levels, supply and demand for oil and natural gas, curtailments or increases in consumption by oil and natural gas purchasers, changes in governmental regulation or taxation and the impact of inflation on costs.

Actual production and cash flows derived therefrom will vary from the estimates contained in the applicable engineering reports. The reserve reports are based in part on the assumed success of activities the Trust intends to undertake in future years. The reserves and estimated cash flows to be derived therefrom contained in the engineering reports will be reduced to the extent that such activities do not achieve the level of success assumed in the engineering reports.

Declines in the reserves of the Administrator or Subtrust which are not offset by the acquisition or development of additional reserves may reduce the underlying value of Trust Units to Unitholders.

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Competition

The industry is highly competitive in the acquisition of exploration prospects and the development of new sources of production and the sale of oil and natural gas. The Trust’s competitors include oil and natural gas companies and trusts that have substantially greater financial resources, staff and facilities than those of the Trust. The Trust’s ability to increase reserves in the future will depend not only on its ability to explore and develop its present properties, but also on its ability to select and acquire suitable producing properties or prospects for exploratory drilling.  Competitive factors in the distribution and marketing of oil and natural gas include price and methods and reliability of delivery.

Environmental Concerns

The oil and natural gas industry is subject to environmental regulation pursuant to local, provincial and federal legislation. A breach of such legislation may result in the imposition of fines or issuance of clean-up orders in respect of the Administrator, Subtrust or their properties. Such legislation may be changed to impose higher standards and potentially more costly obligations on the Administrator and Subtrust.  There can be no assurance that the Trust will be able to satisfy its actual future environmental and reclamation obligations.

Insurance

The Trust’s involvement in the exploration for and development of oil and natural gas properties may result in the Trust or its subsidiaries, as the case may be, becoming subject to liability for pollution, blow-outs, property damage, personal injury or other hazards. Although prior to drilling, the Trust or its subsidiaries, as the case may be, will obtain insurance in accordance with industry standards to address certain of these risks, such insurance has limitations on liability that may not be sufficient to cover the full extent of such liabilities.  In addition, such risks may not in all circumstances be insurable or, in certain circumstances, the Trust or its subsidiaries, as the case may be, may elect not to obtain insurance to deal with specific risks due to the high premiums associated with such insurance or other reasons. The Trust currently does not possess business interruption insurance.  The payment of such uninsured liabilities would reduce the funds available to the Trust.  The occurrence of a significant event that the Trust is not fully insured against, or the insolvency of the insurer of such event, could have a material adverse effect on the Trust’s financial position, including, but not limited to, distributable cash, results of operations or prospects and will reduce income otherwise distributable to the Trust.

Delay in Cash Distributions

In addition to the usual delays in payment by purchasers of oil and natural gas to the operators of the properties, and by the operator to the Administrator or Subtrust, payments between any of such parties may also be delayed by restrictions imposed by lenders, delays in the sale or delivery of products, delays in the connection of wells to a gathering system, blowouts or other accidents, recovery by the operator of expenses incurred in the operation of the properties, or the establishment by the operator of reserves for such expenses.  Accordingly, the ability of the Administrator to meet its obligations to the Trust or Subtrust to distribute income to the Trust, and the Trust’s corresponding ability to make timely cash distributions to the Unitholders, may be adversely affected.

Depletion of Reserves

The Trust has certain unique attributes that differentiate it from many other oil and gas industry participants. Distributions of distributable cash by the Trust in respect of oil and natural gas properties, absent commodity price increases or cost effective acquisition and development activities, will decline over time in a manner consistent with declining production from typical oil, natural gas and natural gas liquids reserves.  Although the Administrator and Subtrust will reinvest a portion of their cash flow to fund their exploration and development programs, there can be no assurances that this will prevent a reduction in production and reserve levels.

The Administrator’s and Subtrust’s future oil and natural gas reserves and production, and therefore its cash flows,

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will be highly dependent on the Administrator’s and Subtrust’s success in its exploration and development projects, exploiting their reserve base and, if applicable, acquiring additional reserves. Without reserve additions through development or acquisition activities, the Administrator’s and Subtrust’s reserves and production will decline over time as reserves are depleted.

To the extent that external sources of capital, including the issuance of additional Trust Units, become limited or unavailable, the Administrator’s and Subtrust’s ability to make the necessary capital investments to maintain or expand their oil and natural gas reserves will be impaired.  To the extent that the Administrator and Subtrust are required to use cash flow to finance capital expenditures or property acquisitions, the level of distributable cash available for Unitholders may be reduced.

There can be no assurance that the Administrator and Subtrust will be successful in developing or acquiring additional reserves on terms that meet the Trust’s investment objectives.

Return of Capital

Trust Units will have no value when reserves from the Trust’s oil and gas properties can no longer be economically produced and, as a result, cash distributions do not represent a “yield” in the traditional sense and are not comparable to bonds or other fixed yield securities, where investors are entitled to a full return of the principal amount of debt on maturity in addition to a return on investment through interest payments.  Distributions represent a blend of return of Unitholders initial investment and a return on Unitholders initial investment.

