Exhibit 99.84

A copy of this preliminary short form prospectus has been filed with the securities regulatory authorities in each of the provinces of Canada, but has not yet become final for the purpose of the sale of securities. Information contained in this preliminary short form prospectus may not be complete and may have to be amended.  The securities may not be sold until a receipt for the short form prospectus is obtained from the securities regulatory authorities.

This short form prospectus constitutes a public offering of these securities only in those jurisdictions where they maybe lawfully offered for sale and therein only by persons permitted to sell such securities. No securities regulatory authority has expressed an opinion about these securities and it is an offence to claim otherwise. These securities have not been and will not be registered under the United States Securities Act of 1933, as amended (the “U.S. Securities Act”), and may not be offered or sold in the United States except in transactions exempt from the registration requirements of the U.S. Securities Act.  Accordingly, this short form prospectus does not constitute an offer to sell, or a solicitation of an offer to buy, any of these securities within the United States.  See “Plan of Distribution”.

PRELIMINARY SHORT FORM PROSPECTUS

New Issue  May 11, 2005

STARPOINT ENERGY TRUST

$295,200,000

16,400,000 Subscription Receipts,
each representing the right to receive one Trust Unit

Price: $18.00 per Subscription Receipt

$60,000,000

6.50% Convertible Extendible Unsecured Subordinated Debentures

Price: $1,000 per Debenture

Subscription Receipts

This short form prospectus qualifies for distribution 16,400,000 subscription receipts (“Subscription Receipts”) of StarPoint Energy Trust (the “Trust”) at a price of $18.00 per Subscription Receipt (the “Offering Price”).  Each Subscription Receipt will entitle the holder thereof to receive, without payment of additional consideration, one trust unit (“Trust Unit”) of the Trust upon closing of the acquisition (the “EnCana Acquisition”) by the Trust of certain petroleum and natural gas properties and related assets currently owned indirectly by EnCana Corporation.  The proceeds from the sale of the Subscription Receipts (the “Escrowed Funds”) will be held by Olympia Trust Company, as escrow agent (the “Escrow Agent”), and invested in short-term obligations of, or guaranteed by, the Government of Canada (and other approved investments) pending completion of the EnCana Acquisition. Upon the EnCana Acquisition being completed on or before 5:00 p.m.  (Calgary time) on July 31, 2005, the Escrowed Funds and the interest thereon will be released to the Trust and each holder of Subscription Receipts will receive one (1) Trust Unit for each Subscription Receipt held. The Trust will utilize the Escrowed Funds to pay a portion of the purchase price for the EnCana Acquisition.

If the closing of the EnCana Acquisition does not take place by 5:00 p.m. (Calgary time) on July 31, 2005, if the EnCana Acquisition is terminated at any earlier time or if the Trust has advised the underwriters of this offering or announced to the public that it does not intend to proceed with the EnCana Acquisition (in any case, the “Termination Time”), holders of Subscription Receipts shall be entitled to receive an amount equal to the full subscription price therefor and their pro rata entitlements to interest on such amount.  The Escrowed Funds will be applied towards payment of such amount.

If the closing of the EnCana Acquisition takes place by 5:00 p.m. (Calgary time) on July 31, 2005 and holders of Subscription Receipts become entitled to receive Trust Units, such holders shall be entitled to receive an amount per Subscription Receipt equal to the amount per Trust Unit of any cash distributions for which record dates have occurred during the period from and including May 24, 2005 to and including the date immediately preceding the date the Trust Units are issued pursuant to the Subscription Receipts.  Any entitlement of a holder of Subscription Receipts to interest earned on the Escrowed Funds shall form part of such payment and shall not be in addition to such payment.  Accordingly, if the offering of the Subscription Receipts hereunder closes and if the closing of the EnCana Acquisition occurs on or before July 31, 2005, holders of Subscription Receipts of record on the date the Trust Units are issued pursuant to the Subscription Receipts will be entitled to receive: (i) at the time the Trust Units are issued pursuant to the Subscription Receipts, a payment equal to the distribution of $0.20 per Trust Unit that will be paid by the Trust on June 15, 2005 to holders of Trust Units (“Unitholders”) of record on May 24, 2005, (ii) at the time the Trust Units are issued pursuant to the Subscription Receipts, a payment equal to any distribution that has been paid by the Trust to Unitholders of record on each Trust distribution record date (being on or about the 22^nd day of each month) subsequent to May 24, 2005 and prior to the closing of the EnCana Acquisition, and (iii) at the time of payment to the Unitholders, a payment equal to any distribution that is payable by the Trust to Unitholders of record on each Trust distribution record date, other than those referred in items (i) or (ii), that occurs prior to the closing of the EnCana Acquisition. In addition, if the EnCana Acquisition closes on June 30, 2005, as currently contemplated, holders of Subscription Receipts will become Unitholders on June 30, 2005 and will be entitled, provided they remain Unitholders on July 22, 2005, to receive the monthly distribution expected to be paid on August 15, 2005 to Unitholders of record on July 22, 2005.  See “Description of Subscription Receipts”.

Debentures

The Trust is also hereby qualifying for distribution 60,000 6.50% convertible extendible unsecured subordinated debentures (the “Debentures”) of the Trust at a price of $1,000 per Debenture.  The Debentures have an initial maturity date of July 31, 2005 (the “Initial Maturity Date”).  If the closing of the EnCana Acquisition takes place by 5:00 p.m. (Calgary time) on July 31, 2005, the maturity date will be automatically extended from the Initial Maturity Date to July 31, 2010 (the “Final Maturity Date”).  If closing of the EnCana Acquisition does not take place by 5:00 p.m. (Calgary time) on July 31, 2005, the Debentures will mature on the Initial Maturity Date.

The Debentures bear interest at an annual rate of 6.50%, payable semi-annually in arrears on January 31 and July 31 in each year, commencing July 31, 2005. The first interest payment will include interest accrued from the closing of the offering to July 31, 2005.

The Debentures are redeemable by the Trust, on not more than 60 days and not less than 30 days prior notice, at a price of $1,050 per Debenture after July 31, 2008 and on or before July 31, 2009, and at a price of $1,025 per Debenture after July 31, 2009 and before maturity on July 31, 2010, in each case, plus accrued and unpaid interest thereon, if any.

Upon the maturity or redemption of the Debentures, the Trust may pay the outstanding principal amounts of the Debentures in cash or may, at its option, on not more than 60 days and not less than 30 days prior notice and subject to regulatory approval, elect to satisfy its obligations to repay the principal amount of the Debentures which have matured or been redeemed by issuing and delivering that number of Trust Units obtained by dividing the aggregate principal amount of Debentures which have matured or redeemed by 95%of the weighted average trading price of the Trust Units on the Toronto Stock Exchange (the “TSX”) for the 20

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consecutive trading days ending five trading days preceding the date fixed for redemption or the date of maturity, as the case may be.  Any accrued and unpaid interest thereon will be paid in cash.

Each Debenture will be convertible into Trust Units at the option of the holder at any time prior to the close of business on the earlier of the maturity date, being the Initial Maturity Date or the Final Maturity Date, as applicable, and the business day immediately preceding the date specified by the Trust for redemption of the Debentures, at a conversion price of $19.75 per Trust Unit, subject to adjustment in certain events. Holders converting their Debentures will receive accrued and unpaid interest thereon. See “Description of the Debentures”.

The issued and outstanding Trust Units are listed on the TSX under the trading symbol “SPN.UN”.  On May 6, 2005, the last trading day prior to the public announcement of the offering, the closing price of the Trust Units on the TSX was $18.44 per Trust Unit. The Trust has applied to list the Subscription Receipts, the Debentures and the Trust Units issuable pursuant to the Subscription Receipts and on the conversion, redemption or maturity of the Debentures on the TSX.  Listing will be subject to the Trust fulfilling all of the listing requirements of the TSX.

The price of the Subscription Receipts and Debentures offered hereunder was determined by negotiation between StarPoint Energy Ltd. (the “Administrator”), on behalf of the Trust, and BMO Nesbitt Burns Inc. on its own behalf and on behalf of Scotia Capital Inc., FirstEnergy Capital Corp., CIBC World Markets Inc., TD Securities Inc., Orion Securities Inc., National Bank Financial Inc., GMP Securities Ltd., RBC Dominion Securities Inc.,  Tristone Capital Inc., Canaccord Capital Corporation, First Associates Investments Inc. and Haywood Securities Inc. (collectively, the “Underwriters”).

	Offering Price		Underwriters’ Fee		Net Proceeds to the Trust
Per Subscription Receipt(1)(3)	$	18.00	$	0.90	$	17.10
Total(1)(3)	$	295,200,000	$	14,760,000	$	280,440,000
Per Debenture	$	1,000	$	40	$	960
Total	$	60,000,000	$	2,400,000	$	57,600,000
Total(2)	$	355,200,000	$	17,160,000	$	338,040,000

Notes:

(1)The Underwriters’ fee with respect to the Subscription Receipts is payable as to 50% upon the closing of the offering and 50% on the release of the Escrowed Funds to the Trust.  If the EnCana Acquisition is not completed, the Underwriters’ fee with respect to the Subscription Receipts will be reduced to the amount payable upon closing of the offering.

(2)Excluding interest, if any, on the Escrowed Funds and before deducting expenses of the offering estimated to be $250,000, which will be paid from the general funds of the Trust.

(3)The Trust has granted to the Underwriters an option (the “Option”) to purchase up to an additional 1,400,000 Subscription Receipts pursuant to the offering at a price equal to the Offering Price. The Option is exercisable, in whole or in part, at any time until 24 hours prior to the time of closing of the offering. If the Underwriters exercise the Option in full, the total Offering Price, Underwriters’ Fee and Net Proceeds to the Trust with respect to the Subscription Receipts will be $320,400,000, $16,020,000 and $304,380,000 respectively.  This short form prospectus qualifies the distribution of any Subscription Receipts issued pursuant to the exercise of the Option.  See “Plan of Distribution”.

The Underwriters, as principals, conditionally offer the Subscription Receipts and Debentures, subject to prior sale, if, as and when issued by the Trust and delivered and accepted by the Underwriters in accordance with the conditions contained in the Underwriting Agreement referred to under “Plan of Distribution”and subject to approval of certain legal matters relating to the offering on behalf of the Trust by Heenan Blaikie LLP and on behalf of the Underwriters by Bennett Jones LLP.

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BMO Nesbitt Burns Inc. is a wholly owned subsidiary of a Canadian chartered bank which is a lender to the Trust.  Consequently, the Trust may be considered to be a connected issuer of BMO Nesbitt Burns Inc. for the purposes of securities regulations in certain provinces.  See “Relationship Between the Trust and BMO Nesbitt Burns Inc.” and “Use of Proceeds”.

There is currently no market through which the Subscription Receipts or Debentures may be sold and purchasers may not be able to resell Subscription Receipts or Debentures purchased under this short form prospectus.

Subscriptions for Subscription Receipts and Debentures will be received subject to rejection or allotment in whole or in part and the right is reserved to close the subscription books at any time without notice. It is expected that closing will occur on or about May 26, 2005 or such other date not later than June 15, 2005 as the Trust and the Underwriters may agree. The Subscription Receipts will be represented by a global certificate issued in registered form to the Canadian Depository for Securities Limited (“CDS”) or its nominee under the book-based system administered by CDS.  Certificates for the aggregate principal amount of the Debentures will be issued in registered form to CDS and will be deposited with CDS on the date of closing. No certificates evidencing the Subscription Receipts or Debentures will be issued to subscribers except in certain limited circumstances, and registration will be made in the depositary service of CDS. Subscribers for Subscription Receipts and Debentures will receive only a customer confirmation from the Underwriter or other registered dealer who is a CDS participant and from or through whom a beneficial interest in the Subscription Receipts or Debentures is purchased. Subject to applicable laws, the Underwriters may, in connection with the offering, effect transactions which stabilize or maintain the market price of the Subscription Receipts, the Trust Units or the Debentures at levels other than those that might otherwise prevail on the open market. See “Plan of Distribution”.

In the opinion of counsel, subject to the qualifications and assumptions discussed under the heading “Certain Canadian Federal Income Tax Considerations”, the Subscription Receipts, the Debentures and the Trust Units issuable pursuant to the Subscription Receipts and on the conversion, redemption or maturity of the Debentures will, on the date of closing, be qualified investments under the Income Tax Act (Canada) (the “Tax Act”) and the regulations thereunder for trusts governed by registered retirement savings plans, registered retirement income funds, deferred profit sharing plans (except, in the case of the Debentures, a deferred profit sharing plan to which the Trust has made a contribution) and registered education savings plans (collectively, “Exempt Plans”). Under proposed amendments to the regulations to the Tax Act, Subscription Receipts will only be a qualified investment for an Exempt Plan if the Trust deals at arm’s length (within the meaning of the Tax Act) with each person who is an annuitant, a beneficiary, an employer or a subscriber under the governing plan of the particular Exempt Plan.  See “Certain Canadian Federal Income Tax Considerations” and “Eligibility for Investment”.

A return on an investment in the Trust Units issuable pursuant to the Subscription Receipts is not comparable to the return on an investment in a fixed-income security.  The recovery of an initial investment in the Trust is at risk, and the anticipated return on such investment is based on many performance assumptions.  Although the Trust intends to make distributions of its available cash to Unitholders, these cash distributions may be reduced or suspended.  The actual amount distributed will depend on numerous factors, including the financial performance of the subsidiaries of the Trust, debt obligations, working capital requirements and future capital requirements.  In addition, the market value of the Trust Units may decline if the Trust’s cash distributions decline in the future and that decline may be material.  The Trust has not obtained a stability rating from an independent rating agency regarding the relative stability and sustainability of the Trust’s cash distribution stream. The Trust may consider obtaining a stability rating from an independent rating agency in the future.

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The after tax return from an investment in Trust Units to Unitholders subject to Canadian income tax will depend, in part, on the composition for tax purposes of distributions paid by the Trust (portions of which will be fully or partially taxable or may constitute non-taxable returns of capital). The composition for tax purposes of those distributions may change over time, thus affecting the after tax return to Unitholders. Returns on capital are generally taxed as ordinary income or as dividends in the hands of Unitholders.  Returns of capital are generally non-taxable to a Unitholder (but reduce the Unitholder’s adjusted cost base in the Trust Unit for tax purposes).  See “Certain Canadian Federal Income Tax Considerations”.

It is important for an investor to consider the particular risk factors that may affect the securities and industry in which it is investing, and therefore the stability of the distributions that it receives.  See “Risk Factors”.

The Subscription Receipts, the Debentures and the Trust Units are not “deposits” within the meaning of the Canada Deposit Insurance Corporation Act (Canada) and are therefore not insured under the provisions of that act or any other legislation.  Furthermore, the Trust is not a trust company and, accordingly, it 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.

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TABLE OF CONTENTS

Special Note Regarding Forward Looking Statements	1
Definitions	2
Abbreviations and Conversion	6
Notes on Reserves Data	7
Documents Incorporated by Reference	8
Non-GAAP Measures	9
StarPoint Energy Trust	10
The Arrangement	12
Significant Acquisitions by StarPoint and the Trust	13
Recent Developments	13
The EnCana Acquisition	14
Information Concerning the EnCana Assets	15
The APF Combination	26
Information Concerning the APF Assets	26
Effect of the EnCana Acquisition and APF Combination on the Trust	36
Description of Subscription Receipts	40
Description of Debentures	41
Description of Trust Units	47
Consolidated Capitalization of the Trust	48
Interest Coverage	49
Material Debt	49
Price Range and Trading Volume of Units	50
Record of Cash Distributions	50
Use of Proceeds	51
Plan of Distribution	51
Relationship Between the Trust and BMO Nesbitt Burns Inc.	52
Interest of Experts	53
Certain Canadian Federal Income Tax Considerations	53
Eligibility for Investment	59
Risk Factors	60
Material Contracts	61
Legal Proceedings	62
Auditors, Transfer Agent and Registrar	62
Statutory and Contractual Rights of Withdrawal and Rescission	62
Auditors’ Consents	63
Schedule “A” - Financial Statements of E3	A-1
Schedule “B” - Financial Statements of Upton	B-1
Schedule “C” - Financial Statements of Selkirk	C-1
Schedule “D” - Financial Statements of APF	D-1
Schedule “E” - Schedule of Revenues, Royalties and Operating Expenses for the EnCana Assets	E-1
Schedule “F” - Pro Forma Consolidated Financial Statements	F-1
Certificate of the Trust	G-1
Certificate of the Underwriters	H-1

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SPECIAL NOTE REGARDING FORWARD LOOKING STATEMENTS

Certain statements contained in this short form prospectus, and in certain documents incorporated by reference into this short form prospectus, 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 short form prospectus should not be unduly relied upon.  These statements speak only as of the date of this short form prospectus or as of the date specified in the documents incorporated by reference into this short form prospectus, as the case may be.

In particular, this short form prospectus, 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.

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 short form prospectus 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 short form prospectus and the documents incorporated by reference herein are expressly qualified by this cautionary statement.  Except as required under applicable securities laws, neither the Trust nor the Administrator undertake any obligation to publicly update or revise any forward-looking statements.

1

DEFINITIONS

Unless the context indicates otherwise, the following terms shall have the meanings set out below when used in this short form prospectus.  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.