Variations in Interest Rates and Foreign Exchange Rates

Variations in interest rates could result in a significant change in the amount the Trust pays to service debt, potentially impacting distributions to Unitholders.

In addition, the exchange rate for the Canadian dollar versus the U.S. dollar has increased significantly over the last 12 months, resulting in the receipt by the Trust of fewer Canadian dollars for its production which may affect future distributions. The increase in the exchange rate for the Canadian dollar and future Canadian/United States exchange rates may impact future distributions and the future value of the Trust’s reserves as determined by independent evaluators.

Distributions

Historical distribution payments of the Trust may not be reflective of future distribution payments, which will be subject to review by the Board of Directors taking into account the prevailing financial circumstances of the Administrator and Subtrust at the relevant time. The actual amount distributed, if any, is at the discretion of the Board of Directors.  Cash distributions by the Trust to Unitholders are not guaranteed.

Investment Eligibility and Mutual Fund Trust Status

It is intended that the Trust qualify at all times as a mutual fund trust for the purposes of the Tax Act. The Trust may not, however, always be able to satisfy any future requirement for the maintenance of mutual fund trust status. Should the status of the Trust as a mutual fund trust be lost or successfully challenged by a relevant tax authority, certain adverse consequences may arise for the Trust and Unitholders. Some of the significant consequences of losing mutual fund trust status are as follows:

•the Trust Units would cease to be a qualified investment for trusts governed by registered retirement savings plans (“RRSP”), registered retirement income funds (“RRIF”), deferred profit sharing plans (“DPSP”) and registered education savings plans (“RESP”) (collectively, “Exempt Plans”) under the Tax Act.  Where, at the end of a month, an Exempt Plan holds Trust Units that ceased to be a qualified investment, the Exempt

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Plan, must, in respect of that month, pay a tax under Part XI.1 of the Tax Act equal to 1% of the fair market value of the Trust Units at the time such Trust Units were acquired by the Exempt Plan.  In addition, trusts governed by an RRSP or an RRIF which hold Trust Units that are not qualified investments will be subject to tax on the income attributable to the Trust Units while they are non-qualified investments, including the full capital gains, if any, realized on the disposition of such Trust Units.  Where a trust governed by a RRSP or a RRIF acquires Trust Units that are not qualified investments, the value of the investment will be included in the income of the annuitant for the year of the acquisition. Trusts governed by RESPs which hold Trust Units that are not qualified investments can have their registration revoked by the CRA;

•Trust Units would become foreign property for Exempt Plans, registered pension plans and other persons subject to tax under Part XI of the Tax Act upon the Trust ceasing to be a mutual fund trust;

•the Trust would be required to pay a tax under Part XII.2 of the Tax Act. The payment of Part XII.2 tax by the Trust may have adverse income tax consequences for certain Unitholders, including non-resident persons and residents of Canada who are exempt from Part I tax;

•the Trust would cease to be eligible for the capital gains refund mechanism available under Canadian tax laws; and

•Trust Units would become taxable Canadian property. As a result, non-resident Unitholders would be subject to Canadian income tax on any gains realized on a disposition of Trust Units held by them.

In addition, the Trust may take certain measures in the future to the extent the Trust believes such measures are necessary to ensure the Trust maintains its status as a mutual fund trust. These measures could be adverse to certain Unitholders.

Non-Resident Ownership of Trust Units

In order for the Trust to maintain its status as a mutual fund trust under the Tax Act, the Trust must not be established or maintained primarily for the benefit of Non-Residents. The Trust Indenture provides that if at any time the Trust or the Administrator becomes aware that the beneficial owners of 40% or more of the Trust Units then outstanding are or may be Non-Residents or that such a situation is imminent, the Trust, by or through the Administrator on the Trust’s behalf, shall take such action as may be necessary to carry out the foregoing intention. These measures could be adverse to certain Unitholders and may not be effective to avoid the Trust losing its status as a mutual fund trust for the purposes of the Tax Act.

Proposed amendments to the Tax Act originally published by the Minister of Finance on March 22, 2004 were to provide that, after December 31, 2004, the Trust must continuously ensure that not more than 50% of its issued Trust Units are held by non-residents of Canada or partnerships (other than “Canadian partnerships” as defined in the Tax Act). These proposals were not included in the Notice of Ways and Means Motion tabled by the Minister of Finance on December 6, 2004 and the Minister of Finance has indicated that further discussions are to be held with the private sector on the appropriate tax treatment for Non-Residents investing in resource property through mutual funds.

Income Tax Matters

Generally, oil and gas income trusts including the Trust involve significant amounts of inter-company debt, royalties or similar instruments, generating substantial interest expense or other deductions which serve to reduce taxable income and income tax payable. There can be no assurance that the taxation authorities will not seek to challenge the amount of interest expense and other deductions. If such a challenge were to succeed against the Trust or the Administrator, it could materially adversely affect the amount of distributions available to the Trust. The Trust and the Administrator believe that the interest expense inherent in the structure of the Trust is supportable and reasonable

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in light of the terms of the Administrator Notes.

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Changes in Legislation and Administrative Practices

There can be no assurances that income tax laws and government incentive programs relating to mutual fund trusts and to the oil and gas industry will not be changed in a manner which materially adversely affects the Trust and the Unitholders (see the discussion under the heading “Risk Factors - Non-Resident Ownership of Trust Units”). There can be no assurance that the CRA will agree with how the Trust calculates its income for tax purposes or that the CRA will not change its administrative practices to the detriment of the Trust or the Unitholders.

Nature of Trust Units

The Trust Units do not represent a traditional investment in the oil and natural gas sector and should not be viewed by investors as “shares” in the Trust.  The Trust Units represent a fractional interest in the Trust.  As holders of Trust Units, Unitholders have substantially all of the same protections, rights and remedies as a shareholder would have under the Canada Business Corporations Act, except a Unitholder will not have the statutory rights normally associated with ownership of shares of a corporation, including, for example, the right to bring “oppression” or “derivative” actions.  A Unitholder is also not entitled to “dissent rights”.

Unitholders may not be protected from liabilities of the Trust to the same extent as a shareholder is protected from the liabilities of a corporation.  Unlike many other royalty trusts, the structure of the Trust does not include the interposition of a limited liability entity such as a corporation or limited partnership between the Trust and Subtrust which would provide further limited liability protection to Unitholders between the assets and Subtrust.

The Trust’s sole assets are the NPI, the Administrator Notes, the common shares of the Administrator, its beneficial interest in Subtrust and other investments in securities.  The price per Trust Unit is a function of anticipated income available for distributions, the oil and natural gas assets held by the Administrator and Subtrust and the Administrator’s and Subtrust’s ability to effect long-term growth in the value of the Trust. The market price of the Trust Units will be sensitive to a variety of market conditions, including, but not limited to, interest rates and the ability of the Trust to acquire suitable oil and natural gas properties.  Changes in market conditions may adversely affect the trading price of the Trust Units.

Neither the Trust Units nor the Debentures are “deposits” within the meaning of the Canada Deposit Insurance Corporation Act (Canada) and are not insured under the provisions of that Act or any other legislation.  Furthermore, the Trust is not a trust company and, accordingly, is not registered under any trust and loan company legislation as it does not carry on or intend to carry on the business of a trust company.

Debt Service

The Administrator has a $125 million demand revolving operating credit facility (the “Credit Facility”) with Bank of Montreal pursuant to a letter agreement dated January 6, 2005.  As at March 22, 2005, a total of $99.5 million was outstanding under the Credit Facility. Variations in interest rates and scheduled principal repayments or the need to refinance the Credit Facility upon expiration could result in significant changes in the amount required to be applied to debt service before payment of any amounts to the Trust.

Although it is believed that the Credit Facility is sufficient, there can be no assurance that the amount will be adequate for the financial obligations of the Administrator, that additional funds can be obtained or that, upon expiration, the Credit Facility can be refinanced on terms acceptable to the Trust and the lender.

Amounts outstanding under the Credit Facility are secured by a first charge in favour of Bank of Montreal over all assets and undertakings of the Administrator and Subtrust and have been guaranteed by the subsidiaries of the Administrator. If the Administrator or Subtrust becomes unable to pay its debt service charges or otherwise commits an event of default such as bankruptcy, the lenders may foreclose on or sell the properties free from or together with the NPI.

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Also the Trust, the Trustee, the Administrator, the Partnership, Subtrust and Bank of Montreal have entered into a an amended and restated subordination agreement dated February 3, 2005 (the “Subordination Agreement”).  Pursuant to the Subordination Agreement, any and all present and future indebtedness of Subtrust, the Administrator or any of its subsidiaries to the Trust, including under the NPI or the Administrator Notes, is made subordinate to the repayment of amounts owing under the Credit Facility.

Under the Credit Facility and Subordination Agreement, the Trust, the Administrator, Subtrust and their subsidiaries are restricted from making distributions when (i) a default or event of default under the Credit Facility has occurred and is continuing, (ii) outstanding loans under the Credit Facility exceed the borrowing base set by the lender thereunder until such time as such outstanding loans are reduced below the borrowing base, or (iii) a distribution would exceed the net income of the entity for the applicable period after deducting cash taxes paid and scheduled principal and interest payments.

The terms of the Credit Facility and the Subordination Agreement ensure that Bank of Montreal has priority over the Unitholders with respect to the assets and income of the Trust.  Amounts due and owing to Bank of Montreal under the Credit Facility must be paid before any distribution can be made to Unitholders.  This could result in an interruption of distributions.