“1167639” means 1167639 Alberta Ltd., a corporation incorporated under the ABCA and a wholly-owned subsidiary of Subtrust;

“1148607” means 1148607 Alberta Ltd., a corporation incorporated under the ABCA and a wholly-owned subsidiary of EnCana;

“ABCA” meansthe Business Corporations Act (Alberta), 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 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;

“AIF” means the renewal annual information form of the Trust dated March 28, 2005;

“APF” means APF Energy Trust, an unincorporated trust formed pursuant to the laws of the Province of Alberta;

“APF Combination” means the indirect acquisition by the Trust of the APF Assets in exchange for Trust Units pursuant to the Combination Agreement;

“APF Assets” means those petroleum and natural gas properties and related assets described under the heading “The APF Combination – Information Concerning the APF Assets” that the Trust will indirectly acquire pursuant to the APF Combination;

“APF ExploreCo” means Rockyview Energy Inc., a corporation incorporated under the ABCA;

“APF ExploreCo Assets” means certain petroleum and natural gas properties and related assets currently held indirectly by APF and to be transferred to APF ExploreCo prior to the completion of the APF Combination;

“APF Reports” means the independent engineering reports of Sproule dated February 18, 2005 and of GLJ dated February 28, 2005 evaluating, effective December 31, 2004, the oil, NGL and natural gas reserves attributable to the APF Assets, in the case of GLJ, and the coalbed methane reserves attributable to the APF Assets in the case of Sproule;

“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;

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“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;

“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;

“Combination Agreement” means the combination agreement dated April 13, 2005 between the Trust and the Administrator and APF and APF Energy Inc. described under the heading the “The APF Combination”;

“CRA” means the Canada Revenue Agency;

“Credit Facility” means the credit facility between the Administrator and Bank of Montreal described under the heading “Material Debt”;

“Debenture Trustee” means Olympia Trust Company or its successor as trustee under the Indenture;

“Debentures” means the 6.50% convertible extendible unsecured subordinated debentures of the Trust offered hereby;

“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;

“EnCana” means EnCana Corporation;

“EnCana Acquisition” means the indirect acquisition by the Trust of the EnCana Assets pursuant to the EnCana Agreement;

“EnCana Agreement” means the agreement dated May 9, 2005 between Subtrust and 1167639, as purchasers, and EnCana and 114860, as vendors, respecting the purchase of the EnCana Assets;

“EnCana Assets” means those petroleum and natural gas properties and related assets described under the heading “The EnCana Acquisition – Information Concerning the EnCana Assets” that the Trust will indirectly acquire pursuant to the EnCana Acquisition;

“EnCana Asset Reports” means the independent engineering reports of McDaniel dated April 29, 2005 and of GLJ dated April 29, 2005, evaluating, effective March 31, 2005, the oil, NGL and natural gas reserves attributable to the EnCana Assets;

“Equity Bridge Loan” means the equity bridge loan provided by Bank of Montreal to the Trust as described under the heading “Material Debt”;

“Escrow Agent” means Olympia Trust Company;

“Escrowed Funds” means the proceeds from the sale of the Subscription Receipts;

“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;

“Final Maturity Date” means July 31, 2010;

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“GLJ” means Gilbert Laustsen Jung Associates Ltd., independent oil and gas reservoir engineers of Calgary, Alberta;

“Indenture” means the trust indenture to be dated as of the date of closing of the offering between the Trust and the Debenture Trustee governing the terms of the Debentures;

“Initial Maturity Date” means July 31, 2005;

“McDaniel” means McDaniel & Associates Consultants Ltd., independent oil and gas reservoir engineers of Calgary, Alberta;

“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;

“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 Trust;

“Offering” means the offering of 16,400,000 Subscription Receipts, and any Subscription Receipts issued pursuant to the exercise of the Option, and 60,000 Debentures pursuant to this short form prospectus;

“Option” means the option granted by the Trust to the Underwriters to purchase up to an additional 1,400,000 Subscription Receipts at a price of $18.00 per Subscription Receipt at any time until 24 hours prior to the time of closing of the Offering;

“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;

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

“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 of Calgary, Alberta;

“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;

“Subscription Receipt Agreement” means the agreement to be dated the date of closing of the Offering among the Trust, the Underwriters and the Escrow Agent governing the terms of the Subscription Receipts;

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“Subscription Receipts” means the subscription receipts of the Trust offered hereby;

“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;

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

“Trend” means Trend Energy Inc., a corporation incorporated under the ABCA;

“Trust” means StarPoint Energy Trust, a unincorporated 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;

“Underwriters” means, collectively, BMO Nesbitt Burns Inc., Scotia Capital Inc., FirstEnergy Capital Corp., CIBC World Markets Inc., TD Securities Inc., Orion Securities Inc., National Bank Financial Inc., GMP Securities Ltd., RBC Dominion Securities Inc., Tristone Capital Inc., Canaccord Capital Corporation, First Associates Investments Inc. and Haywood Securities Inc.;

“Underwriting Agreement” means the agreement dated as of May 11, 2005 among the Trust, the Administrator and the Underwriters in respect of the Offering;

“United States” or “U.S.” means the United States of America, it territories and possessions, any state of the United States, and the District of Columbia; and

“Unitholder” means a holder of Trust Units.

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 short form prospectus are in Canadian dollars, except where otherwise indicated.

5

ABBREVIATIONS AND CONVERSION

In this short form prospectus, 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’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
$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

6

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 are 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 known 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 plus 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.

7

DOCUMENTS INCORPORATED BY REFERENCE

Information has been incorporated by reference in this short form prospectus from documents filed with securities commissions or similar authorities in Canada. Copies of the documents incorporated herein by reference may be obtained on request without charge from the Vice-President, Finance and Chief Financial Officer of the Administrator at 3900, 205 - 5th Avenue S.W., Calgary, Alberta, T2P 2V7, Telephone: (403) 268-7800, Fax: (403) 263-3388.  For the purpose of the Province of Québec, this simplified prospectus contains information to be completed by consulting the permanent information record. A copy of the permanent information record may be obtained from the Vice-President, Finance and Chief Financial Officer of the Administrator at the above-mentioned address and telephone and fax numbers. In addition, copies of the documents incorporated herein by reference maybe obtained from the securities commissions or similar authorities in Canada through the SEDAR website at www.sedar.com.

The following documents of the Trust are filed with the various securities commissions or similar authorities in the provinces of Canada and are specifically incorporated by reference into and form an integral part of this short form prospectus:

(a)the AIF;

(b)the Trust’s audited balance sheet as at December 31, 2004 and the audited comparative consolidated financial statements of StarPoint as at and for the year ended December 31, 2004, together with the notes thereto and the reports of the auditors thereon;

(c)the Trust’s management’s discussion and analysis for the year ended December 31, 2004;

(d)the Trust’s material change report dated January 28, 2005 with respect to the completion of the acquisition of Selkirk Energy Partnership;

(e)the Trust’s material change report dated April 22, 2005 with respect to the APF Combination and the Combination Agreement; and

(f)the Trust’s Information Circular and Proxy Statement dated April 15, 2005 relating to the annual meeting of Unitholders to be held on May 30, 2005, excluding the sections entitled “Corporate Governance Practices”, “Report to the Unitholders on Executive Compensation” and “Appendix A - Report on Corporate Governance Practices”.

Any material change reports (excluding confidential reports), comparative interim financial statements, comparative annual financial statements and the auditors’ report thereon and information circulars (excluding those portions that are not required pursuant to National Instrument 44-101 of the Canadian Securities Administrators to be incorporated by reference herein) filed by the Trust with the securities commissions or similar authorities in Canada subsequent to the date of this short form prospectus and prior to the termination of this distribution shall be deemed to be incorporated by reference in this short form prospectus.

Any statement contained in a document incorporated or deemed to be incorporated by reference herein shall be deemed to be modified or superseded for the purposes of this short form prospectus to the extent that a statement contained herein or in any other subsequently filed document which also is, or is deemed to be, incorporated by reference herein modifies or supersedes such statement. The modifying or superseding statement need not state that it has modified or superseded a prior statement or include any other information set forth in the document that it modifies or supersedes. The making of a modifying or superseding statement shall not be deemed an admission for any purposes that the modified or superseded statement, when made, constituted a misrepresentation, an untrue statement of a material fact or an omission to state a material fact that is required to be stated or that is necessary to make a statement not misleading in

8

light of the circumstances in which it was made. Any statement so modified or superseded shall not be deemed, except as so modified or superseded, to constitute a part of this short form prospectus.

NON-GAAP MEASURES

In this short form prospectus and in the documents incorporated by reference into this short form prospectus, 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”.

9

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. The Arrangement is described further under the heading “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, 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.

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

Business of the Trust and the Administrator

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.  As part of the Arrangement, StarPoint and E3 amalgamated with StarPoint Acquisition Ltd. to become the Administrator.  The Trust owns all of the issued and outstanding common shares of the Administrator.  The Arrangement is described further under the heading “The Arrangement”.

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’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 Southern Saskatchewan, Central Alberta and the plains area of Northeastern 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 may 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.  See below under the heading “Record of Cash Distributions”.

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 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 share they owned for:

•              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.

The audited comparative consolidated financial statements of StarPoint as at and for the year ended December 31, 2004 have been incorporated by reference into this short form prospectus.  Schedule “A” hereto contains the audited comparative financial statements of E3 as at and for the years ended December 31, 2004 and 2003.

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SIGNIFICANT ACQUISITIONS BY STARPOINT AND THE TRUST

Acquisition of Upton

On January 27, 2004, StarPoint completed the acquisition of Upton Resources Inc. (“Upton”) pursuant to a plan of arrangement under the provisions of The Business Corporations Act (Saskatchewan).  Under the arrangement, StarPoint acquired all of the issued and outstanding common shares of Upton in exchange for a total of approximately 23,700,625 common shares of StarPoint. The acquisition increased StarPoint’s production by an estimated 5,000 BOE/d and added an estimated 12,775 MBOE in Proved plus Probable reserves of light oil and natural gas, focused mainly in southeast Saskatchewan and North Dakota.

Schedule “B” hereto contains the audited consolidated financial statements of Upton as at and for the year ended December 31, 2003.

Acquisition of Selkirk

On January 28, 2005, the Administrator acquired all of the issued and outstanding shares of four private corporations for aggregate net cash consideration of $63.1 million. Together, the private corporations owned 100% of the interests in Selkirk, a general partnership formed under the laws of the Province of Alberta.   Selkirk was subsequently reorganized such that it was dissolved and Subtrust now holds all of the assets and liabilities of Selkirk.

The Trust financed the acquisition of Selkirk through borrowings under its demand revolving operating credit facility with Bank of Montreal and an equity bridge loan with Bank of Montreal.  On February 10, 2005, the Trust completed an offering of 3,760,000 Trust Units at a price of $18.00 per Trust Unit for net proceeds of $64,296,000.  The net proceeds were used to pay down the amounts owing under the equity bridge loan and to reduce indebtedness under the credit facility.

A description of the properties held by Selkirk is provided in the AIF under the heading “Oil and Gas Properties – Selkirk Properties”. A description of the oil and natural gas reserves attributable to those properties is provided in the AIF under the heading “Oil and Natural Gas Reserves and Net Present Value of Future Net Revenue”. The AIF is incorporated by reference into this short form prospectus.

Schedule “C” hereto contains audited financial statements for Selkirk and its four partners for the year ended January 31, 2004 and unaudited comparative financial statements for the period ended October 31, 2004.

RECENT DEVELOPMENTS

Unitholder Limited Liability Legislation

On July 1, 2004 the Income Trusts Liability Act (Alberta) came into force, creating a statutory limitation on the liability of unitholders of Alberta income trusts such as the Trust.  The legislation provides that a unitholder will not be, as a beneficiary, liable for any act, default, obligation or liability of the trustee that arises after July 1, 2004.  For additional information, see “Risk Factors - Unitholder Limited Liability” in the AIF.

DRIP Plan

The Trust has implemented a premium distribution, distribution reinvestment and optional trust unit purchase plan (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

13

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 DRIP 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.

Trust Unit Financing

On February 10, 2005, the Trust completed an offering of 3,760,000 Trust Units at a price of $18.00 per Trust Unit for net proceeds of $64,296,000.

Potential Acquisitions

The Trust continues to evaluate potential acquisitions of all types of petroleum and natural gas 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. As of the date hereof, the Trust has not reached agreement on the price or terms of any potential material acquisitions, other than the EnCana Acquisition and the APF Combination. The Trust cannot predict whether any current or future opportunities will result in one or more acquisitions for the Trust.

THE ENCANA ACQUISITION

On May 9, 2005, Subtrust and 1167639 entered into the EnCana Agreement with EnCana and 1148607.  The EnCana Agreement provides for the acquisition (referred to herein as the EnCana Acquisition) by Subtrust and 1167639 of all of the interests of 1148607 Alberta Partnership, an Alberta general partnership which holds the EnCana Assets, for aggregate cash consideration of $403,500,000, subject to adjustments.

Under the EnCana Agreement, conditions to closing of the EnCana Acquisition include the continued accuracy of representations and warranties, the due performance of all covenants, the receipt of necessary approvals under the Competition Act (Canada) and the absence of anysubstantial unrepaired damage or physical alteration of the tangibles included in the EnCana Assets occurring prior to closing which would materially and adversely affect the value of the EnCana Assets.   Closing of the EnCana Acquisition is expected to occur on or about June 30, 2005, with an effective date of May 1, 2005.

Subtrust and 1167639 have paid a deposit of $20,175,000 (the “Deposit”) to EnCana under the EnCana Agreement.  The Deposit will be credited against the purchase price in the event the EnCana Acquisition is completed.  If the EnCana Acquisition is not completed due to a default by Subtrust and 1167639, EnCana will be entitled to retain the Deposit, plus interest, as liquidated damages.  In all other cases, if the EnCana Acquisition does not occur, the Deposit and interest accrued thereon will be refunded.

In addition to forfeiting the Deposit, if the EnCana Acquisition is not completed due to a default by Subtrust and 1167639, the EnCana Agreement requires Subtrust and 1167639 to pay EnCana a break fee of $20,175,000 as liquidated damages.

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INFORMATION CONCERNING THE ENCANA ASSETS

General

As the Trust does not currently own the EnCana Assets, the information under this heading has been summarized from publicly available information and information obtained from EnCana and other third parties.

Oil and Natural Gas Reserves

In accordance with NI 51-101, McDaniel and GLJ prepared the EnCana Asset Reports.  The EnCana Asset Reports evaluated, as at March 31, 2005, the oil, NGL and natural gas reserves attributable to the EnCana Assets.  The tables below are a summary of the oil, NGL and natural gas reserves attributable to the EnCana Assets and the net present value of future net revenue attributable to such reserves as evaluated in the EnCana Asset Reports, based on constant and forecast price and cost assumptions.  The tables summarize the data contained in the EnCana Asset Reports 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.

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 McDaniel and GLJ.  It should not be assumed that the undiscounted or discounted net present value of future net revenue attributable to reserves estimated by McDaniel and GLJ 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 there is no guarantee that the estimated reserves will be recovered.  Actual oil, NGL and natural gas reserves may be greater than or less than the estimates provided herein.

The Trust is entitled to deduct from its income all amounts which are paid or payable by it to Unitholders in a given financial year.  As a result, the Trust does not anticipate being liable for any material amount of income tax on income.  Therefore, the net present values of future net revenue after income taxes will be the same as the net present values of future net revenue before income taxes presented in the tables below.

Summary of Oil and Gas Reserves – Constant Prices and Costs

	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	5,121	5,998	63	6,335	4,995	5,550	57	5,936
Developed Non-Producing	259	1,306	10	1,062	231	1,240	9	1,040
Undeveloped	1,775	425	4	839	1,709	401	4	763
Total Proved	7,155	7,729	77	8,235	6,936	7,191	69	7,739
Probable	4,588	1,394	19	3,701	4,461	1,298	17	3,459
Total Proved plus Probable	11,743	9,124	96	11,937	11,396	8,489	86	11,198

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

	Before Future Income Tax Expenses and Discounted at
	0%	10%
	(M$)	(M$)
Proved
Developed Producing	352,640	239,477
Developed Non-Producing	44,439	30,899
Undeveloped	54,961	37,938
Total Proved	452,041	308,314
Probable	211,445	110,796
Total Proved plus Probable	663,486	419,110

Additional Information Concerning Future Net Revenue – Constant Prices and Costs

(Undiscounted)	Revenue	Royalties	Operating Costs	Develop- ment Costs	Abandon- ment and Reclamation Costs	Future Net Revenue Before Income Taxes
	(M$)	(M$)	(M$)	(M$)	(M$)	(M$)
Total Proved Reserves	722,307	52,473	178,393	22,968	16,430	452,041
Total Proved plus Probable	1,018,254	73,357	230,449	34,036	16,929	663,486

Future Net Revenue by Production Group – Constant Prices and Costs

	Future Net Revenue Before Income Taxes and Discounted at 10%
	(M$)
Proved
Light and Medium Crude Oil(1)	166,789
Heavy Oil(1)	135,664
Natural Gas(2)	5,861
Proved plus Probable
Light and Medium Crude Oil(1)	259,756
Heavy Oil(1)	154,200
Natural Gas(2)	5,154

Notes:

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

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

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Summary of Oil and Gas Reserves – Forecast Prices and Costs

	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	5,120	5,908	61	6,305	4,994	5,464	55	5,911
Developed Non-Producing	260	1,293	10	1,064	233	1,227	9	1,041
Undeveloped	1,775	402	4	837	1,709	378	4	761
Total Proved	7,155	7,603	75	8,205	6,936	7,070	67	7,713
Probable	4,588	1,422	20	3,705	4,461	1,326	17	3,462
Total Proved plus Probable	11,743	9,024	95	11,910	11,396	8,395	85	11,175

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

	Before Future Income Tax Expenses and Discounted at
	0%	5%	10%	15%	20%
	(M$)	(M$)	(M$)	(M$)	(M$)
Proved
Developed Producing	268,650	223,217	193,533	172,541	156,794
Developed Non-Producing	35,091	29,660	25,551	22,332	19,766
Undeveloped	40,865	33,941	28,650	24,503	21,164
Total Proved	344,607	286,818	247,734	219,375	197,724
Probable	161,488	113,449	85,916	68,239	55,996
Total Proved plus Probable	506,094	400,268	333,650	287,614	253,720

Additional Information Concerning Future Net Revenue – Forecast Prices and Costs

(Undiscounted)	Revenue	Royalties	Operating Costs	Develop- ment Costs	Abandon- ment and Reclamation Costs	Future Net Revenue Before Income Taxes
	(M$)	(M$)	(M$)	(M$)	(M$)	(M$)
Total Proved Reserves	630,411	45,742	196,266	23,455	20,341	344,607
Total Proved plus Probable	886,898	63,520	260,731	34,778	21,773	506,094

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Future Net Revenue by Production Group – Forecast Prices and Costs

	Future Net Revenue Before Income Taxes and Discounted at 10%
	(M$)
Proved
Light and Medium Crude Oil(1)	133,926
Heavy Oil(1)	108,794
Natural Gas(2)	5,014
Proved plus Probable
Light and Medium Crude Oil(1)	205,889
Heavy Oil(1)	123,760
Natural Gas(2)	3,971

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

McDaniel and GLJ employed the following pricing and exchange rate assumptions as of March 31, 2005 in the EnCana Asset Reports in estimating reserves data using constant prices and costs.