Redemption Right

Unitholders have a limited right to require the Trust to repurchase their Trust Units, which is referred to as a redemption right. It is anticipated that the redemption right will not be the primary mechanism for Unitholders to liquidate their investments.  Administrator Notes or Redemption Notes (as defined in the Trust Indenture) which may be distributed in specie to Unitholders in connection with a redemption will not be listed on any stock exchange and no established market is expected to develop for such Administrator Notes or Redemption Notes.  Cash redemptions are subject to limitations.

Unitholder Limited Liability

The Trust Indenture provides that no Unitholder will be subject to any liability in connection with the Trust or its obligations and affairs and, in the event that a court determines Unitholders are subject to any such liabilities, the liabilities will be enforceable only against, and will be satisfied only out of the Trust’s assets. Pursuant to the Trust Indenture, the Trust will indemnify and hold harmless each Unitholder from any costs, damages, liabilities, expenses, charges and losses suffered by a Unitholder resulting from or arising out of such Unitholder not having such limited liability.

Permitted Investments

An investment in the Trust should be made with the understanding that the value of any Permitted Investments may fluctuate in accordance with changes in the financial condition of the issuers of the Permitted Investments, the value of similar securities, and other factors. For example, the prices of Canadian government securities, bankers’ acceptances and commercial paper react to economic developments and changes in interest rates.  Commercial paper is also subject to issuer credit risk. Other Permitted Investments in energy related income trusts, companies and partnerships will be subject to the general risks of investing in equity securities.  These include the risk that the financial condition of issuers may become impaired, or that the energy sector may suffer a market downturn. Securities markets in general are affected by a variety of factors, including governmental, environmental, and regulatory policies, inflation and interest rates, economic cycles, and global, regional and national events.  The value of Trust Units could be affected by adverse changes in the market values of Permitted Investments.

Regulatory Matters

The operations of the Administrator and Subtrust are subject to a variety of federal and provincial laws and regulations, including income tax laws and laws and regulations relating to the protection of the environment. The

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operations of the Administrator and Subtrust may require licenses from various governmental authorities. There can be no assurance that the Administrator and Subtrust will be able to obtain all necessary licenses and permits that may be required to carry out exploration and development at their projects.

Kyoto Protocol

In 1994, the United Nations’ Framework Convention on Climate Change came into force and three years later led to the Kyoto Protocol which will require nations to reduce their emissions of carbon dioxide and other greenhouse gases. In December 2002, the Government of Canada ratified and signed the Kyoto Protocol.  The Kyoto Protocol has now come into effect. As a result of the ratification of the Kyoto Protocol and the adoption of legislation or other regulatory initiatives designed to implement its objectives by the federal or provincial governments, reductions in greenhouse gases from crude oil and natural gas producers may be required which could result in, among other things, increased operating and capital expenditures for those producers (including the Trust) which may make certain production of crude oil and natural gas by those producers uneconomic resulting in reductions in such production. Until such legislation or other regulatory initiatives are finalized, the impact of the Kyoto Protocol and any such legislation adopted as a result of its ratification remains uncertain. The direct or indirect costs of such legislation or regulatory initiatives may adversely affect the business of the Administrator and Subtrust.

Possible Failure to Realize Anticipated Benefits of Acquisitions

The Trust and StarPoint, prior to the Arrangement, have completed a number of acquisitions to strengthen the Trust’s position in the oil and natural gas industry and to create the opportunity to realize certain benefits including, among other things, potential cost savings. Achieving the benefits of these and any future acquisitions depends, in part, on successfully consolidating functions and integrating operations, procedures and personnel in a timely and efficient manner, as well as the Trust’s ability to realize the anticipated growth opportunities and synergies from combining the acquired businesses and operations with those of the Administrator or Subtrust.  The integration of acquired businesses requires the dedication of substantial management effort, time and resources which may divert management’s focus and resources from other strategic opportunities and from operational matters during this process. The integration process may result in the loss of key employees and the disruption of ongoing business, customer and employee relationships that may adversely affect the Trust’s ability to achieve the anticipated benefits of these and future acquisitions.

LEGAL PROCEEDINGS

There are no outstanding legal proceedings material to the Trust to which the Trust or the Administrator is a party or in respect of which any of their respective properties are subject, nor are there any such proceedings known to the Trust or the Administrator to be contemplated.

INTEREST OF MANAGEMENT AND OTHERS IN MATERIAL TRANSACTIONS

Except as may be disclosed elsewhere in this Annual Information Form or in the documents incorporated by reference herein, none of the directors, officers or principal shareholders of the Trust or the Administrator and no associate or affiliate of any of them, has or has had any material interest in any transaction or any proposed transaction which materially affects the Trust, the Administrator or any of their affiliates.

AUDITORS, TRANSFER AGENT AND REGISTRAR

The auditors of the Trust are KPMG LLP, Chartered Accountants, Suite 1200, 205 - 5th Avenue S.W., Calgary, Alberta, T2P 4B9.