Edmonton Par Price 40° API	Bow River Medium 25° API	AECO - C Spot	Natural Gasolines & Condensate	Exchange Rate
($Cdn/Bbl)	($Cdn/Bbl)	($Cdn/MMBTU)	($Cdn/Bbl)	($US/$Cdn)
67.38	44.12	7.87	68.97	0.826

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Pricing Assumptions – Forecast Prices and Costs

McDaniel and GLJ employed the following pricing, exchange rate and inflation rate assumptions as of April 1, 2005 in the EnCana Asset Reports in estimating reserves data using forecast prices and costs.

	Medium and Light Crude Oil			Natural Gas
Year	WTI Cushing Oklahoma 40° API	Edmonton Par Price 40° API	Bow River Medium 25° API	AECO - C Spot	Exchange Rate
	(US$/Bbl)	($CDN/Bbl)	($CDN/Bbl)	($CDN/GJ)	($US/$Cdn)
2005	53.00	63.20	43.30	7.55	0.825
2006	50.00	59.60	42.00	7.30	0.825
2007	45.00	53.50	39.30	6.70	0.825
2008	40.00	47.40	35.30	6.00	0.825
2009	37.90	44.90	33.40	5.65	0.825
2010	38.60	45.70	34.00	5.75	0.825
2011	39.40	46.60	34.70	5.90	0.825
2012	40.20	47.60	35.40	5.95	0.825
2013	41.00	48.50	36.10	6.10	0.825
2014	41.80	49.50	36.80	6.20	0.825
2015	42.60	50.40	37.50	6.35	0.825
2016	43.50	51.50	38.30	6.45	0.825
2017	44.40	52.50	39.10	6.60	0.825
2018	45.30	53.60	39.90	6.80	0.825
2019	46.20	54.70	40.70	6.85	0.825
2020	47.10	55.70	41.50	7.00	0.825
2021	48.00	56.80	42.30	7.15	0.825
2022	49.00	58.00	43.10	7.30	0.825
2023	50.00	59.20	44.00	7.45	0.825
2024	51.00	60.40	44.90	7.60	0.825
Thereafter	51.00	60.40	44.90	7.60	0.825

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Future Development Costs

The table below sets out the total development costs deducted in the estimation in the EnCana Asset Reports 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 Costs	Forecast Prices and Costs
	Proved Reserves	Proved Reserves	Proved Plus Probable Reserves
	(M$)	(M$)	(M$)
2005	10,436	10,436	11,274
2006	7,510	7,660	17,008
2007	3,707	3,857	5,038
2008	70	74	0
2009	70	76	76
Remaining Years	1,175	1,352	1,381
Total Undiscounted	22,968	23,455	34,777
Total Discounted at 10% per year	20,720	21,084	31,185

The Trust has three sources of funding available to finance its capital expenditure programs: internally generated cash flow from operations, debt financing when appropriate and new issues of Trust Units, if available on favourable terms.  If the EnCana Acquisition is completed, 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.

Oil and Gas Properties

The following is a description of the major oil and natural gas properties comprising the EnCana Assets.

Countess, Alberta

The Countess properties are located in southern Alberta, approximately 130 kilometres southeast from the City of Calgary, Alberta.  The EnCana Assets include an average operated working interest of approximately 100% in 23,580 (22,533 net) acres of land in this area.  There are 84 (82 net) producing oil wells, 13 (13 net) non-producing oil wells and 2 (2 net) non-producing natural gas wells on the Countess properties.

The majority of the Countess production is obtained from the Rosemary Lower Mannville Z and RR oil pools and the Duchess Lower Mannville X and VVV oil pools which are currently under active waterflood schemes.  A small portion of the production is obtained from 38 single well batteries.  The medium oil (26-33° API) is produced from Lower Mannville sandstones at 1,100 to 1,200 metres in depth.

Substantially all of the Countess production is pipelined to one of two 100% working interest central facilities located at Rosemary and Duchess. The central facilities include oil, gas and water separation and treating equipment, crude oil pipeline connection, salt water disposal facilities, and solution gas gathering facilities. A small portion of the production is produced to single well batteries where oil and water are separated and trucked to various area facilities for processing and sale.

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For the year ended December 31, 2004, 5 (5 net) development wells were drilled in the area resulting in 5 (5 net) oil wells.  For the quarter ended March 31, 2005, no exploration or development wells were drilled in the area.

Planned exploration and development activity in the Countess area for 2005 includes the drilling of 6 (6 net) wells at an estimated total net cost of approximately $4.8 million.

Provost, Alberta

The Provost properties are located in Eastern Alberta, approximately 260 kilometres southeast from the City of Edmonton, Alberta.  The EnCana Assets include an average operated working interest of approximately 100% in 22,934 (22,929 net) acres of land in this area.  There are 153 (153 net) producing oil wells and 84 (83 net) non-producing oil wells on the Provost properties.

The majority of the Provost production is obtained from the Provost Lloydminster O and Sparky D oil pools and the Hayter Sparky FF, GG, T and W oil pools. The Provost oil pools are currently under active waterflood schemes and the Hayter pool will commence waterflood once Alberta Energy Utilities Board approval is obtained.  A small portion of the production is obtained from Cummings and Colony oil pools at Provost and Cummings and General Petroleum oil pools at Hayter.  The medium and heavy oil (20-25° API) is produced from Middle and Lower Mannville sandstones at 700 to 900 metres in depth.

The majority of the production is processed through a pipeline connected 100% working interest central facility located at Provost. The central facility includes oil, gas and water separation and treating equipment, crude oil pipeline connection, salt water disposal facilities, and solution gas gathering facilities. Gas production at Hayter is custom processed through a third party facility.

For the year ended December 31, 2004, 58 (58 net) development wells were drilled in the area resulting in 58 (58 net) oil wells.  For the quarter ended March 31, 2005, no exploration or development wells were drilled in the area.

Planned exploration and development activity in the Provost area for 2005 includes the drilling of 4 (4 net) wells at an estimated total net cost of approximately $1.0 million.

Alderson, Alberta

The Alderson properties are located in Southern Alberta, approximately 190 kilometres southeast from the City of Calgary, Alberta.  The EnCana Assets include an average operated working interest of 100% in 14,650 (14,650 net) acres of land in this area.  There are 97 (97 net) producing oil wells and 53 (53 net) non-producing oil wells on the Alderson properties.

The majority of the Alderson production is obtained from the Suffield West Arcs D and Lower Mannville D3D and E3E oil pools and several Alderson Lower Mannville oil pools which are currently under active waterflood schemes.  A small portion of the production is obtained from 44 single well batteries.  The medium oil (27-31° API) is produced from Lower Mannville sandstones at 900 to 1,000 meters depth and the Arcs Nisku carbonate formation at approximately 1,250 metres in depth.

Substantially all of the Alderson production is pipelined to one of four 100% working interest central facilities located at West Suffield and Alderson. The central facilities include oil, gas and water separation and treating equipment, crude oil pipeline connection, salt water disposal facilities, and solution gas gathering facilities. A small portion of the production is produced to single well batteries where oil and water are separated and trucked to various area facilities for processing and sale.

21

For the year ended December 31, 2004, 15 (15 net) development wells were drilled in the area resulting in 15 (15 net) oil wells.  For the quarter ended March 31, 2005, 1 (1 net) development well was drilled in the area resulting in 1 (1 net) oil well.

Planned exploration and development activity in the Alderson area for 2005 includes the drilling of 7 (7 net) wells at an estimated total net cost of approximately $4.6 million.

Oil and Gas Wells

The following table sets forth the number and status of wells, effective March 31, 2005, in which the Trust will acquire a working interest if it acquires the EnCana Assets.

	Producing Wells				Non-Producing Wells
	Oil		Natural Gas		Oil		Natural Gas
	Gross	Net	Gross	Net	Gross	Net	Gross	Net
Countess	84	82	—	—	13	13	2	2
Provost	153	153	—	—	84	83	—	—
Alderson	97	97	—	—	53	53	—	—
Total	334	332	—	—	150	149	2	2

Properties with no Attributed Reserves

The following table summarizes the gross and net acres of unproved properties, effective March 31, 2005, in which the Trust will acquire an interest if it acquires the EnCana Assets 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.

	Gross Acres	Net Acres	Net Acres Expiring Within One Year
Countess	23,580	22,533	Nil
Provost	22,934	22,926	Nil
Alderson	14,650	14,650	Nil
Total	61,164	60,109	Nil

Drilling Activity

The following table sets forth the gross and net exploratory and development wells drilled on the properties comprising the EnCana Assets during the year ended December 31, 2004.

	Exploratory Wells		Development Wells
	Gross	Net	Gross	Net
Crude Oil	—	—	77	77
Natural Gas	—	—	—	—
Dry	—	—	—	—
Total:	—	—	77	77

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No exploratory or development wells drilled on the properties comprising the EnCana Assets during the three months ended March 31, 2005.

Additional Information Concerning Abandonment and Reclamation Costs

Well abandonment costs have been estimated area by area.  Such costs are included in the EnCana Asset Reports as deductions in arriving at future net revenue.  The expected total abandonment costs, net of estimated salvage value, included in the EnCana Asset Reports for 468 net wells under the proved reserves category is $20.3 million undiscounted ($7.7 million discounted at 10%), of which a total of $1.8 million is estimated to be incurred in 2005, 2006 and 2007.  This estimate does not include expected reclamation costs for surface leases of $4.7 million undiscounted ($1.8 million discounted at 10%).

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 EnCana Assets.

	Property Acquisition Costs
	Proved Properties	Unproved Properties	Exploration Costs	Development Costs
Total (M$)	—	—	—	32,123

The following table summarizes capital expenditures (net of incentives and net of certain proceeds and including capitalized general and administrative expenses) incurred for the three months ended March 31, 2005 with respect to the EnCana Assets.

	Property Acquisition Costs
	Proved Properties	Unproved Properties	Exploration Costs	Development Costs
Total (M$)	—	—	—	304

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Production Estimates

The following table discloses for each product type the total volume of production estimated by McDaniel and GLJ in the EnCana Asset Reports for 2005 in the estimates of future net revenue from proved reserves disclosed above.

	Crude Oil	Natural Gas	Natural Gas Liquids	BOE	%
	(Bbls/d)	(Mcf/d)	(Bbls/d)	(BOE/d)
Countess	1,939	3,662	15	2,564	39
Provost	1,954	392	16	2,035	31
Alderson	1,879	643	—	1,986	30
Estimated Total Production	5,772	4,697	31	6,585	100

Production History

The following tables disclose, on a quarterly basis for the year ended December 31, 2004 and the three months ended March 31, 2005, certain information in respect of production, product prices received, royalties paid, operating expenses and resulting netback for the EnCana Assets.

Average Daily Production Volume

	Three Months Ended
	Mar. 31, 2004	June 30, 2004	Sept. 30, 2004	Dec. 31, 2004	Mar. 31, 2005
Natural gas (Mcf/d)	4,567	4,623	5,390	6,216	5,742
Crude Oil (Bbls/d)	5,602	5,862	6,142	6,312	5,913
NGL (Bbls/d)	24	21	28	34	20
Total (BOE/d)	6,387	6,654	7,068	7,382	6,890

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

	Three Months Ended
($ per Bbl)	Mar. 31, 2004	June 30, 2004	Sept. 30, 2004	Dec. 31, 2004	Mar. 31, 2005
Prices Received	36.11	39.40	43.94	39.30	41.07
Royalties Paid	1.65	2.16	2.16	1.85	1.92
Production Costs	7.65	8.34	7.30	7.46	8.18
Netback(1)	26.81	28.90	34.48	29.99	30.97

Note:

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

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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	Mar. 31, 2005
Prices Received	6.77	7.02	6.87	7.41	7.09
Royalties Paid	0.35	0.36	0.36	0.37	0.27
Production Costs	0.66	0.58	0.59	0.41	0.34
Netback(1)	5.76	6.08	5.92	6.63	6.48

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 EnCana Assets for the year ended December 31, 2004.

Field	Crude Oil	Natural Gas	Natural Gas Liquids	BOE	%
	(Bbls/d)	(Mcf/d)	(Bbls/d)	(BOE/d)
Countess	2,247	4,359	13	2,987	43
Provost	1,914	335	13	1,983	29
Alderson	1,820	508	1	1,905	28
Total	5,981	5,202	27	6,875	100

The following table indicates the average daily production from the important fields comprising the EnCana Assets for the three months ended March 31, 2005.

Field	Crude Oil	Natural Gas	Natural Gas Liquids	BOE	%
	(Bbls/d)	(Mcf/d)	(Bbls/d)	(BOE/d)
Countess	2,025	4,760	11	2,829	41
Provost	1,906	233	8	1,953	28
Alderson	1,982	749	1	2,108	31
Total	5,913	5,742	20	6,890	100

Financial Statements

Schedule “E” hereto contains an audited Statement of Net Operating Revenue concerning the EnCana Assets for the years ended December 31, 2004, 2003 and 2002 and an unaudited Statement of Net Operating Revenue concerning the EnCana Assets for the three month period ended March 31, 2005.

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THE APF COMBINATION

On April 13, 2005, the Trust and APF jointly announced that they had entered into the Combination Agreement.  The Combination Agreement provides for the APF Combination.  Pursuant to the APF Combination, the Trust will acquire all of the assets of APF and assume all of its liabilities.  This will result in the Trust indirectly acquiring the APF Assets.  In exchange, the Trust will issue 0.63 of a Trust Unit for every outstanding trust unit of APF.

Prior to the completion of the APF Combination, the APF ExploreCo Assets and the liabilities associated therewith will be transferred to APF ExploreCo and each holder of trust units of APF will be given the right to receive common shares in APF ExploreCo.  The APF ExploreCo Assets consist of approximately 1,000 BOE/d of production, primarily natural gas from properties located in Central Alberta.  The APF ExploreCo Assets will not be acquired by the Trust pursuant to the APF Combination and do not form part of the APF Assets.

The APF Combination and the terms of the Combination Agreement are described in greater detail in the Material Change Report of the Trust dated April 22, 2005, the contents of which have been incorporated by reference into this short form prospectus.

INFORMATION CONCERNING THE APF ASSETS

General

As the Trust does not currently own the APF Assets, the information under this heading has been summarized from publicly available information and information obtained from APF and other third parties.

Oil and Natural Gas Reserves

In accordance with NI 51-101, Sproule and GLJ prepared the APF Reports.  The APF Reports evaluated, as at December 31, 2004, the oil, NGL and natural gas reserves attributable to the APF Assets.  The tables below are a summary of the oil, NGL and natural gas reserves attributable to the APF Assets and the net present value of future net revenue attributable to such reserves as evaluated in the APF Reports, based on constant and forecast price and cost assumptions.  The tables summarize the data contained in the APF Reports 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.

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 and GLJ.  It should not be assumed that the undiscounted or discounted net present value of future net revenue attributable to reserves estimated by Sproule and GLJ 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 there is no guarantee that the estimated reserves will be recovered.  Actual oil, NGL and natural gas reserves may be greater than or less than the estimates provided herein.

The Trust is entitled to deduct from its income all amounts which are paid or payable by it to Unitholders in a given financial year.  As a result, the Trust does not anticipate being liable for any material amount of income tax on income.  Therefore, the net present values of future net revenue after income taxes will be the same as the net present values of future net revenue before income taxes presented in the tables below.

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Summary of Oil and Gas Reserves – Constant Prices and Costs

	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	15,461	959	1,876	91,641	13,791	921	1,390	75,741
Developed Non-Producing	471	404	96	9,252	431	386	67	7,500
Undeveloped	2,172	143	130	14,811	1,936	132	87	11,924
Total Proved	18,103	1,506	2,102	115,704	16,158	1,440	1,544	95,165
Probable	6,498	1,036	595	36,251	5,742	962	450	29,906
Total Proved plus Probable	24,601	2,542	2,696	151,955	21,900	2,402	1,994	125,071

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

	Before Future Income Tax Expenses and Discounted at
	0%	10%
	(M$)	(M$)
Proved
Developed Producing	663,820	423,641
Developed Non-Producing	46,969	27,868
Undeveloped	73,023	33,281
Total Proved	783,813	484,789
Probable	257,266	112,785
Total Proved plus Probable	1,041,079	597,575

Additional Information Concerning Future Net Revenue – Constant Prices and Costs

(Undiscounted)	Revenue	Royalties	Operating Costs	Development Costs	Abandonment and Reclamation Costs	Future Net Revenue Before Income Taxes
	(M$)	(M$)	(M$)	(M$)	(M$)	(M$)
Total Proved Reserves	1,589,186	267,727	464,273	42,193	31,181	783,813
Total Proved plus Probable	2,114,463	355,354	605,295	79,349	33,386	1,041,079

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Future Net Revenue by Production Group – Constant Prices and Costs

	Future Net Revenue Before Income Taxes and Discounted at
	10%
	(M$)
Proved
Light and Medium Crude Oil(1)	206,669
Heavy Oil(1)	6,536
Natural Gas(2)	271,585
Proved plus Probable
Light and Medium Crude Oil(1)	255,874
Heavy Oil(1)	9,948
Natural Gas(2)	331,753

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

	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	15,173	1,048	1,857	90,823	13,541	974	1,379	75,058
Developed Non-Producing	477	477	97	9,197	438	451	67	7,440
Undeveloped	2,169	154	130	14,681	1,982	142	88	11,813
Total Proved	17,819	1,678	2,083	114,701	15,960	1,567	1,534	94,310
Probable	6,452	1,072	594	35,819	5,719	970	451	29,539
Total Proved plus Probable	24,271	2,750	2,678	150,520	21,679	2,536	1,985	123,849

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

	Before Future Income Tax Expenses and Discounted at
	0%	5%	10%	15%	20%
	(M$)	(M$)	(M$)	(M$)	(M$)
Proved
Developed Producing	603,890	483,889	411,176	361,518	324,989
Developed Non-Producing	45,813	33,490	26,755	22,370	19,232
Undeveloped	59,701	39,119	26,828	18,886	13,407
Total Proved	709,405	556,497	464,759	402,774	357,628
Probable	242,201	152,116	108,675	83,104	66,207
Total Proved plus Probable	951,606	708,614	573,434	485,878	423,836

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Additional Information Concerning Future Net Revenue – Forecast Prices and Costs

(Undiscounted)	Revenue	Royalties	Operating Costs	Development Costs	Abandonment and Reclamation Costs	Future Net Revenue Before Income Taxes
	(M$)	(M$)	(M$)	(M$)	(M$)	(M$)
Total Proved Reserves	1,601,950	265,514	542,256	44,004	40,771	709,405
Total Proved plus Probable	2,170,393	356,649	734,211	81,593	46,334	951,606

Future Net Revenue by Production Group – Forecast Prices and Costs

	Future Net Revenue Before Income Taxes and Discounted at
	10%
	(M$)
Proved
Light and Medium Crude Oil(1)	213,724
Heavy Oil(1)	14,052
Natural Gas(2)	236,983
Proved plus Probable
Light and Medium Crude Oil(1)	265,241
Heavy Oil(1)	20,417
Natural Gas(2)	287,777

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 and GLJ employed the following pricing and exchange rate assumptions as of December 31, 2004 in the APF Reports in estimating reserves data using constant prices and costs.