The transfer agent and registrar for the Trust Units and Exchangeable Shares is Olympia Trust Company at its principal offices in Calgary, Alberta and at the principal offices of its agent in Toronto, Ontario.

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MATERIAL CONTRACTS

The following contracts, copies of which are available under the profile of the Trust on www.sedar.com, were entered into within the last completed financial year and may be considered to be material to the Trust:

(a)the Trust Indenture;

(b)the Administrator Note Indenture;

(c)the Administration Agreement;

(d)the Support Agreement;

(e)the Voting and Exchange Trust Agreement;

(f)the Trust’s restricted unit plan;

(g)the DRIP Plan;

(h)the letter agreement dated January 6, 2005 between the Administrator and Bank of Montreal concerning the Credit Facility; and

(i)the Subordination Agreement.

Each of the above agreement or documents are described elsewhere in this Annual Information Form, with the exception of the Trust’s restricted unit plan.  The restricted unit plan authorizes the Trust to grant restricted Trust Units to certain directors, officers, consultants or employees of the Trust or any of its subsidiaries which will vest over time and which, upon vesting, may be redeemed by the holder for cash or Trust Units.  The restricted unit plan is an alternative to the non-discretionary incentive bonus plans and unit right incentive plans employed by many other trusts.

INTEREST OF EXPERTS

Reserve estimates contained in this Annual Information Form have been prepared by Sproule Associates Limited.   As at December 31, 2004, the effective date of those estimates, and as at the date of this Annual Information Form, the principals, directors, officers and associates of Sproule Associates Limited, as a group, owned, directly or indirectly, less than 1% of the outstanding Trust Units.

The auditors of the Trust are KPMG LLP, Chartered Accountants.  The partners and associates of KPMG LLP do not own, directly or indirectly, any securities of the Trust.

ADDITIONAL INFORMATION

Additional information concerning the Trust may be found under the Trust’s profile on SEDAR at www.sedar.com. Additional financial information is provided in the Trust’s comparative financial statements and management’s discussion and analysis for the period ended December 31, 2004.

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SCHEDULE “A” — REPORTS ON RESERVES DATA BY SPROULE ASSOCIATES LIMITED

Form 51-101F2

Report on Reserves Data
by Independent Qualified Reserves Evaluator or Auditor

Report on Reserves Data

To the Board of Directors of Starpoint Energy Ltd. (the “Company”):

1.We have evaluated the Company’s Reserves Data as at December 31, 2004. The reserves data consist of the following:

(a)(i)proved and proved plus probable oil and gas reserves estimated as at December 31, 2004 using forecast prices and costs; and

(ii)the related estimated future net revenue; and

(b)(i)proved oil and gas reserve quantities were estimated as at December 31, 2004 using constant prices and costs; and

(ii)the related estimated future net revenue.

2.The Reserves Data are the responsibility of the Company’s management.  Our responsibility is to express an opinion on the Reserves Data based on our evaluation.

We carried out our evaluation in accordance with standards set out in the Canadian Oil and Gas Evaluation Handbook (the “COGE Handbook”), prepared jointly by the Society of Petroleum Evaluation Engineers (Calgary Chapter) and the Canadian Institute of Mining, Metallurgy & Petroleum (Petroleum Society).

Starpoint Energy Ltd.

Sproule Associates Limited

3.Those standards require that we plan and perform an evaluation to obtain reasonable assurance as to whether the reserves data are free of material misstatement. An evaluation also includes assessing whether the reserves data are in accordance with principles and definitions presented in the COGE Handbook.

4The following table sets forth the estimated future net revenue attributed to proved plus probable reserves, estimated using forecast prices and costs on a before tax basis and calculated using a discount rate of 10%, included in the reserves data of the Company evaluated by us as of December 31, 2004, and identifies the respective portions thereof that we have audited, evaluated and reviewed and reported on to the Company’s management and Board of Directors:

Independent Qualified Reserves Evaluator or	Description and Preparation Date	Location of Reserves	Net Present Value of Future Net Revenue (10% Discount Rate)
Auditor	of Evaluation Report	(Country)	Audited	Evaluated	Reviewed	Total
			(M$)	(M$)	(M$)	(M$)
Sproule	Evaluation of the P&NG Reserves of Starpoint Energy, as of December 31, 2004 prepared September 2004 to February 2005	Canada and U.S.
Total			Nil	281,592	Nil	281,592

5.In our opinion, the reserves data evaluated by us have, in all material respects, been determined and are presented in accordance with the COGE Handbook.

6.We have no responsibility to update the report referred to in paragraph 4 for events and circumstances occurring after its preparation date.

7.Because the reserves data are based on judgements regarding future events, actual results will vary and the variations may be material.

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Executed as to our report referred to above:

Sproule Associates Limited
Calgary, Alberta
February 24, 2005

/s/ Robert N. Johnson

Robert N. Johnson, P.Eng.
Project Leader;
Manager, Engineering, and

Corporate Secretary

/s/ Michael W. Maughan

Michael W. Maughan, C.P.G., P.Geol.
Manager, Geoscience, and Associate

/s/ Harry J. Helwerda

Harry J. Helwerda, P.Eng.
Vice-President, Engineering,

Canada and U.S.