Edmonton Par Price 40° API	Cromer Medium 29.3° API	AECO - C Spot	Butanes	Pentanes Plus	Exchange Rate
($/Bbl)	($/Bbl)	($/MMBTU)	($/Bbl)	($/Bbl)	($US/$Cdn)
46.54	32.12	6.79	34.44	48.97	0.8308

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Pricing Assumptions – Forecast Prices and Costs

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

	Medium and Light Crude Oil			Natural Gas
Year	WTI Cushing Oklahoma 40° API	Edmonton Par Price 40° API	Cromer Medium 29.3° API	AECO - C Spot	Exchange Rate
	(US$/Bbl)	($CDN/Bbl)	($CDN/Bbl)	($CDN/MMBTU)	($US/$Cdn)
2004	41.38	52.96	45.75	6.88	0.769
2005	42.00	50.25	43.75	6.60	0.82
2006	40.00	47.75	41.50	6.35	0.82
2007	38.00	45.50	39.50	6.15	0.82
2008	36.00	43.25	37.75	6.00	0.82
2009	34.00	40.75	35.50	6.00	0.82
2010	33.00	39.50	34.25	6.00	0.82
2011	33.00	39.50	34.25	6.00	0.82
2012	33.00	39.50	34.25	6.00	0.82
2013	33.50	40.00	34.75	6.10	0.82
2014	34.00	40.75	35.50	6.20	0.82
2015	34.50	41.25	36.00	6.30	0.82

Escalated at 2.0% per year thereafter.

Future Development Costs

The table below sets out the total development costs deducted in the estimation in the APF Reports 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 Costs	Forecast Prices and Costs
		Proved Reserves	Proved Plus Probable Reserves
	Proved Reserves
	(M$)	(M$)	(M$)
2005	25,184	25,184	49,796
2006	8,486	8,656	18,488
2007	1,569	1,632	3,362
2008	624	663	910
2009	1,158	1,253	1,258
Remaining Years	5,172	6,616	7,779
Total Undiscounted	42,193	44,004	81,593
Total Discounted at 10% per year	35,855	36,538	70,536

The Trust has three sources of funding available to finance its capital expenditure programs: internally generated cash flow from operations, debt financing when appropriate and new issues of Trust Units, if available on favourable terms.  If the APF Combination is completed, the Trust expects to fund the above future development

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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.

Oil and Gas Properties

The following is a description of the major oil and natural gas properties comprising the APF Assets.

Southeast Saskatchewan

The Southeast Saskatchewan properties are located within 120 kilometres of the City of Estevan, Saskatchewan and are bounded by the US border to the south, the Manitoba border to the east and Weyburn, Saskatchewan to the west.  The APF Assets include an average working interest of 32% in 275,388 (88,555 net) acres of land in this area.

Substantially all of the production in which APF 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, APF participated in drilling 19 (10.0 net) development oil wells and 1 (1.0 net) dry well.

Planned exploration and development activity in Southeast Saskatchewan for 2005 includes approximately $8.6 million for the drilling of 12 (7.9 net) wells and approximately $1.3 million for seismic programs, for an estimated total net cost of approximately $9.9 million.

Southern Alberta

The Southern Alberta properties are located approximately 350 kilometres south and southwest of the City of Calgary, Alberta and include the Robsart assets located in the southwest corner of Saskatchewan.  The APF Assets include an average working interest of 46% in 704,589 (326,661 net) acres of land in this area.

APF’s facilities are comprised of a compressor and processing facility at Countess and several booster compressors.  The compression facilities supply gas to pipelines for sales distribution.

For the year ended December 31, 2004, 1 (0.5 net) exploration wells and 113 (58.5 net) development wells were drilled in the area resulting in 101 (53.2 net) natural gas wells, 7 (1.6 net) oil wells and 1 (0.5 net) suspended well.

Planned exploration and development activity in Southern Alberta for 2005 includes approximately $8.0 million for the drilling of 46 (38.7 net) wells and approximately $2.0 million for seismic programs, for an estimated total net cost of approximately $10.0 million.

Central Alberta

APF’s Central Alberta assets are generally located north of the City of Calgary and south of the City of Edmonton with the eastern most properties of Epping and Chauvin being located less than 50 kilometres from the Saskatchewan border.  The APF Assets include an average working interest of 30% in 369,014 (109,066 net) acres of land in this area.

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APF has a 41% working interest in a gas plant and a 74% working interest in a compressor facility at Joffre, Alberta which serves as a gathering and processing point for natural gas produced by its Central Alberta properties.  In addition, APF holds various working interests in two Innisfail batteries.

For the year ended December 31, 2004, 10 (7.2 net) exploration wells and 7 (1.5 net) development wells were drilled in the area resulting in 16 (8.5 net) natural gas wells and 1 (0.2 net) oil well.

Planned exploration and development activity for Central Alberta during 2005 includes approximately $11.4 million for the drilling of 33 (25.0 net) wells and approximately $1.0 million for seismic programs at an estimated total net cost of approximately $12.4 million.

Western Alberta

The Western Alberta assets of APF are located north of the City of Edmonton, Alberta.  The APF Assets include an average working interest of 45% in 531,464 (241,760 net) acres of land in this area

APF has various working interests in batteries at several of its properties in this region, including Pembina, Paddle River and Sakwatamau. These facilities include gas plants, a gathering and inlet separator, compression and an acid gas injection battery.

For the year ended December 31, 2004, 12 (8.1 net) exploration wells and 15 (4.1 net) development wells were drilled in the area resulting in 13 (5.9 net) natural gas wells, 10 (0.6 net) oil wells, 1 (0.0 net) injection well and 3 (2.0 net) dry wells.

Planned exploration and development activity in Western Alberta for 2005 includes approximately $5.8 million for the drilling of 10 (3.2 net) wells and approximately $3.3 million for seismic programs, for an estimated total net cost of approximately $9.1 million.

Coalbed Methane

APF’s Alberta coalbed methane (“CBM”) properties are primarily located at the Doris and Corbett properties northwest of Edmonton, Alberta with some additional prospects within its Southern Alberta holdings, proximate to the town of Stettler.  The Doris and Corbett lands are included in the APF’s Western Alberta properties.

During 2004, 4 (0.79 net) exploration CBM wells and 5 (3.5 net) development CBM wells were drilled on the Western Alberta properties.

APF also has CBM production in the Powder River Basin, located north of Casper, Wyoming, USA. APF has a working interest of 47% in 31,014 (14,437 net) acres of land in Wyoming.

During 2004, 79 (27.6 net) development CBM wells and 2 (1.7 net) injection wells were drilled on these properties.

Planned exploration and development activity for Wyoming during 2005 totals approximately $4.5 million for the drilling of 77 (31.7 net) wells.

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Oil and Gas Wells

The following table sets forth the number and status of wells, effective December 31, 2004, in which the Trust will acquire a working interest if it acquires the APF Assets.

	Producing Wells				Non-Producing Wells
	Oil		Natural Gas		Oil		Natural Gas
	Gross	Net	Gross	Net	Gross	Net	Gross	Net
Alberta	1,219	206.8	958	555.0	10	3.6	83	31.9
British Columbia	—	—	6	1.0	—	—	—	—
Saskatchewan	1,156	279.0	257	32.0	2	1.0	5	2.0
Wyoming	—	—	63	18.0	—	—	24	23.0
Total	2,375	485.8	1,284	606.0	12	4.6	112	56.9

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 will acquire interest if it acquires the APF Assets 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.

	Gross Acres	Net Acres	Net Acres Expiring Within One Year
Alberta	823,830	335,024	54,814
Saskatchewan	313,938	125,827	3,333
British Columbia	15,547	672	—
Manitoba	1,559	541	—
Wyoming	21,873	10,815	2,623
Total	1,174,747	472,879	60,770

Drilling Activity

The following table sets forth the gross and net exploratory and development wells drilled on the properties comprising the APF Assets during the year ended December 31, 2004.

	Exploratory Wells		Development Wells
	Gross	Net	Gross	Net
Oil	1	1.0	36	11.4
Natural Gas	16	7.7	193	85.9
Dry	2	1.0	2	2.0
Other	1	0.5	—	—
Total:	20	10.2	231	99.3

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Additional Information Concerning Abandonment and Reclamation Costs

Well abandonment costs have been estimated area by area.  Such costs are included in the APF Reports as deductions in arriving at future net revenue.  The expected total abandonment costs included in the APF Reports for 1,431 net wells under the proved plus probable reserves category is $46.3 million undiscounted ($13.8 million discounted at 10%), of which a total of $4.0 million is estimated to be incurred in 2005, 2006 and 2007.  This estimate does not include expected reclamation costs for surface leases of $56.4 million undiscounted ($5.3 million discounted at 10%).

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 APF Assets.

	Property Acquisition Costs
	Proved Properties	Unproved Properties	Exploration Costs	Development Costs
Total (M$)	6,962	4,775	3,856	48,885

Production Estimates

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

	Crude Oil	Natural Gas	Natural Gas Liquids	BOE	%
	(Bbls/d)	(Mcf/d)	(Bbls/d)	(BOE/d)
Alberta	2,887	46,021	777	11,232	69.1
Saskatchewan	4,164	2,537	5	4,701	28.9
British Columbia	—	126	—	22	0.1
Wyoming	—	1,950	—	317	1.9
Estimated Total Production	7,051	50,634	782	16,272	100

Production History

The following tables disclose, 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 APF Assets.

Average Daily Production Volume

	Three Months Ended
	Mar. 31, 2004	June 30, 2004	Sept. 30, 2004	Dec. 31, 2004
Oil & NGL (Bbls/d)	8,766	8,390	8,657	8,803
Natural gas (Mcf/d)	51,209	53,785	52,994	52,585
Total (BOE/d)	17,301	17,354	17,490	17,567

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Prices Received, Royalties Paid, Production Costs and Netback – Crude Oil and NGLs

	Three Months Ended
($ per Bbl)	Mar. 31, 2004	June 30, 2004	Sept. 30, 2004	Dec. 31, 2004
Prices Received	36.85	39.92	42.57	40.13
Royalties Paid	7.07	7.61	9.47	8.36
Production Costs	11.71	11.20	11.55	10.87
Netback(1)	18.07	21.11	21.55	20.90

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
Prices Received	6.73	6.85	6.21	6.46
Royalties Paid	1.40	1.55	1.18	1.20
Production Costs	0.77	0.91	1.37	1.29
Netback(1)	4.56	4.39	3.66	3.97

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 APF Assets for the year ended December 31, 2004.

Business Units	Crude Oil	Natural Gas	Natural Gas Liquids	BOE	%
	(Bbls/d)	(Mcf/d)	(Bbls/d)	(BOE/d)
Coalbed Methane	—	1,095	—	183	1.1
Central Alberta	2,986	18,359	298	6,343	36.6
Southeast Saskatchewan	3,490	772	—	3,619	20.9
Southern Alberta	406	18,315	80	3,539	20.4
Western Alberta	988	13,724	378	3,653	21.0
Total	7,870	52,265	756	17,337	100

Financial Statements

Schedule “D” hereto contains audited annual financial statements for APF for the years ended December 31, 2004 and 2003.   On June 4, 2004, APF acquired all of the issued and outstanding shares of Great Northern Exploration Ltd.  Schedule “D” also contains audited annual financial statements for Great Northern Exploration Ltd. for the years ended December 31, 2003 and 2002 and unaudited comparative financial statements for the three months ended March 31, 2004.  Finally, Schedule “D” contains unaudited pro forma combined financial statements for APF giving effect to the acquisition of Great Northern Exploration Ltd. by APF and the transfer by APF of the APF ExploreCo Assets to APF ExploreCo prior to the completion of the APF Combination.

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EFFECT OF THE ENCANA ACQUISITION AND APF COMBINATION ON THE TRUST

Selected Pro Forma Financial Information

The following tables set out certain pro forma combined financial information for the EnCana Assets, the APF Assets and the Trust for the year ended December 31, 2004 after giving effect to the Arrangement, the acquisition of Selkirk, the EnCana Acquisition, the APF Combination, the offering of 3,760,000 Trust Units completed on February 10, 2005 and the Offering hereunder.   The tables are first presented assuming the completion of both the EnCana Acquisition and the APF Combination.  As there is no guarantee that the APF Combination will be completed, alternative tables are also presented assuming the completion of the EnCana Acquisition, but not the APF Combination.

The information provided below is qualified in its entirety by the unaudited pro forma combined financial statements attached as Schedule “F” hereto.  Reference should also be made to the following financial statements: (i) the Trust’s audited balance sheet as at December 31, 2004, incorporated herein by reference, (ii) the audited comparative consolidated financial statements of StarPoint as at and for the year ended December 31, 2004, incorporated herein by reference, (iii) the audited comparative financial statements of E3 as at and for the years ended December 31, 2004 and 2003, attached as Schedule “A” hereto, (iv) the audited consolidated financial statements of Upton as at and for the year ended December 31, 2003, attached as Schedule “B” hereto, (v) the audited financial statements for Selkirk and its four partners for the year ended January 31, 2004 and unaudited comparative financial statements for the period ended October 31, 2004, attached as Schedule “C” hereto, (vi) the statement of net operating revenue concerning the EnCana Assets for the years ended December 31, 2004, 2003 and 2002, attached as Schedule “E” hereto, (vii) the audited annual financial statements for APF for the years ended December 31, 2004 and 2003, attached at Schedule “D”, (viii) the audited annual financial statements for Great Northern Exploration Ltd. for the years ended December 31, 2003 and 2002 and unaudited comparative financial statements for the three months March 31, 2004, attached at Schedule “D”, and (ix) the unaudited pro forma combined financial statements for APF, attached at Schedule “D”.

Assuming the Completion of the EnCana Acquisition and the APF Combination

For the year ended December 31, 2004	Trust(1)		EnCana Assets(2)	APF Assets(3)		Pro Forma(3)
	($000’s)		($000’s)	($000’s)		($000’s)
Net petroleum and natural gas revenue(4)	99,904		95,897	204,386		400,187
Net earnings (loss)	5,379		77,971	50,803		88,743
Per unit (basic)	$	0.16	—	$	0.75	$	1.02
Per unit (diluted)	$	0.16	—	$	0.75	$	1.02
Total Assets	503,496		—	816,794		2,024,162
Total Liabilities	187,561		—	329,563		660,677
Net Equity	315,935		—	487,231		1,363,485

Note:

(1)Information is derived from the applicable audited financial statements included or incorporated by reference herein and applicable unaudited pro form financial statements included herein.

(2)Information is derived from the applicable audited financial statements included or incorporated by reference herein.

(3)Information from the applicable unaudited pro form financial statements included herein.

(4)Before transportation expenses.

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Assuming the Completion of the EnCana Acquisition, but not the APF Combination

For the year ended December 31, 2004	Trust(1)		EnCana Assets(2)	Pro Forma(3)
	($000’s)		($000’s)	($000’s)
Net petroleum and natural gas revenue(4)	99,904		95,897	195,801
Net earnings (loss)	5,379		77,971	18,605
Per unit (basic)	$	0.16	—	$	0.41
Per unit (diluted)	$	0.16	—	$	0.41
Total Assets	503,496		—	914,378
Total Liabilities	187,561		—	303,653
Net Equity	315,935		—	610,725

Note:

(1)Information is derived from the applicable audited financial statements included or incorporated by reference herein and applicable unaudited pro form financial statements included herein.

(2)Information is derived from the applicable audited financial statements included or incorporated by reference herein.

(3)Information from the applicable unaudited pro form financial statements included herein.

(4)Before transportation expenses.

Selected Combined Operational Information

The following tables set forth certain combined operational information as at December 31, 2004 (except with respect to the EnCana Assets, which is at March 31, 2005) after giving effect to the Arrangement, the acquisition of Selkirk, the EnCana Acquisition and the APF Combination.  The tables are first presented assuming the completion of both the EnCana Acquisition and the APF Combination.  As there is no guarantee that the APF Combination will be completed, alternative tables are also presented assuming the completion of the EnCana Acquisition, but not the APF Combination.

Important information concerning the oil and natural gas properties and operations of the Trust is contained in the AIF, which is incorporated herein by reference.   Important information concerning the oil and natural gas properties in respect of the EnCana Assets and the APF Assets is set forth herein under the headings “Information Concerning the EnCana Assets” and “Information Concerning the APF Assets”.  Readers are encouraged to carefully review the AIF and the information provided herein concerning the EnCana Assets and the APF Assets as the tables below provide a summary only.

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Assuming the Completion of the EnCana Acquisition and the APF Combination

	Trust	EnCana Assets	APF Assets	Pro Forma
Average Daily Production
(For the year ended December 31, 2004)
Crude oil & NGLs (Bbls/d)	6,553	6,008	8,626	21,187
Natural gas (Mcf/d)	17,111	5,202	52,265	75,578
Oil equivalent (BOE/d)	9,405	6,875	17,337	33,783
Net Proved Reserves(1)
Light/medium crude oil & NGLs (Mbbls)	8,193	7,003	17,494	32,690
Heavy crude oil (Mbbls)	2,701	7,070	1,567	11,338
Natural gas (MMcf)	27,128	7,713	94,310	129,151
Oil equivalent (MBOE)	15,415	15,359	34,779	65,553
Net Proved plus Probable Reserves(1)
Light/medium crude oil & NGLs (Mbbls)	15,030	11,481	23,664	50,175
Heavy crude oil (Mbbls)	3,671	8,395	2,536	14,602
Natural gas (MMcf)	45,786	11,175	123,849	180,810
Oil equivalent (MBOE)	26,332	21,739	46,842	94,912
Net Undeveloped Land (thousands of acres)(2)	185,022	60,109	472,879	718,010

Notes:

(1)Reserves information is at December 31, 2004, except with respect to the EnCana Assets which is at March 31, 2005, and is based on forecast prices and costs.

(2)As at December 31, 2004, except with respect to the EnCana Assets which is at March 31, 2005.

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Assuming the Completion of the EnCana Acquisition, but not the APF Combination

	Trust	EnCana Assets	Pro Forma
Average Daily Production
(For the year ended December 31, 2004)
Crude oil & NGLs (Bbls/d)	6,553	6,008	12,561
Natural gas (Mcf/d)	17,111	5,202	22,313
Oil equivalent (BOE/d)	9,405	6,875	16,280
Net Proved Reserves(1)
Light/medium crude oil & NGLs (Mbbls)	8,193	7,003	15,196
Heavy crude oil (Mbbls)	2,701	7,070	9,771
Natural gas (MMcf)	27,128	7,713	34,841
Oil equivalent (MBOE)	15,415	15,359	30,774
Net Proved plus Probable Reserves(1)
Light/medium crude oil & NGLs (Mbbls)	15,030	11,481	26,511
Heavy crude oil (Mbbls)	3,671	8,395	12,066
Natural gas (MMcf)	45,786	11,175	56,961
Oil equivalent (MBOE)	26,332	21,739	48,071
Net Undeveloped Land (thousands of acres)(2)	185,022	60,109	245,131

Notes:

(1)Reserves information is at December 31, 2004, except with respect to the EnCana Assets which is at March 31, 2005, and is based on forecast prices and costs.

(2)As at December 31, 2004, except with respect to the EnCana Assets which is at March 31, 2005.

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DESCRIPTION OF SUBSCRIPTION RECEIPTS

The following is a summary of the material attributes and characteristics of the Subscription Receipts. This summary does not purport to be complete and is subject to, and qualified in its entirety by, reference to the terms of the Subscription Receipt Agreement.

At the closing of the Offering, a certificate representing the Subscription Receipts will be issued in registered form to CDS or its nominee, CDS & Co., and will be deposited with CDS on the closing date of the Offering pursuant to a book-entry only system. Unless the book-entry only system is terminated, and except in certain limited circumstances, owners of beneficial interests in Subscription Receipts shall not receive a certificate for subscription receipts or, unless requested, for the Trust Units issuable on the exchange of the Subscription Receipts. Beneficial interests in Subscription Receipts will generally be represented solely through the book-entry only system and such interests will be evidenced by customer confirmations of purchase from the Underwriters.

The Escrowed Funds will be delivered to and held by the Escrow Agent and invested in short-term obligations of, or guaranteed by, the Government of Canada (and other approved investments) pending the closing of the EnCana Acquisition.  Provided that the closing of the EnCana Acquisition occurs by 5:00 p.m. (Calgary time) on July 31, 2005, the Escrowed Funds and the interest earned thereon will be released to the Trust and the Trust Units will be issued to holders of Subscription Receipts who will receive, without payment of additional consideration or further action, one Trust Unit for each Subscription Receipt held.

Forthwith upon the closing of the EnCana Acquisition, the Trust will execute and deliver to the Escrow Agent a notice thereof, and will issue and deliver the Trust Units to the Escrow Agent.  Contemporaneously with the delivery of such notice, the Trust will issue a press release announcing that the Trust Units have been issued.

If the closing of the EnCana Acquisition does not take place by 5:00 p.m. (Calgary time) on July 31, 2005, the EnCana Acquisition is terminated at any earlier time or the Trust has advised the Underwriters or announced to the public that it does not intend to proceed with the EnCana Acquisition (in any case, the “Termination Time”),holders of Subscription Receipts shall be entitled to receive an amount equal to the full subscription price therefor and their pro rata entitlements to interest on such amount. The Escrowed Funds will be applied toward payment of such amount.  The issuance of a cheque in payment of the subscription price for the Subscription Receipts will require the surrender of the certificate(s) representing the same at the principal office of the Escrow Agent in Calgary, Alberta. If any certificates representing Subscription Receipts have not been surrendered one year after the Termination Time, the Escrow Agent will mail the cheques that the holders thereof are entitled to receive to their last addresses of record.

If the closing of the EnCana Acquisition takes place prior to the Termination Time and holders of Subscription Receipts become entitled to receive Trust Units pursuant to the Subscription Receipt Agreement, such holders will be entitled to receive an amount per Subscription Receipt equal to the amount per Trust Unit of any cash distributions for which record dates have occurred from and including May 24, 2005 to and including the date immediately preceding the date the Trust Units are issued pursuant to the Subscription Receipts (the “Special Interest”).  Any entitlement of a holder of Subscription Receipts to interest earned on the Escrowed Funds shall form part of such payment and shall not be in addition to such payment. Accordingly, if the offering of the Subscription Receipts hereunder closes and if the closing of the EnCana Acquisition occurs on or before July 31, 2005, holders of Subscription Receipts of record on the date the Trust Units are issued pursuant to the Subscription Receipts will be entitled to receive: (i) at the time the Trust Units are issued pursuant to the Subscription Receipts, a payment equal to the distribution of $0.20 per Trust Unit that will be paid by the Trust on June 15, 2005 to Unitholders of record on May 24, 2005, (ii) at the time the Trust Units are issued pursuant to the Subscription Receipts, a payment equal to any distribution that has been paid by the Trust to Unitholders of record on each Trust distribution record date (being on or about the 22^nd day of each month) subsequent to May 24, 2005 and prior to the closing of the EnCana Acquisition, and (iii) at the time of payment to the Unitholders, a payment equal to any distribution that is payable by the Trust to Unitholders of record on each Trust distribution record date, other than

40

those referred in items (i) or (ii), that occurs prior to the closing of the EnCana Acquisition.  In addition, if the EnCana Acquisition closes on June 30, 2005, as currently contemplated, holders of Subscription Receipts will become Unitholders on June 30, 2005 and will be entitled, provided they remain Unitholders on July 22, 2005, to receive the monthly distribution expected to be paid on August 15, 2005 to Unitholders of record on July 22, 2005.

All or a portion of the Special Interest will be satisfied by the payment by the Escrow Agent to holders of Subscription Receipts of interest earned on the Escrowed Funds. The difference, if any, between the amount of interest earned on the Escrowed Funds and the distribution that would have been payable on the Trust Units will be paid by the Trust to the Escrow Agent for payment to holders of Subscription Receipts that have become entitled to receive Trust Units pursuant to the Subscription Receipt Agreement.  If holders of Subscription Receipts become entitled to receive Trust Units, the Escrow Agent will pay such amounts to holders on the later of the date the Trust Units are issued and the date such distribution(s) is paid to Unitholders.  For greater certainty, if the closing of the EnCana Acquisition takes place on a date that is a Trust Unit distribution record date, holders of Subscription Receipts shall not be entitled as such to receive a payment in respect of the cash distribution for such record date, but shall instead be deemed to be holders of Trust Units on such date and will be entitled as Unitholders to receive such monthly distribution.

Under the Subscription Receipt Agreement, original purchasers of Subscription Receipts under the Offering will have a contractual right of rescission following the issuance of Trust Units to such purchaser upon the exchange of the Subscription Receipts to receive the amount paid for the Subscription Receipts if this short form prospectus (including documents incorporated by reference) and any amendment contains a misrepresentation or is not delivered to such purchaser, provided such remedy for rescission is exercised within 180 days of closing of the Offering.

Holders of Subscription Receipts are not Unitholders.  Holders of Subscription Receipts are entitled only to receive Trust Units on surrender of their Subscription Receipts to the Escrow Agent or to a return of the subscription price for the Subscription Receipts together with any payments in lieu of interest or distributions, as applicable, as described above.

DESCRIPTION OF DEBENTURES

The following is a summary of the material attributes and characteristics of the Debentures. This summary does not purport to be complete and is subject to, and qualified in its entirety by, reference to the terms of the Indenture referred to below.

General

The Debentures will be issued under the Indenture.  The Debentures authorized for issue immediately will be limited in aggregate principal amount to $60,000,000. The Trust may, however, from time to time, without the consent of the holders of the Debentures, but subject to the limitations described herein, issue additional debentures of the same series or of a different series under the Indenture, in addition to the Debentures offered hereby. The Debentures will be issuable only in denominations of $1,000 and integral multiples thereof.

The Debentures will be dated as of the closing date of the Offering and will mature on the Initial Maturity Date. If the closing of the EnCana Acquisition takes place by 5:00 p.m. (Calgary time) on July 31, 2005, the maturity date will be automatically extended from the Initial Maturity Date to the Final Maturity Date. If the closing of the EnCana Acquisition does not take place by 5:00 p.m. (Calgary time) on July 31, 2005, the Debentures will mature on the Initial Maturity Date.

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The Debentures bear interest at an annual rate of 6.50%, payable semi-annually in arrears on January 31 and July 31 in each year, commencing July 31, 2005. The first interest payment will include interest accrued from the closing of the Offering to July 31, 2005.

The principal amount of the Debentures will be payable in lawful money of Canada or, at the option of the Trust and subject to applicable regulatory approval, by payment of Trust Units as further described under “Payment Upon Redemption or Maturity” and “Redemption and Purchase”. The interest on the Debentures will be payable in lawful money of Canada including, at the option of the Trust and subject to applicable regulatory approval, in accordance with the Trust Unit Interest Payment Obligation as described under “Interest Payment Option”.

The Debentures will be direct obligations of the Trust and will not be secured by any mortgage, pledge, hypothec or other charge and will be subordinated to other liabilities of the Trust as described under “Subordination”. The Indenture will not restrict the Trust from incurring additional indebtedness for borrowed money or from mortgaging, pledging or charging its properties to secure any indebtedness.

Conversion Privilege

The Debentures will be convertible at the holder’s option into fully paid and non-assessable Trust Units at any time prior to the close of business on the earlier of the Final Maturity Date and the business day immediately preceding the date specified by the Trust for redemption of the Debentures, at a conversion price of $19.75 per Trust Unit (the “Conversion Price”), being a conversion rate of 50.6329 Trust Units for each $1,000 principal amount of Debentures.  No adjustment will be made for distributions on Trust Units issuable upon conversion or for interest accrued on Debentures surrendered for conversion; however, holders converting their Debentures will receive accrued and unpaid interest thereon.

Subject to the provisions thereof, the Indenture will provide for the adjustment of the Conversion Price in certain events including: (a) the subdivision or consolidation of the outstanding Trust Units; (b) the distribution of Trust Units to holders of Trust Units by way of distribution or otherwise other than an issue of securities to holders of Trust Units who have elected to receive distributions in securities of the Trust in lieu of receiving cash distributions paid in the ordinary course; (c) the issuance of options, rights or warrants to holders of Trust Units entitling them to acquire Trust Units or other securities convertible into Trust Units at less than 95% of the then current market price (as defined below under “Payment upon Redemption or Maturity”) of the Trust Units; and (d) the distribution to all holders of Trust Units of any securities or assets (other than cash distributions and equivalent distributions in securities paid in lieu of cash distributions in the ordinary course). There will be no adjustment of the Conversion Price in respect of any event described in (b), (c) or (d) above if the holders of the Debentures are allowed to participate as though they had converted their Debentures prior to the applicable record date or effective date. The Trust will not be required to make adjustments in the Conversion Price unless the cumulative effect of such adjustments would change the conversion price by at least 1%.

In the case of any reclassification or capital reorganization (other than a change resulting from consolidation or subdivision) of the Trust Units or in the case of any consolidation, amalgamation, arrangement or merger of the Trust with or into any other entity, or in the case of any sale or conveyance of the properties and assets of the Trust as, or substantially as, an entirety to any other entity, or a liquidation, dissolution or winding-up of the Trust, the terms of the conversion privilege shall be adjusted so that each holder of a Debenture shall, after such reclassification, capital reorganization, consolidation, amalgamation, merger, sale, conveyance, liquidation, dissolution or winding up, be entitled to receive the number of Trust Units or other securities or property such holder would be entitled to receive if on the effective date thereof, it had been the holder of the number of Trust Units into which the Debenture was convertible prior to the effective date of such reclassification, capital reorganization, consolidation, amalgamation, merger, sale, conveyance, liquidation, dissolution or winding up.

No fractional Trust Units will be issued on any conversion but in lieu thereof the Trust shall satisfy fractional interests by a cash payment equal to the current market price of any fractional interest.

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Redemption and Purchase

The Debentures will not be redeemable on or before July 31, 2008. The Trust may, on not more than 60 days and not less than 30 days prior notice, redeem the Debentures at a redemption price of $1,050 per Debenture after July 31, 2008, and on or before July 31, 2009, and at a price of $1,025 per Debenture after July 31, 2009 and before the Final Maturity Date (each a “Redemption Price”), plus accrued and unpaid interest thereon, if any.

In the case of redemption of less than all of the Debentures, the Debentures to be redeemed will be selected by the Debenture Trustee on a pro rata basis or in such other manner as the Debenture Trustee deems equitable, subject to the consent of the TSX.

The Trust will have the right to purchase Debentures in the market, by tender or by private contract.

Payment upon Redemption or Maturity

On redemption or at maturity, the Trust will repay the indebtedness represented by the Debentures by paying to the Debenture Trustee in lawful money of Canada an amount equal to the aggregate Redemption Price of the outstanding Debentures which are to be redeemed or the principal amount of the outstanding Debentures which have matured, as the case may be, together with accrued and unpaid interest thereon.  The Trust may, at its option, on not more than 60 days and not less than 30 days prior notice and subject to applicable regulatory approval, elect to satisfy its obligation to pay the Redemption Price of the Debentures which are to be redeemed or the principal amount of the Debentures which have matured, as the case may be, by issuing Trust Units to the holders of the Debentures.  Any accrued and unpaid interest thereon will be paid in cash. The number of Trust Units to be issued will be determined by dividing the aggregate Redemption Price of the outstanding Debentures which are to be redeemed or the principal amount of the outstanding Debentures which have matured, as the case may be, by 95% of the current market price on the date fixed for redemption or the maturity date, as the case may be. No fractional Trust Units will be issued on redemption or maturity, but, in lieu thereof, the Trust shall satisfy fractional interests by a cash payment equal to the current market price of any fractional interest.

The term “current market price” will be defined in the Indenture to mean the weighted average trading price of the Trust Units on the TSX for the 20 consecutive trading days ending on the fifth trading day preceding the date fixed for redemption or the maturity date, as the case may be.

Subordination

The payment of the principal of, and interest on, the Debentures will be subordinated in right of payment, as set forth in the Indenture, to the prior payment in full of all Senior Indebtedness of the Trust and indebtedness to trade creditors of the Trust.  “Senior Indebtedness” of the Trust will be defined in the Indenture as the principal of and premium, if any, and interest on and other amounts in respect of all indebtedness of the Trust (whether outstanding as at the date of the Indenture or thereafter incurred), other than indebtedness evidenced by the Debentures and all other existing and future debentures or other instruments of the Trust which, by the terms of the instrument creating or evidencing the indebtedness, is expressed to be pari passu with, or subordinate in right of payment to, the Debentures.

The Indenture will provide that, in the event of any insolvency or bankruptcy proceedings, or any receivership, liquidation, reorganization, creditor enforcement or realization or other similar proceedings relative to the Trust, or to its property or assets, or in the event of any proceedings for voluntary liquidation, dissolution or other winding-up of the Trust, whether or not involving insolvency or bankruptcy, or any marshalling of the assets and liabilities of the Trust (and whether voluntary or involuntary, partial or complete), then those holders of Senior Indebtedness, including any indebtedness to trade creditors, will receive payment in full before the holders of Debentures will be entitled to receive any payment or distribution of any kind or character, whether in cash, property or securities, which may be payable or deliverable in any such event in respect of any of the Debentures or any unpaid interest

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accrued thereon. The Indenture will also provide that the Trust will not make any payment, and the holders of the Debentures will not be entitled to demand, institute proceedings for the collection of, or receive any payment or benefit (including, without any limitation, by set-off, combination of accounts or realization of security or otherwise in any manner whatsoever) on account of indebtedness represented by the Debentures (a) in a manner inconsistent with the terms (as they exist on the date of issue) of the Debentures or (b) at any time when an event of default has occurred under the Senior Indebtedness and is continuing and the notice of such event of default has been given by or on behalf of the holders of Senior Indebtedness to the Trust, unless the Senior Indebtedness has been repaid in full.

The Debentures will also be effectively subordinate to claims of creditors of the Trust’s subsidiaries, except to the extent the Trust is a creditor of such subsidiaries ranking at least pari passu with such other creditors. Specifically, the Debentures will be subordinated in right of payment to the prior payment in full of all indebtedness under the Trust’s current credit facilities.  See “Material Debt”.