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Form 51-101F2

Report on Reserves Data
by Independent Qualified Reserves Evaluator or Auditor

Report on Reserves Data

To the Board of Directors of StarPoint Energy Ltd. (the “Company”):

1.We have evaluated the Company’s Reserves Data as at December 31, 2004. The reserves data consist of the following:

(a)(i)proved and proved plus probable oil and gas reserves estimated as at December 31, 2004 using forecast prices and costs; and

(ii)the related estimated future net revenue; and

(b)(i)proved oil and gas reserve quantities were estimated as at December 31, 2004 using constant prices and costs; and

(ii)the related estimated future net revenue.

2.The Reserves Data are the responsibility of the Company’s management.  Our responsibility is to express an opinion on the Reserves Data based on our evaluation.

We carried out our evaluation in accordance with standards set out in the Canadian Oil and Gas Evaluation Handbook (the “COGE Handbook”), prepared jointly by the Society of Petroleum Evaluation Engineers (Calgary Chapter) and the Canadian Institute of Mining, Metallurgy & Petroleum (Petroleum Society).

StarPoint Energy Ltd.

Sproule Associates Limited

3.Those standards require that we plan and perform an evaluation to obtain reasonable assurance as to whether the reserves data are free of material misstatement. An evaluation also includes assessing whether the reserves data are in accordance with principles and definitions presented in the COGE Handbook.

4.The following table sets forth the estimated future net revenue attributed to proved plus probable reserves, estimated using forecast prices and costs on a before tax basis and calculated using a discount rate of 10%, included in the reserves data of the Company evaluated by us as of December 31, 2004, and identifies the respective portions thereof that we have audited, evaluated and reviewed and reported on to the Company’s management and Board of Directors:

Independent Qualified Reserves Evaluator or	Description and Preparation Date	Location of Reserves	Net Present Value of Future Net Revenue (10% Discount Rate)
Auditor	of Evaluation Report	(Country)	Audited	Evaluated		Reviewed	Total
			(M$)	(M$)		(M$)	(M$)
Sproule	Evaluation of the P&NG Reserves of Starpoint Energy Ltd., as of December 31, 2004 prepared January and February 2005	Canada
Total			Nil	$	49,318	Nil	$	49,318

5.In our opinion, the reserves data evaluated by us have, in all material respects, been determined and are presented in accordance with the COGE Handbook.

6.We have no responsibility to update the report referred to in paragraph 4 for events and circumstances occurring after its preparation date.

7.Because the reserves data are based on judgements regarding future events, actual results will vary and the variations may be material.

2

Executed as to our report referred to above:

Sproule Associates Limited
Calgary, Alberta
February 23, 2005

/s/ Matthew J. O’Blenes

Matthew J. O’Blenes, P.Eng.
Project Leader and Associate

/s/ Michael W. Maughan

Michael W. Maughan, C.P.G., P.Geol.
Manager, Geoscience, and Associate

/s/ Robert N. Johnson

Robert N. Johnson P.Eng.
Manager, Engineering, and
Corporate Secretary

3

SCHEDULE “B” – REPORT OF MANAGEMENT AND DIRECTORS ON RESERVES DATA

Report of Management and Directors
On Reserves Data and Other Information

(Form 51-101F3)

Terms to which a meaning is ascribed in National Instrument 51-101 have the same meaning in this herein.

Management of StarPoint Energy Ltd. (the “Administrator”), as the duly appointed administrator of StarPoint Energy Trust (the “Trust”), are responsible for the preparation and disclosure of information with respect to the Trust’s oil and gas activities in accordance with securities regulatory requirements. This information includes reserves data, which consist of the following:

(a)(i)proved and proved plus probable oil and gas reserves estimated as at December 31, 2003 using forecast prices and costs; and

(ii)the related estimated future net revenue; and

(b)(i)proved oil and gas reserves estimated as at December 31, 2003 using constant prices and costs; and

(ii)the related estimated future net revenue.

Independent qualified reserves evaluators have evaluated and reviewed the Trust’s reserves data. The report of the independent qualified reserves evaluators will be filed with securities regulatory authorities concurrently with this report.

The Reserves Committee of the board of directors of the Administrator has:

(a)reviewed the Administrator’s procedures for providing information to the independent qualified reserves evaluators;

(b)met with the independent qualified reserves evaluators to determine whether any restrictions affected the ability of the independent qualified reserves evaluators to report without reservation; and

(c)reviewed the reserves data with management and independent qualified reserves evaluators.

The Reserves Committee of the board of directors has reviewed the Administrator’s procedures for assembling and reporting other information associated with oil and gas activities and has reviewed that information with management. The board of directors has, on the recommendation of the Reserves Committee, approved

(a)the content and filing with securities regulatory authorities of the reserves data and other oil and gas information;

(b)the filing of the report of the independent qualified reserves evaluators on the reserve data; and

(c)the content and filing of this report.