Priority over Trust Distributions

The Trust Indenture provides that certain expenses of the Trust must be deducted in calculating the amount to be distributed to the Unitholders.  Accordingly, the funds required to satisfy the interest payable on the Debentures, as well as the amount payable upon redemption or maturity of the Debentures or upon an Event of Default (as defined below), will be deducted and withheld from the amounts that would otherwise be payable as distributions to Unitholders.

Change of Control of the Trust

Within 30 days following the occurrence of a change of control of the Trust involving the acquisition of voting control or direction over 66 2/3% or more of the Trust Units or securities convertible into or carrying into or carrying the right to acquire Trust Units (a “Change of Control”), the Trust will be required to make an offer in writing to purchase all of the Debentures then outstanding (the “Debenture Offer”), at a price equal to 101% of the principal amount thereof plus accrued and unpaid interest (the “Debenture Offer Price”).

The Indenture contains notification and repurchase provisions requiring the Trust to give written notice to the Debenture Trustee of the occurrence of a Change of Control within 30 days of such event together with the Debenture Offer. The Debenture Trustee will thereafter promptly mail to each holder of Debentures a notice of the Change of Control together with a copy of the Debenture Offer to repurchase all the outstanding Debentures.

If 90% or more of the aggregate principal amount of the Debentures outstanding on the date of the giving of notice of the Change of Control have been tendered to the Trust pursuant to the Debenture Offer, the Trust will have the right and obligation to redeem all the remaining Debentures at the Debenture Offer Price. Notice of such redemption must be given by the Trust to the Debenture Trustee within 10 days following the expiry of the Debenture Offer, and as soon as possible thereafter, by the Debenture Trustee to the holders of the Debentures not tendered pursuant to the Debenture Offer.

Interest Payment Option

The Trust may elect, from time to time, to satisfy its obligation to pay all or any part of the interest on the Debentures (the “Interest Obligation”), on the date it is payable under the Indenture (an “Interest Payment Date”), by delivering sufficient Trust Units to the Debenture Trustee to satisfy all or part, as the case may be, of the Interest Obligation in accordance with the Indenture (the “Trust Unit Interest Payment Election”). The Indenture will provide that, upon such election, the Debenture Trustee shall (a) accept delivery from the Trust of Trust Units, (b) accept bids with respect to, and consummate sales of, such Trust Units, each as the Trust shall direct in its absolute discretion, (c) invest the proceeds of such sales in Government Obligations (as defined in the Indenture) which

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mature prior to the applicable Interest Payment Date, and use such proceeds to satisfy the Interest Obligation, and (d) perform any other action necessarily incidental thereto.

The Indenture will set forth the procedures to be followed by the Trust and the Debenture Trustee in order to effect the Trust Unit Interest Payment Election. If a Trust Unit Interest Payment Election is made, the sole right of a holder of Debentures in respect of interest will be to receive cash from the Debenture Trustee out of the proceeds of the sale of Trust Units (plus any amount received by the Debenture Trustee from the Trust attributable to any fractional Trust Units) in full satisfaction of the Interest Obligation, and the holder of such Debentures will have no further recourse to the Trust in respect of the Interest Obligation.

Neither the Trust’s making of the Trust Unit Interest Payment Election nor the consummation of sales of Trust Units will (a) result in the holders of the Debentures not being entitled to receive on the applicable Interest Payment Date cash in an aggregate amount equal to the interest payable on such Interest Payment Date, or (b) entitle such holders to receive any Trust Units in satisfaction of the Interest Obligation.

Events of Default

The Indenture will provide that an event of default (“Event of Default”) in respect of the Debentures will occur if any one or more of the following described events has occurred and is continuing with respect of the Debentures: (a) failure for 10 days to pay interest on the Debentures when due; (b) failure to pay principal or premium, if any, on the Debentures when due, whether at maturity, upon redemption, by declaration or otherwise; (c) certain events of bankruptcy, insolvency or reorganization of the Trust under bankruptcy or insolvency laws; or (d) default in the observance or performance of any material covenant or condition of the Indenture and continuance of such default for a period of 30 days after notice in writing has been given by the Debenture Trustee to the Trust specifying such default and requiring the Trust to remedy the same. If an Event of Default has occurred and is continuing, the Debenture Trustee may, in its discretion, and shall upon request of holders of not less than 25% of the principal amount of Debentures then outstanding, declare the principal of and interest on all outstanding Debentures to be immediately due and payable. In certain cases, the holders of more than 50% of the principal amount of the Debentures then outstanding may, on behalf of the holders of all Debentures, waive any Event of Default and/or cancel any such declaration upon such terms and conditions as such holders shall prescribe.

Offers for Debentures

The Indenture will contain provisions to the effect that if an offer is made for the Debentures which is a take-over bid for Debentures within the meaning of the Securities Act (Alberta) and not less than 90% of the Debentures (other than Debentures held at the date of the take-over bid by or on behalf of the offeror or associates or affiliates of the offeror) are taken up and paid for by the offeror, the offeror will be entitled to acquire the Debentures held by the holders of Debentures who did not accept the offer on the terms offered by the offeror.

Modification

The rights of the holders of the Debentures as well as any other series of debentures that may be issued under the Indenture may be modified in accordance with the terms of the Indenture. For that purpose, among others, the Indenture will contain certain provisions which will make binding on all Debenture holders resolutions passed at meetings of the holders of Debentures by votes cast thereat by holders of not less than 66 2/3% of the principal amount of the Debentures present at the meeting or represented by proxy, or rendered by instruments in writing signed by the holders of not less than 66 2/3% of the principal amount of the Debentures then outstanding.  In certain cases, the modification will, instead or in addition, require assent by the holders of the required percentage of Debentures of each particularly affected series.

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Limitation on Issuance of Additional Debentures

The Indenture will provide that the Trust shall not issue additional convertible debentures of equal ranking if the principal amount of all issued and outstanding convertible debentures of the Trust exceeds 25% of the Total Market Capitalization of the Trust immediately after the issuance of such additional convertible debentures. “Total Market Capitalization” will be defined in the Indenture as the total principal amount of all issued and outstanding debentures of the Trust which are convertible at the option of the holder into Trust Units of the Trust plus the amount obtained by multiplying the number of issued and outstanding Trust Units of the Trust (including Trust Units represented by Subscription Receipts) by the current market price of the Trust Units on the relevant date.

Limitation on Non-Resident Ownership

At no time may non-residents of Canada be the beneficial owners of more than 49% of the Trust Units, on a fully diluted basis, including any Trust Units which may be issued upon conversion, redemption or maturity of the Debentures. The Debenture Trustee, on receipt of written direction of the Trust, may require declarations as to the jurisdictions in which beneficial owners of Debentures are resident. If the Trust or the Debenture Trustee becomes aware as a result of requiring such declarations as to beneficial ownership, that the beneficial owners of 40% or more of the Trust Units then outstanding, on a fully diluted basis, are, or may be, non-residents or that such a situation is imminent, the Debenture Trustee may make a public announcement thereof and the Debenture Trustee shall not accept a subscription of Debentures from, issue to or register a transfer of Debentures to a person unless the person provides a declaration that the person is not a non-resident.  If, notwithstanding the foregoing, the Debenture Trustee determines that a majority of the Trust Units are held by non-residents, the Debenture Trustee may send a notice to non-resident holders of Debentures, chosen in inverse order to the order of acquisition or registration of the Debentures or in such manner as the Debenture Trustee may consider equitable and practicable, requiring them to sell their Debentures or a portion thereof within a specified period of not less than 60 days. If the Debenture holders receiving such notice have not sold the specified number of Debentures or provided the Debenture Trustee with satisfactory evidence that they are not non-residents within such period, the Debenture Trustee may on behalf of such Debenture holder sell such Debentures, and, in the interim, shall suspend the rights attached to such Debentures. Upon such sale the affected holders shall cease to be holders of Debentures, and their rights shall be limited to receiving the net proceeds of sale upon surrender of such Debentures.

Book-Entry System for Debentures

The Debentures will be issued in “book-entry only” form and must be purchased or transferred through a participant in the depository service of CDS (a “Participant”). On the closing date of the Offering, the Debenture Trustee will cause the Debentures to be delivered to CDS and registered in the name of its nominee. The Debentures will be evidenced by a single book-entry only certificate. Registration of interests in and transfers of the Debentures will be made only through the depository service of CDS.

Except as described below, a purchaser acquiring a beneficial interest in the Debentures (a “Beneficial Owner”)will not be entitled to a certificate or other instrument from the Debenture Trustee or CDS evidencing that purchaser’s interest therein, and such purchaser will not be shown on the records maintained by CDS, except through a Participant.  Such purchaser will receive a confirmation of purchase from the Underwriter or other registered dealer from whom Debentures are purchased.

Neither the Trust nor the Underwriters will assume any liability for: (a) any aspect of the records relating to the beneficial ownership of the Debentures held by CDS or the payments relating thereto; (b) maintaining, supervising or reviewing any records relating to the Debentures; or (c) any advice or representation made by or with respect to CDS and contained in this short form prospectus and relating to the rules governing CDS or any action to be taken by CDS or at the direction of its Participants. The rules governing CDS provide that it acts as the agent and depositary for the Participants. As a result, Participants must look solely to CDS and Beneficial Owners must look

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solely to Participants for the payment of the principal and interest on the Debentures paid by or on behalf of the Trust to CDS.

As indirect holders of Debentures, investors should be aware that they (subject to the situations described below): (a) may not have Debentures registered in their name; (b) may not have physical certificates representing their interest in the Debentures; (c) may not be able to sell the Debentures to institutions required by law to hold physical certificates for securities they own; and (d) may be unable to pledge Debentures as security.

The Debentures will be issued to Beneficial Owners in fully registered and certificate form (the ““Debenture Certificates”) only if: (a) required to do so by applicable law; (b) the book-entry only system ceases to exist; (c) the Trust or CDS advises the Debenture Trustee that CDS is no longer willing or able to properly discharge its responsibilities as depositary with respect to the Debentures and the Trust is unable to locate a qualified successor; (d) the Trust, at its option, decides to terminate the book-entry only system through CDS; or (e) after the occurrence of an Event of Default, provided that Participants acting on behalf of Beneficial Owners representing, in the aggregate, more than 25% of the aggregate principal amount of the Debentures then outstanding advise CDS in writing that the continuation of a book-entry only system through CDS is no longer in their best interest, and provided further that the Debenture Trustee has not waived the Event of Default in accordance with the terms of the Indenture.

Upon the occurrence of any of the events described in the immediately preceding paragraph, the Debenture Trustee must notify CDS, for and on behalf of Participants and Beneficial Owners, of the availability through CDS of Debenture Certificates. Upon surrender by CDS of the single certificate representing the Debentures and receipt of instructions from CDS for the new registrations, the Debenture Trustee will deliver the Debentures in the form of Debenture Certificates and thereafter the Trust will recognize the holders of such Debenture Certificates as debentureholders under the Indenture.

Interest on the Debentures will be paid directly to CDS while the book-entry only system is in effect. If Debenture Certificates are issued, interest will be paid by cheque drawn on the Trust and sent by prepaid mail to the registered holder or by such other means as may become customary for the payment of interest. Payment of principal, including payment in the form of Trust Units if applicable, and the interest due, at maturity or on a redemption date, will be paid directly to CDS while the book-entry only system is in effect. If Debenture Certificates are issued, payment of principal, including payment in the form of Trust Units if applicable, and interest due, at maturity or on a redemption date, will be paid upon surrender thereof at any office of the Debenture Trustee or as otherwise specified in the Indenture.

DESCRIPTION OF TRUST UNITS

An unlimited number of Trust Units may be created and issued pursuant to the Trust Indenture. Each Trust Unit entitles the holder thereof to one vote at any meeting of Unitholders 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 shall rank among themselves equally and rateably without discrimination, preference or priority.  Each Trust Unit is transferable, subject to compliance with applicable Canadian securities laws, is not subject to any conversion or preemptive rights and entitles the holder thereof to require the Trust to redeem any or all of the Trust Units held by such holder and to one vote at all meetings of Unitholders for each Trust Unit held.

The Trust Indenture provides that Trust Units, including rights, warrants, special warrants or 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 time or times as the Trustee, on the recommendation of the Board of Directors, 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

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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.

For additional information respecting the Trust Units, including information respecting Unitholders’ limited liability, the terms of the Special Voting Units and Exchangeable Shares, restrictions on non-resident Unitholders, the redemption right attached to the Trust Units, meetings of Unitholders and amendments to the Trust Indenture, see under the headings “Additional Information Concerning the Trust”, “The Administrator Share Capital” and “Voting Exchange and Trust Agreement” in the AIF, which is incorporated by reference herein.

The Trust Units do not represent a traditional investment and should not be viewed by investors as “shares” in either the Administrator or the Trust.  As holders of Trust Units, Unitholders do 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 market price of the Trust Units will be sensitive to, among other things, the anticipated distributable income from the Trust and the ability of the Administrator to effect long term growth in the value of the Trust, as well as a variety of market conditions including, but not limited to, interest rates, commodity prices and the ability of the Trust to maintain and grow production. Changes in market conditions may adversely affect the trading price of the Trust Units.  See “Risk Factors”.

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.

CONSOLIDATED CAPITALIZATION OF THE TRUST

The following table sets forth the consolidated capitalization of the Trust effective December 31, 2004, both before and after giving effect to the Arrangement, the acquisition of Selkirk, the EnCana Acquisition, the APF Combination, the offering of 3,760,000 Trust Units completed on February 10, 2005 and the Offering hereunder (referred to as the “Transactions” in the table below).

Designation	Authorized	Outstanding as at December 31, 2004 before giving effect to the Transactions(1)	Outstanding as at December 31, 2004 after giving effect to the Transactions(2)(3)
Trust Units	Unlimited	$2,000	$1,339,791,000
		(1 trust unit)	(83,251,475 trust units)
Exchangeable Shares	Unlimited	$nil	$6,810,000
		(nil shares)	(3,494,595 shares)
Bank Debt		$nil	$264,105,000(4)
Debentures		$nil	$60,000,000

Notes:

(1)The Trust was initially settled as of December 6, 2004.

(2)After deducting the estimated costs of the Offering of $250,000 and the Underwriters’ commission of $18,420,000, and assuming the exercise of the Option and that the net proceeds of the Offering are used to fund a portion of the purchase price of the EnCana Assets.

(3)As at May 10, 2005 there were 27,876,726 Trust Units and 1,753,168 Exchangeable Shares outstanding. In addition there were 468,500 restricted units of the Trust outstanding as at May 10, 2005 pursuant to the Trust’s restricted unit plan, as described in the AIF.

(4)See under the heading “Material Debt” below for a description of the Trust’s bank debt and credit facilities.

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INTEREST COVERAGE

The following interest coverages are calculated on a consolidated basis for the 12 month period ended December 31, 2004 and are based on audited financial information.

The pro forma earnings of the Trust before income taxes and interest expense for the year ended December 31, 2004 were $17.7 million. After giving effect to the issue of the Debentures, the pro forma interest expense for the year ended December 31, 2004 was $6.9 million, for a ratio of 2.6 times.

Based on the pro forma financial statements included at Schedule “F” hereto, which give effect to the Arrangement, the acquisition of Selkirk, the EnCana Acquisition, the APF Combination, the offering of 3,760,000 Trust Units completed on February 10, 2005 and the Offering hereunder, the pro forma interest expense for the year ended December 31, 2004 was $17.1 million, for a ratio of 5.0 times.

MATERIAL DEBT

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 May 10, 2005, a total of $103.9 million was outstanding under the Credit Facility.   The Trust anticipates that approximately an additional $54 million will be drawn on the Credit Facility to fund a portion of the purchase price of the EnCana Assets.  The Trust anticipates that the borrowing limit under the Credit Facility will be increased by an amount sufficient to accommodate this additional borrowing with the increase in the borrowing base of the Trust and its subsidiaries that will occur with the acquisition of the EnCana Assets and APF Assets.

Pursuant to a letter agreement dated May 9, 2005, Bank of Montreal has provided the Administrator with an equity bridge loan in the amount of $20,175,000 (the “Equity Bridge Loan”) for the purposes of paying the Deposit under the EnCana Agreement.  A portion of the proceeds of the Offering will be applied to pay down all of the amount owing under Equity Bridge Loan.

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.

There can be no assurance that the amounts available under the Credit Facility 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 and Equity Bridge Loan 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.

Also, the Trust, the Trustee, the Administrator, the Partnership, Subtrust and Bank of Montreal have entered into 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, the Equity Bridge Loan 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

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

PRICE RANGE AND TRADING VOLUME OF UNITS

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, 2005	$	21.49	$	20.65	4,206,861
April, 2005	$	20.50	$	20.20	4,435,841
May 1 to 10, 2005	$	18.65	$	18.45	1,678,026

On May 6, 2005, being the last day on which the Trust Units traded prior to the public announcement of the Offering, the closing price of the Trust Units on the TSX was $18.44.  On May 10, 2005, being the last day on which the Trust Units traded prior to the date of this short form prospectus, the closing price of the Trust Units on the TSX was $18.25.

RECORD OF CASH DISTRIBUTIONS

The Trust may 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.  The following table summarizes cash distributions made or declared by the Trust to the Unitholders since its inception.  Distributions are not guaranteed.  See “Risk Factors”.

Record Date	Payment Date	Distribution per Trust Unit
January 31, 2005	February 15, 2005	$	0.20
February 22, 2005	March 15, 2005	$	0.20
March 22, 2005	April 15, 2005	$	0.20
April 22, 2005	May 16, 2005	$	0.20

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USE OF PROCEEDS

After deducting the Underwriters’ fee of $17,160,000, and prior to the deduction of the estimated expenses of the Offering of $250,000, the Trust will have received net proceeds from the sale of the Subscription Receipts and Debentures of $338,040,000.  If the Option is exercised in full, the net proceeds to the Trust from the sale of the Subscription Receipts and Debentures will be $361,980,000, after deducting the Underwriters’ fee of $18,420,000 and prior to the deduction of the estimated expenses of the Offering.  The net proceeds of the Offering will be used by the Trust to pay down all of the amount owing under Equity Bridge Loan and fund a portion of the purchase price of the EnCana Assets pursuant to the EnCana Acquisition.

PLAN OF DISTRIBUTION

Pursuant to the Underwriting Agreement, the Trust has agreed to issue and sell an aggregate of 16,400,000 Subscription Receipts and 60,000 Debentures to the Underwriters and the Underwriters have severally agreed to purchase such Subscription Receipts and Debentures on May 26, 2005, or such other date not later than June 15, 2005 as may be agreed among the parties to the Underwriting Agreement.  Delivery of the Subscription Receipts and Debentures is conditional upon payment on closing of $18.00 per Subscription Receipt by the Underwriters to the Escrow Agent and $1,000 per Debenture by the Underwriters to the Trust.  The Underwriting Agreement provides that the Trust will pay the Underwriters’ fee of $0.90 per Subscription Receipt for Subscription Receipts issued and sold by the Trust and of $40 per Debenture for Debentures issued and sold by the Trust, for an aggregate fee payable by the Trust of $17,160,000, in consideration for their services in connection with the Offering.  The Underwriters’ fee in respect of the Subscription Receipts is payable as to 50% upon the closing of the Offering and 50% upon closing of the EnCana Acquisition.  If the EnCana Acquisition is not completed by 5:00 p.m. (Calgary time) on July 31, 2005, the Underwriters’ fee in respect of the Subscription Receipts will be reduced to the amount payable upon closing of the Offering.  The terms of the Offering were determined by negotiation between the Administrator, on behalf of the Trust, and BMO Nesbitt Burns Inc. on their own behalf and on behalf the other Underwriters.

The Trust has granted to the Underwriters the Option to purchase up to an additional 1,400,000 Subscription Receipts at a price of $18.00 per Subscription Receipt, exercisable in whole or in part, at any time up to 24 hours prior to the closing of the Offering.

The obligations of the Underwriters under the Underwriting Agreement are several and not joint, and may be terminated at their discretion upon the occurrence of certain stated events. The obligations of the Trust and the Underwriters under the Underwriting Agreement to complete the purchase and sale of the Subscription Receipts and Debentures will terminate if the EnCana Acquisition is terminated or the Trust has advised the Underwriters or announced to the public that it does not intend to proceed with the EnCana Acquisition. If an Underwriter fails to purchase the Subscription Receipts or the Debentures that it has agreed to purchase, the other Underwriters may, but are not obligated to, purchase such Subscription Receipts or Debentures.  The Underwriters are, however, obligated to take up and pay for all Subscription Receipts if any are purchased under the Underwriting Agreement.  The Underwriting Agreement also provides that the Trust and the Administrator will indemnify the Underwriters and their directors, officers, agents, shareholders and employees against certain liabilities and expenses.

Except in certain limited circumstances, the Subscription Receipts and Debentures will be issued in “book-entry only” form and must be purchased or transferred through a participant in the depository service of CDS.  See “Description of the Subscription Receipts” and “Description of Debentures”.

The Trust has been advised by the Underwriters that, in connection with the Offering, the Underwriters may effect transactions that stabilize or maintain the market price of the Subscription Receipts, the Debentures or the Trust Units at levels other than those that might otherwise prevail in the open market. Such transactions, if commenced, may be discontinued at any time.

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The Trust has agreed that, subject to certain exceptions, it will not offer or issue, or enter into an agreement to offer or issue, Trust Units or any securities convertible or exchangeable into Trust Units for a period of 90 days subsequent to the closing date of the Offering without the prior written consent of BMO Nesbitt Burns Inc., on behalf of the Underwriters, which consent may not be unreasonably withheld.

The Trust has applied to list the Subscription Receipts, the Debentures and the Trust Units issuable pursuant to the Subscription Receipts and on the conversion, redemption or maturity of the Debentures on the TSX.   Listing will be subject to the Trust fulfilling all of the listing requirements of the TSX.  There is currently no market through which the Subscription Receipts or Debentures may be sold and purchasers may not be able to resell Subscription Receipts or Debentures purchased under this short form prospectus.

The Subscription Receipts, the Debentures and the Trust Units issuable pursuant to the Subscription Receipts and on the conversion, redemption or maturity of the Debentures (the “Securities”) have not been and will not be registered under the United States Securities Act of 1933, as amended (the “U.S. Securities Act”), or any state securities laws, and, accordingly, the Securities may not be offered or sold within the United States or to U.S. persons (as such term is defined in Regulation S under the U.S. Securities Act) except in transactions exempt from the registration requirements of the U.S. Securities Act and applicable state securities laws. The Underwriting Agreement permits the Underwriters to offer and resell the Subscription Receipts and Debentures that they have acquired pursuant to the Underwriting Agreement to certain qualified institutional buyers in the United States, provided such offers and sales are made in accordance with Rule 144A under the U.S. Securities Act.  Moreover, the Underwriting Agreement provides that the Underwriters will offer and sell the Subscription Receipts and Debentures outside the United States only in accordance with Regulation S under the U.S. Securities Act.

In addition, until 40 days after the commencement of the Offering, an offer or sale of Securities within the United States by any dealer (whether or not participating in the Offering) may violate the registration requirements of the U.S. Securities Act if such offer or sale is made otherwise than in accordance with an exemption from registration under the U.S. Securities Act.

RELATIONSHIP BETWEEN THE TRUST AND BMO NESBITT BURNS INC.

BMO Nesbitt Burns Inc. is a wholly-owned subsidiary of Bank of Montreal, a Canadian chartered bank (the “Bank”).  The Bank is a lender to the Administrator.  Accordingly, the Trust may be considered a “connected issuer” of BMO Nesbitt Burns Inc. under applicable Canadian securities legislation.

Under the Credit Facility and the Equity Bridge Loan, the Administrator was indebted to the Bank for an aggregate amount of $124.075 million as at May 10, 2005.  The Administrator is in compliance with all material terms of the agreements governing the Credit Facility and the Bank has not waived any material breach by the Administrator of such agreements since their execution.  Neither the financial position of the Administrator nor the value of the security under the Credit Facility has changed substantially since the indebtedness under the Credit Facility was incurred.

The decision to distribute the Subscription Receipts and Debentures offered hereby and the determination of the terms of the Offering were made through negotiations between the Administrator on behalf of the Trust and the Underwriters. The Bank did not have any involvement in such decision or determination, but has been advised of the issuance and terms thereof. As a consequence of the offering, BMO Nesbitt Burns Inc. will receive its share of the underwriting fee payable by the Trust to the Underwriters.

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INTEREST OF EXPERTS

Certain legal matters relating to the Offering will be passed upon by Heenan Blaikie LLP on behalf of the Trust.  As at the date hereof, the partners and associates of Heenan Blaikie LLP, as a group, own, directly or indirectly, less than 1% of the outstanding Trust Units.  Mr. James Pasieka, a director and the corporate secretary of the Administrator, is a partner of Heenan Blaikie LLP.

Certain legal matters relating to the Offering will be passed upon by Bennett Jones LLP on behalf of the Underwriters.  As at the date hereof, the partners and associates of Bennett Jones LLP, as a group, own, directly or indirectly, less than 1% of the outstanding Trust Units.

Reserve estimates contained herein and in the AIF have been prepared by GLJ, McDaniel and Sproule.  As of the date hereof, the principals, directors, officers and associates of each of GLJ, McDaniel and Sproule, as a group in each case, own, directly or indirectly, less than 1% of the outstanding Trust Units.

CERTAIN CANADIAN FEDERAL INCOME TAX CONSIDERATIONS

In the opinion of Heenan Blaikie LLP and Bennett Jones LLP (collectively, “Counsel”), the following summary, as of the date hereof, describes the principal Canadian federal income tax considerations generally applicable under the Tax Act and the regulations thereunder (the “Regulations”) to a subscriber who acquires Subscription Receipts or Debentures pursuant to the Offering and who, for purposes of the Tax Act and at all relevant times, holds the Subscription Receipts, the Debentures and the Trust Units issuable pursuant to the Subscription Receipts or on the conversion, redemption or maturity of the Debentures (the “Securities”) as capital property and deals at arm’s length with the Trust and the Underwriters. Generally speaking, the Securities will be considered to be capital property to a holder provided the holder does not hold the Securities in the course of carrying on a business of trading or dealing in securities and has not acquired them in one or more transactions considered to be an adventure in the nature of trade. Certain holders who might not otherwise be considered to hold their Securities as capital property may, in certain circumstances, be entitled to have them treated as capital property by making the election permitted by subsection 39(4) of the Tax Act. This summary is not applicable to: (i) a holder that is a “financial institution”, as defined in the Tax Act for purposes of the mark-to-market rules; (ii) a holder an interest in which would be a “tax shelter investment” as defined in the Tax Act; or (iii) a holder that is a “specified financial institution” as defined in the Tax Act.  Any such holder should consult its own tax advisor with respect to an investment in the Securities.

This summary is based upon the provisions of the Tax Act and the Regulations in force as of the date hereof, all specific proposals to amend the Tax Act and/or the Regulations that have been publicly announced by or on behalf of the Minister of Finance (Canada) prior to the date hereof (the “Proposed Amendments”) and Counsels’ understanding of the current published administrative and assessing practices of CRA. This summary assumes the Proposed Amendments will be enacted in the form proposed, however, no assurance can be given that the Proposed Amendments will be enacted in their current form, or at all. This summary is not exhaustive of all possible Canadian federal income tax considerations and, except for the Proposed Amendments, does not take into account any changes in the law, whether by legislative, governmental or judicial action, nor does it take into account provincial, territorial or foreign tax considerations, which may differ significantly from those discussed herein.

This summary is of a general nature only and is not intended to be, nor should it be construed to be, legal or tax advice to any prospective purchaser or holder of Securities, and no representations with respect to the income tax consequences to any prospective purchaser or holder are made. Consequently, prospective holders should consult their own tax advisors with respect to their particular circumstances.

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Taxation of Holders of Subscriptions Receipts Resident in Canada

No gain or loss will be realized by a holder on the issuance of a Trust Unit pursuant to a Subscription Receipt.  The holder’s cost of a Trust Unit issued pursuant to a Subscription Receipt will be equal to the holder’s adjusted cost base of such Subscription Receipt immediately prior to the issuance of the Trust Unit.  However, if the EnCana Acquisition is completed prior to the Termination Time, the holder of a Subscription Receipt, in addition to receiving a Trust Unit in exchange therefor, will be entitled to receive a payment in respect of Special Interest, which payment will include the amount of any interest which has accrued on the Escrow Funds.  Counsel is of the view that the amount of Special Interest received by the holder must be included in the holder’s income. The cost of any Trust Units acquired pursuant to the Subscription Receipts must be averaged with the adjusted cost base of any other Trust Units held by the Unitholder to determine the adjusted cost base of each Trust Unit held.

A disposition or deemed disposition by a holder of a Subscription Receipt, other than on the exchange thereof for a Trust Unit, but including on the repayment of the issue price thereof by the Trust in the event the EnCana Acquisition is not completed before the Termination Time, will generally result in the holder realizing a capital gain (or capital loss) equal to the amount by which the proceeds of disposition are greater (or less) than the aggregate of the holder’s adjusted cost base thereof and any reasonable costs of disposition.  In the event that a holder becomes entitled to the repayment of the issue price of a Subscription Receipt as a consequence of the EnCana Acquisition not becoming effective prior to the Termination Time, any amount that is paid to the holder by the Trust as or on account of interest on the Escrowed Funds will be included in the holder’s income and excluded from the holder’s proceeds of disposition.

One-half of any capital gain realized by the holder will be included in the holder’s income under the Tax Act for the year of disposition as a taxable capital gain. One-half of any capital loss realized on a disposition of a Subscription Receipt may be deducted against taxable capital gains realized by the holder in the year of disposition, in the three preceding taxation years or in any subsequent taxation year, to the extent and under the circumstances described in the Tax Act.

A capital gain realized by a holder who is an individual may give rise to a liability for alternative minimum tax. A holder that is throughout the year a “Canadian-controlled private corporation” (as defined in the Tax Act) may be liable to pay an additional refundable tax of 6-2/3 % on certain investment income, including interest and taxable capital gains.

Taxation of Holders of Subscriptions Receipts Not Resident in Canada

No gain or loss will be realized by a holder on the issuance of a Trust Unit pursuant to a Subscription Receipt. A holder of Subscription Receipts who is not resident or deemed to be resident in Canada (a “Non-Resident”) will be subject to withholding tax on such holder’s proportionate share of interest on the Escrowed Funds which is paid or credited to such holder at the rate of 25%,unless such rate is reduced under the provisions of a tax treaty between Canada and the holder’s jurisdiction of residence. A Non-Resident who is resident in the United States and who is entitled to claim the benefit of the Canada-US Income Tax Convention (1980) will generally be entitled to have the rate of withholding reduced to 10% of the amount of any interest paid or credited.  In this regard, CRA takes the position that U.S. limited liability companies generally are not entitled to claim the benefit of the Canada-US Income Tax Convention (1980).  If and to the extent the Escrowed Funds are invested in obligations of, or guaranteed by, the Government of Canada, interest on such obligations that is paid or credited to a Non-Resident holder of Subscription Receipts will not be subject to Canadian withholding tax.   Special Interest payments received by a Non-Resident holder in excess of interest earned on the Escrow Funds may also be subject to Canadian withholding tax.

A disposition or deemed disposition of Subscription Receipts will not give rise to any capital gains subject to tax under the Tax Act to a Non-Resident holder provided that the Subscription Receipts are not “taxable Canadian property” of the holder for the purposes of the Tax Act. Generally, Subscription Receipts will not constitute “taxable

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Canadian property” to a Non-Resident holder at the time of the disposition or deemed disposition thereof unless (i) the holder uses or holds or is deemed to use or hold the Subscription Receipts (or the Trust Units issuable pursuant thereto) in, or in the course of, carrying on a business in Canada, (ii) the Subscription Receipts (or the Trust Units issuable pursuant thereto) are “designated insurance property” of the holder for purposes of the Tax Act, (iii) the holder, persons with whom the holder does not deal at arm’s length (within the meaning of the Tax Act) or the holder together with such persons owned 25% or more of the Trust Units at any time during the 60-month period immediately preceding the disposition; or (iv) the Trust is not a mutual fund trust for the purposes of the Tax Act at the time of disposition.

Taxation of Holders of Debentures Resident in Canada

(i)           Taxation of Interest on Debentures

A holder of Debentures that is a corporation, partnership, unit trust or any trust of which a corporation or a partnership is a beneficiary will be required to include in computing its income for a taxation year all interest on the Debentures that accrues to it to the end of the particular taxation year or that has become receivable or is received by it before the end of that taxation year, except to the extent that such interest was included in computing the holder’s income for a preceding taxation year.

Any other holder will be required to include in computing income for a taxation year all interest on the Debentures that is received or receivable by the holder in that taxation year (depending upon the method regularly followed by the holder in computing income), except to the extent that the interest was included in the holder’s income for a preceding taxation year.  In addition, such holder will be required to include in computing income for a taxation year any interest that accrues to the holder on the Debenture to the end of any “anniversary day” (as defined in the Tax Act) in that year to the extent such interest was not otherwise included in the holder’s income for that year or a preceding year.

A holder of a Debenture who exchanges the Debenture for Trust Units pursuant to the conversion privilege will be entitled to receive a payment in respect of accrued and unpaid interest in respect of the Debenture up until the time of the exchange.  The holder will be required to include such payment in computing income to the extent that such interest was not otherwise included in the holder’s income for the taxation year or a preceding taxation year.   Similarly, on any other disposition or deemed disposition of a Debenture, including a payment on maturity, redemption or purchase for cancellation of a Debenture, the holder generally will be required to include in computing income the amount of interest accrued on the Debenture from the date of the last interest payment to the date of disposition to the extent that such amount has not otherwise been included in computing the holder’s income for the taxation year or a previous taxation year.

A holder that is throughout the year a “Canadian-controlled private corporation” (as defined in the Tax Act) may be liable to pay an additional refundable tax of 6-2/3 % on certain investment income, including interest.

(ii)          Disposition of Debentures

A holder of a Debenture who exchanges the Debenture for Trust Units pursuant to the conversion privilege will be considered to have disposed of the Debenture for proceeds of disposition equal to the aggregate of the fair market value of the Trust Units so acquired at the time of the exchange and the amount of any cash received in lieu of any fractional Trust Unit.  If the Trust redeems a Debenture prior to maturity or repays a Debenture upon maturity and the holder does not exercise the conversion privilege prior to such redemption or repayment, the holder will be considered to have disposed of the Debenture for proceeds of disposition equal to the amount received by the holder (other than the amount received as interest) on such redemption or repayment. If the holder receives Trust Units on redemption or repayment, the holder will be considered to have received proceeds of disposition equal to the fair market value of the Trust Units so received and the amount of any cash received in lieu of any fractional Trust Unit (less any portion of such amount that must be included in the holder’s income on account of accrued interest).

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The cost to the holder of any Trust Units received on an exchange, redemption or repayment of a Debenture will be equal to their fair market value at the time of the exchange, redemption or repayment and must be averaged with the adjusted cost base of all other Trust Units held at that time as capital property by the holder for the purpose of calculating the adjusted cost base of each such Trust Unit.

On any disposition or deemed disposition of a Debenture as described above or otherwise, the holder thereof will generally realize a capital gain (or capital loss) equal to the amount by which the proceeds of disposition are greater (or less) than the aggregate of the holder’s adjusted cost base of the Debenture and any reasonable costs of the disposition. One-half of any capital gain realized by the holder will be included in the holder’s income under the Tax Act for the year of disposition as a taxable capital gain. One-half of any capital loss realized on a disposition of a Debenture may be deducted against taxable capital gains realized by the holder in the year of disposition, in the three preceding taxation years or in any subsequent taxation year, to the extent and under the circumstances described in the Tax Act.

A capital gain realized by a holder who is an individual may give rise to a liability for alternative minimum tax. A holder that is throughout the year a “Canadian-controlled private corporation” (as defined in the Tax Act) may be liable to pay an additional refundable tax of 6-2/3 % on certain investment income, including taxable capital gains.