Because the reserves data are based on judgments regarding future events, actual results will vary and the variations may be material.

(signed) “Paul Colborne”

Paul Coborne

President and Chief Executive Officer

(signed) “Murray Mason”

Murray Mason

Vice President, Production

(signed) “Fred Coles”

Fred Coles

Director

(signed) “Paul Starnino”

Paul Starnino

Director

March 24, 2005

SCHEDULE “C” – AUDIT COMMITTEE CHARTER

AUDIT COMMITTEE CHARTER

Policy Statement

It is the policy of StarPoint Energy Ltd. (the “Corporation”), as the duly appointed administrator of StarPoint Energy Trust (the “Trust”), to establish and maintain an Audit Committee, composed entirely of independent directors, to assist the Board of Directors (the “Board”) in carrying out their oversight responsibility for the Trust’s internal controls, financial reporting and risk management processes. The Audit Committee will be provided with resources commensurate with the duties and responsibilities assigned to it by the Board including administrative support.  If determined necessary by the Audit Committee, it will have the discretion to institute investigations of improprieties, or suspected improprieties within the scope of its responsibilities, including the standing authority to retain special counsel or experts.

Composition of the Committee

1.The Audit Committee shall consist of a minimum of three directors. The Board shall appoint the members of the Audit Committee. The Board shall appoint one member of the Audit Committee to be the Chair of the Audit Committee.

2.Each director appointed to the Audit Committee by the Board must be independent. A director is independent if the director has no direct or indirect material relationship with the Trust or the Corporation.  A material relationship means a relationship which could, in the view of the Board, reasonably interfere with the exercise of the director’s independent judgment. In determining whether a director is independent of management, the Board shall make reference to the then current legislation, rules, policies and instruments of applicable regulatory authorities.

3.Each member of the Audit Committee shall be “financially literate”. In order to be financially literate, a director must be, at a minimum, able to read and understand financial statements that present a breadth and complexity of accounting issues generally comparable to the breadth and complexity of issues expected to be raised by the Trust’s financial statements.

4.A director appointed by the Board to the Audit Committee shall be a member of the Audit Committee until replaced by the Board or until his or her resignation.

Meetings of the Committee

1.The Audit Committee shall convene a minimum of four times each year at such times and places as may be designated by the Chair of the Audit Committee and whenever a meeting is requested by the Board, a member of the Audit Committee, the auditors, or a senior officer of the Corporation. Meetings of the Audit Committee shall correspond with the review of the quarterly financial statements and management discussion and analysis of the Trust.

2.Notice of each meeting of the Audit Committee shall be given to each member of the Audit Committee and to the auditors, who shall be entitled to attend each meeting of the Audit Committee and shall attend whenever requested to do so by a member of the Audit Committee.

3.Notice of a meeting of the Audit Committee shall:

(a)be in writing;

(b)state the nature of the business to be transacted at the meeting in reasonable detail;

(c)to the extent practicable, be accompanied by copies of documentation to be considered at the meeting; and

(d)be given at least two business days prior to the time stipulated for the meeting or such shorter period as the members of the Audit Committee may permit.

4.A quorum for the transaction of business at a meeting of the Audit Committee shall consist of a majority of the members of the Audit Committee. However, it shall be the practice of the Audit Committee to require review, and, if necessary, approval of certain important matters by all members of the Audit Committee.

5.A member or members of the Audit Committee may participate in a meeting of the Audit Committee by means of such telephonic, electronic or other communication facilities, as permits all persons participating in the meeting to communicate adequately with each other. A member participating in such a meeting by any such means is deemed to be present at the meeting.

6.In the absence of the Chair of the Audit Committee, the members of the Audit Committee shall choose one of the members present to be Chair of the meeting. In addition, the members of the Audit Committee shall choose one of the persons present to be the Secretary of the meeting.

7.The Chairman of the Board, senior management of the Corporation and other parties may attend meetings of the Audit Committee; however the Audit Committee (i) shall meet with the external auditors independent of management as necessary, in the sole discretion of the Committee, but in any event, not less than quarterly; and (ii) may meet separately with management.

8.Minutes shall be kept of all meetings of the Audit Committee and shall be signed by the Chair and the Secretary of the meeting.

Duties and Responsibilities of the Committee

1.The Audit Committee’s primary duties and responsibilities are to:

(a)identify and monitor the management of the principal risks that could impact the financial reporting of the Trust;

(b)monitor the integrity of the Trust’s financial reporting process and system of internal controls regarding financial reporting and accounting compliance;

(c)monitor the independence and performance of the Trust’s external auditors;

(d)deal directly with the external auditors to approve external audit plans, other services (if any) and fees;

(e)directly oversee the external audit process and results and resolve any disagreements between management and the external auditor regarding financial reporting;

(f)provide an avenue of communication among the external auditors, management and the Board; and

(g)ensure that an effective “whistle blowing” procedure exists to permit stakeholders to express any concerns regarding accounting or financial matters to an appropriately independent individual.

2.The Audit Committee shall have the authority to:

(a)inspect any and all of the books and records of the Trust, the Corporation, their subsidiaries and affiliates;

(b)discuss with the management and senior staff of the Trust, the Corporation, their subsidiaries and affiliates, any affected party and the external auditors, such accounts, records and other matters as any member of the Audit Committee considers necessary and appropriate;

(c)engage independent counsel and other advisors as it determines necessary to carry out its duties; and

(d)to set and pay the compensation for any advisors employed by the Audit Committee.

3.The Audit Committee shall, at the earliest opportunity after each meeting, report to the Board the results of its activities and any reviews undertaken and make recommendations to the Board as deemed appropriate.

4.The Audit Committee shall:

(a)evaluate the independence and performance of the external auditors and annually recommend to the Board the appointment of the external auditor and the compensation of the external auditors;

(b)consider the recommendations of management in respect of the appointment of the external auditors;

(c)review the audit plan with the Trust’s external auditors and with management;

(d)discuss with management and the external auditors any proposed changes in major accounting policies or principles, the presentation and impact of significant risks and uncertainties and key estimates and judgments of management that may be material to financial reporting;

(e)review with management and with the external auditors significant financial reporting issues arising during the most recent fiscal period and the resolution or proposed resolution of such issues;

(f)review and resolve any problems experienced or concerns expressed by the external auditors in performing an audit, including any restrictions imposed by management or significant accounting issues on which there was a disagreement with management;

(g)review with senior management the process of identifying, monitoring and reporting the principal risks affecting financial reporting;

(h)consider and review with management, the internal control memorandum or management letter containing the recommendations of the external auditors and management’s response, if any, including an evaluation of the adequacy and effectiveness of the internal financial controls of the Trust and subsequent follow-up to any identified weaknesses;

(i)review, and if appropriate, recommend for approval by the Board, the audited annual financial statements, management discussion and analysis and related documents in conjunction with the report of the external auditors;

(j)review, and if appropriate, recommend for approval by the Board, the quarterly unaudited financial statements and management discussion and analysis;

(k)before release, review and if appropriate, recommend for approval by the Board, all public disclosure documents containing audited or unaudited financial information, including annual and quarterly financial statements, management discussion and analysis,  annual reports, annual information forms and press releases;

(l)oversee any of the financial affairs of the Trust, the Corporation, their subsidiaries and affiliates, and, if deemed appropriate, make recommendations to the Board, external auditors or management;

(l)pre-approve all non-audit services to be provided to the Trust, the Corporation, their subsidiaries and affiliates by the external auditors;

(m)approve the engagement letter for non-audit services to be provided by the external auditors or affiliates, together with estimated fees, and considering the potential impact of such services on the independence of the external auditors;

(n)when there is to be a change of external auditors, review all issues and provide documentation related to the change, including the information to be included in the Change of Auditors Notice and documentation required pursuant to National Instrument 51-102 (or any successor legislation) and the planned steps for an orderly transition period;

(o)review all reportable events, including disagreements, unresolved issues and consultations, as defined by applicable securities laws, on a routine basis, whether or not there is to be a change of external auditors; and

(p)review with management at least annually, the financing strategy and plans of the Trust.

5.The Audit Committee shall review the amount and terms of any insurance to be obtained or maintained by the Corporation with respect to risks inherent in its operations and potential liabilities incurred by the directors or officers in the discharge of their duties and responsibilities.

6.The Audit Committee shall review the appointments of the Chief Financial Officer and any key financial managers who are involved in the financial reporting process.

7.The Audit Committee shall enquire into and determine the appropriate resolution of any conflict of interest in respect of audit or financial matters, which are directed to the Audit Committee by any member of the Board, a securityholder of the Trust or the Corporation, the external auditors, or senior management.

8.The Audit Committee shall periodically review with management the need for an internal audit function.

9.The Audit Committee shall review the Trust’s accounting and reporting of environmental costs, liabilities and contingencies.

10.The Audit Committee shall establish and maintain procedures for:

(a)the receipt, retention and treatment of complaints received by the Trust or Corporation regarding accounting controls, or auditing matters; and

(b)the confidential, anonymous submission by employees of the Trust or Corporation of concerns regarding questionable accounting or auditing matters.

11.The Audit Committee shall review and approve the Corporation’s hiring policies regarding employees and former employees of the present and former external auditors or auditing matters.

12.The Audit Committee shall review with the Corporation’s legal counsel as required but at least annually, any legal matter that could have a significant impact on the Corporation’s financial statements, and any enquiries received from regulators, or government agencies.

13.The Audit Committee shall assess, on an annual basis, the adequacy of this Mandate and the performance of the Audit Committee.