Taxation of Holders of Debentures Not Resident in Canada

A Non-Resident holder of a Debenture will generally be subject to Canadian withholding tax at the rate of 25% on interest paid or credited pursuant to the Debenture, unless such rate is reduced under the provisions of a tax treaty between Canada and the holder’s jurisdiction of residence. A Non-Resident holder of a Debenture who is resident in the United States and who is entitled to claim the benefit of the Canada-US Income Tax Convention (1980) will generally be entitled to have the rate of withholding reduced to 10% of the amount of any interest paid or credited. Any premium paid on a redemption or repurchase of Debentures prior to maturity may be deemed to be interest for Canadian withholding tax purposes.

A disposition or deemed disposition of a Debenture, whether on conversion, redemption, or otherwise, will not give rise to any capital gains subject to tax under the Tax Act to a Non-Resident holder provided that (i) the holder does not hold or use and is not deemed to hold or use the Debenture in the course of carrying on business in Canada; (ii) the Debenture is not a “designated insurance property” of the holder for purposes of the Tax Act; (iii) the Trust is a mutual fund trust for the purposes of the Tax Act at the time of the disposition or deemed disposition; and (iv) the Debenture does not otherwise constitute “taxable Canadian property” to the holder within the meaning of the Tax Act.  Generally, a Debenture will not otherwise constitute taxable Canadian property to a non-resident holder at the time of the disposition or deemed disposition thereof unless the holder, persons with whom the holder does not deal at arm’s length (within the meaning of the Tax Act) or the holder together with such persons owned 25% or more of the Trust Units at any time during the 60-month period immediately preceding the disposition.  To the extent that the fair market value of Trust Units received by a Non-Resident on a conversion of a Debenture exceeds the issue price of the Debenture, such excess amount may be deemed to be interest for the purposes of the Tax Act and may be subject to Canadian withholding tax.

A transfer of a Debenture by a Non-Resident holder to a purchaser who is resident in Canada at a time when interest has accrued and remains unpaid on the Debenture may be subject to Canadian withholding tax to the extent of the portion of the purchase price attributable to such accrued interest.   Non-Resident transferors of Debentures should consult their own advisors as to whether any withholding tax obligation applies in their particular circumstances.

Holders of Trust Units Resident in Canada

This portion of the summary is applicable to Unitholders who, for the purposes of the Tax Act and at all relevant times, are resident or deemed to be resident in Canada.

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Income of a Unitholder from the Trust Units will be considered to be income from property for the purposes of the Tax Act. Any loss of the Trust for the purposes of the Tax Act cannot be allocated to or treated as a loss of a Unitholder, and income of a Unitholder from the Trust Units will be considered to be income from property and not resource income (or “resource profits”) for the purposes of the Tax Act.  A Unitholder will generally be required to include in computing income for a particular taxation year of the Unitholder the portion of the net income of the Trust for a taxation year, including taxable dividends and net realized taxable capital gains, that is paid or payable to the Unitholder in that particular taxation year, whether such amount is payable in cash or in Reinvested Trust Units (as defined below).

The non-taxable portion of net realized capital gains of the Trust that is paid or payable to a Unitholder in a year will not be included in computing the Unitholder’s income for the year.  Any other amount in excess of the net income of the Trust that is paid or payable by the Trust to a Unitholder in a year will not generally be included in the Unitholder’s income for the year. However, where such an amount is paid or becomes payable to a Unitholder, other than as proceeds of disposition of Trust Units or fractions thereof, the adjusted cost base of the Trust Units held by such Unitholder will be reduced by such amount. To the extent that the adjusted cost base of a Trust Unit would otherwise be less than nil, the negative amount will be deemed to be a capital gain of a Unitholder from the disposition of the Trust Unit in the year in which the negative amount arises.

The adjusted cost base to a Unitholder of a Trust Unit will generally be equal to the average of the cost of all Trust Units held by the Unitholder and will be reduced by certain distributions as noted above. Reinvested Trust Units (as defined below) issued to a Unitholder as a non-cash distribution of income will have a cost equal to the amount of such income and this cost will be required to be averaged with the adjusted cost base of all other Trust Units held by the Unitholder as capital property.  Upon the disposition or deemed disposition by a Unitholder of a Trust Unit, whether on redemption or otherwise, the Unitholder will generally realize a capital gain (or a capital loss) equal to the amount by which the proceeds of disposition are greater (or less) than the aggregate of the Unitholder’s adjusted cost base of the Trust Unit and any reasonable costs of disposition.  Where Trust Units are redeemed and any property of the Trust, including Administrator Notes or Redemption Notes (as defined in the Trust Indenture), is distributed in specie to the Unitholder, the proceeds of disposition to the Unitholder of the Trust Units will be equal to the aggregate cash received and the fair market value of the property so distributed less any portion thereof that is considered to be a distribution out of the income of the Trust.  One-half of any capital gain (a “taxable capital gain”) realized by a Unitholder in a taxation year and any net taxable capital gain designated by the Trust to a Unitholder must be included in the Unitholder’s income for the year, and one-half of any capital loss (an “allowable capital loss”) realized by a Unitholder in a taxation year must be deducted from taxable capital gains realized by the Unitholder in that year. Allowable capital losses for a taxation year in excess of taxable capital gains for that year generally may be carried back and deducted in any of the three preceding taxation years or carried forward and deducted in any subsequent taxation year against net taxable capital gains realized in such years, in accordance with, and under the circumstances described in, the Tax Act.

Taxable capital gains realized by a Unitholder who is an individual may give rise to alternative minimum tax depending on the Unitholder’s circumstances. A Unitholder that throughout the relevant taxation year is a “Canadian-controlled private corporation”, as defined in the Tax Act, may be liable to pay an additional refundable tax of 6-2/3% on certain investment income, including taxable capital gains and certain income from the Trust.

The receipt of Administrator Notes or Redemption Notes in substitution for Trust Units may result in a change in the income tax characterization of distributions. Such a Unitholder will be required to include in income, interest on the Administrator Notes or Redemption Notes (including interest that had accrued to the date of the acquisition of the Administrator Notes by the Unitholder) in accordance with the provisions of the Tax Act. To the extent that the Unitholder is required to include in income any interest that had accrued to the date of the acquisition of the Administrator Notes, an offsetting deduction will be available. The adjusted cost base of an Administrator Note or Redemption Note distributed or issued by the Trust, as the case may be, to a Unitholder upon a redemption of Trust Units will be equal to the fair market value of the Administrator Note or Redemption Note at the time of the

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distribution or issuance less, in the case of the Administrator Notes, any accrued interest thereon. Unitholders should consult with their own tax advisors as to the consequences of receiving Administrator Notes or Redemption Notes on a redemption of Trust Units.

Holders of Trust Units Not Resident in Canada

This portion of the summary applies to a Unitholder who, for the purposes of the Tax Act and at all relevant times, is not resident in Canada and is not deemed to be resident in Canada, does not use or hold, and is not deemed to use or hold, Trust Units in, or in the course of, carrying on a business in Canada, and is not an insurer who carries on an insurance business or is deemed to carry on an insurance business in Canada or elsewhere (a “Non-Resident”).

Any distribution of income of the Trust to a Non-Resident Unitholder will generally be subject to Canadian withholding tax at the rate of 25%, unless such rate is reduced under the provisions of a tax treaty between Canada and the Non-Resident’s jurisdiction of residence. A Non-Resident Unitholder who is resident in the United States and who is entitled to claim the benefit of the Canada-US Income Tax Convention (1980) will generally be entitled to have the rate of withholding reduced to 15% of the amount of any income distributed.

Pursuant to the Proposed Amendments, the Trust may also be obligated to withhold at the rate of 15% on all distributions by the Trust to a Non-Resident that are not otherwise included in the income of the Non-Resident for the purposes of the Tax Act or otherwise subject to withholding taxes under the Tax Act.  In the event that the Non-Resident subsequently realizes a loss on the disposition of the Trust Units, the Non-Resident may, in certain circumstances, be entitled to a refund of all or a portion of this tax subject to the filing of appropriate income tax returns.

A disposition or deemed disposition of a Trust Unit by a Non-Resident, whether on redemption or otherwise, will not give rise to any capital gains subject to tax under the Tax Act provided that the Trust Units are not “taxable Canadian property” of the Non-Resident for the purposes of the Tax Act. Trust Units will not be considered taxable Canadian property to a Non-Resident unless: (i) the Non-Resident holds or uses, or is deemed to hold or use the Trust Units in the course of carrying on business in Canada; (ii) at any time during the 60 month period immediately preceding the disposition of the Trust Units the Non-Resident or persons with whom the Non-Resident did not deal at arm’s length or any combination thereof held 25% or more of the issued Trust Units; or (iii) the Trust were not a mutual fund trust for the purposes of the Tax Act on the date of disposition.

Interest paid or credited on Administrator Notes or Redemption Notes (as defined in the Trust Indenture) to a Non-Resident who receives such notes on a redemption of Trust Units will be subject to Canadian withholding tax at a rate of 25%, unless such rate is reduced under the provisions of a tax treaty between Canada and the Non-Resident’s jurisdiction of residence. A Non-Resident who is resident in the United States and who is entitled to claim the benefit of the Canada-US Income Tax Convention (1980) generally will be entitled to have the rate of withholding reduced to 10% of the amount of such interest.

Qualification as a Mutual Fund Trust

The Trust qualifies as a “unit trust” as defined in the Tax Act, and this summary assumes that the Trust also qualifies and will continue to qualify at all times as a “mutual fund trust” as defined in the Tax Act.  In order to qualify as a mutual fund trust the sole undertaking of the Trust must be the investing of its funds in property (other than real property or interests in real property) and the Trust must comply on a continuous basis with certain requirements relating to the qualification of the Trust Units for distribution to the public, the number of Unitholders and the dispersal of ownership of Trust Units.  Subject to some exceptions, the Tax Act currently provides that the Trust may not reasonably be considered to have been established or maintained primarily for the benefit of non-residents of Canada.  If the Trust were to not qualify as a mutual fund trust at any particular time, the income tax considerations for the Trust and Unitholders would be materially different in certain respects from those contained herein and the Trust could be liable to pay tax under Part XII.2 of the Tax Act. Counsel has been advised by the

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Administrator that the Trust has been or has been deemed to be a mutual fund trust from the beginning of the Trust’s first taxation year.

Taxation of the Trust

The Trust is subject to taxation in each taxation year on its income for the year less the portion thereof that is paid or payable in the year to Unitholders and which is deducted by the Trust in computing its income for purposes of the Tax Act. An amount will be considered to be payable to a Unitholder in a taxation year if it is paid in the year by the Trust or the Unitholder is entitled in that year to enforce payment of the amount. The taxation year of the Trust will end on December 31 of each year.

The Trust will be required to include, among other things, in its income for each taxation year: (i) income from the NPI on an accrual basis; and (ii) all interest on the Administrator Notes that accrues to it to the end of the year, or becomes receivable or is received by it before the end of the year, except to the extent that such interest was included in computing its income for a preceding year.

The Trust will generally be entitled to deduct on an annual basis, reasonable administrative expenses incurred on its ongoing investment activities provided such expenses are reasonable and otherwise deductible, subject to the relevant provisions of the Tax Act, including the Proposed Amendments, which require that the Trust have a reasonable expectation of profit. The Trust will also be entitled to deduct a portion of any costs incurred by it in connection with the issuance of the Securities. The amount of such expenses deductible by the Trust in a taxation year is 20% of such issue expenses, pro-rated where the Trust’s taxation year is less than 365 days, to the extent such expenses were not deductible in a previous taxation year. The Trust may also deduct, in computing its income from all sources for a taxation year, an amount not exceeding 10% on a declining balance basis of its cumulative Canadian oil and gas property expense account at the end of that year pro-rated where the Trust’s taxation year is less than 365 days. Counsel is advised that the cost of the NPI has been added to the Trust’s cumulative Canadian oil and gas property expense account. Under the Trust Indenture, income received by the Trust may be used to finance cash redemptions of Trust Units. The Trust Indenture also contemplates other situations in which the Trust may not have sufficient available funds to distribute all of its income by way of cash distributions. In such circumstances, such income will be payable to Unitholders in the form of additional Trust Units (“Reinvested Trust Units”).

Counsel has been advised by the Administrator that the Trust shall make sufficient distributions in each year of its net income for tax purposes so that the Trust generally will not be liable for any material amounts of income tax under the Tax Act.

ELIGIBILITY FOR INVESTMENT

In the opinion of Counsel, based on representations from the Administrator and the Trust as to certain factual matters, and subject to the qualifications and assumptions discussed under the heading “Certain Canadian Federal Income Tax Considerations”, the Subscription Receipts, the Debentures and the Trust Units issuable pursuant to the Subscription Receipts and on the conversion, redemption or maturity of the Debentures will, on the date of closing, be qualified investments for trusts governed by registered retirement savings plans (“RRSP”), registered retirement income funds (“RRIF”), deferred profit sharing plans (“DPSP”) (except, in the case of the Debentures, a DPSP to which the Trust has made a contribution) and registered education savings plans (“RESP”) (collectively, “Exempt Plans”) under the Tax Act as in effect on the date hereof.  The Administrator has advised Counsel that the cost amount of foreign property of the Trust, if any, has always been and will be less than 30% of the cost amount of all property of the Trust and accordingly the Subscription Receipts, the Debentures and the Trust Units issuable pursuant to the Subscription Receipts and on the conversion, redemption or maturity of the Debentures will not, on the date of closing, constitute foreign property for such plans. Under proposed amendments to the Regulations under the Tax Act, Subscription Receipts will only be a qualified investment for an Exempt Plan if the Trust deals at arm’s length (within the meaning of the Tax Act) with each person who is an annuitant, a beneficiary, an employer

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or a subscriber under the governing plan of the particular Exempt Plan.  The Minister of Finance (Canada) announced as part of the 2005 federal budget that the foreign property restrictions would be removed from the Tax Act for months that end after 2004.  There is no assurance that the budget proposals will be enacted as proposed, or at all.  See “Risk Factors - Investment Eligibility and Mutual Fund Trust Status” in the AIF.

RISK FACTORS

An investment in the Subscription Receipts, Debentures and Trust Units is subject to certain risks. Investors should carefully consider the risks factors described under the heading “Risk Factors” in the AIF.  In addition to the risk factors set out in the AIF, investors should consider the following additional risk factors:

Possible Failure to Complete the EnCana Acquisition or the APF Combination

Both the EnCana Acquisition and APF Combination are subject to normal commercial risks that the transactions may not be completed on the terms negotiated or at all.  The APF Combination is subject to necessary court and regulatory approvals and the approval of the unitholders of APF, all of which are beyond the control of the Trust.  If closing of either the EnCana Acquisition or the APF Combination does not take place as contemplated, the Trust could suffer adverse consequences, including the forfeiture of deposits, the payment of break fees or the loss of investor confidence.  In addition, if the EnCana Acquisition does not take place by the Termination Time, the Escrow Agent and the Trust must repay to holders of Subscription Receipts an amount equal to the issue price thereof plus a pro rata share of the interest earned on the Escrowed Funds and the Debentures will mature on the Initial Maturity Date.

Possible Failure to Realize Anticipated Benefits of the EnCana Acquisition and the APF Combination

The Trust is proposing to complete the EnCana Acquisition and the APF Combination to strengthen its 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 future acquisitions the Trust may complete 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 and the Administrator’s ability to realize the anticipated growth opportunities and synergies from combining the acquired businesses and operations with those of the Trust. 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.

Operational and Reserves Risks Relating to the EnCana Assets and the APF Assets

The risk factors set forth in the AIF relating to the oil and natural gas business and the operations and reserves of the Trust apply equally in respect of the EnCana Assets and the APF Assets that the Trust intends to acquire pursuant to the EnCana Acquisition and the APF Combination.  In particular, the reserve and recovery information contained in the APF Reports and EnCana Asset Reports in respect of the APF Assets and the EnCana Assets, respectively, is only an estimate of actual production from, and ultimate reserves of, those properties.  Reserves of those properties may be greater or less than the estimates contained in such reports.

Market for Securities

There is currently no market through which the Subscription Receipts or Debentures may be sold and purchasers may not be able to resell Subscription Receipts or Debentures purchased under this short form prospectus.  There can be no assurance that an active trading market will develop for the Subscription Receipts or the Debentures after the Offering, or if developed, such a market will be sustained at the price level of the Offering.

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Prior Ranking Indebtedness; Absence of Covenant Protection

The Debentures will be subordinate to all Senior Indebtedness and to any indebtedness of creditors of the Trust.  This includes the any indebtedness outstanding under the Credit Facility and the Equity Bridge Loan.  The Debentures will also be effectively subordinate to claims of creditors of the Trust’s subsidiaries except to the extent the Trust is a creditor of such subsidiaries ranking at least pari passu with such other creditors.

The Indenture will not limit the ability of the Trust to incur additional debt or liabilities (including Senior Indebtedness) or to make distributions.  The Indenture does not contain any provision specifically intended to protect holders of the Debentures in the event of a future leveraged transaction involving the Trust.

Possible Dilutive Effects on Holders of Trust Units

The Trust may determine to redeem outstanding Debentures for Trust Units, repay outstanding principal amounts thereunder at maturity of the Debentures or arrange for the payment of interest under the Debentures by issuing additional Trust Units. Accordingly, holders of Trust Units may suffer dilution. See “Description of the Debentures”.

MATERIAL CONTRACTS

The following contracts may be material to an investor in Trust Units:

(a)the Trust Indenture;

(b)the note indenture dated January 4, 2005 between the Administrator and Olympia Trust Company governing the issuance of the Administrator Notes;

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

(d)the Administration Agreement;

(e)the support agreement dated January 7, 2005 among the Trust, the Administrator and ExchangeCo concerning certain matters affecting the Exchangeable Shares;

(f)the voting and exchange trust agreement dated January 7, 2005 among the Trust, the Administrator, ExchangeCo and the Trustee concerning certain matters affecting the Exchangeable Shares;

(g)the Trust’s restricted unit plan;

(h)the DRIP Plan;

(i)the EnCana Agreement;

(j)the Combination Agreement;

(k)the Subscription Receipt Agreement; 

(l)the Indenture; and

(m)the Underwriting Agreement.

61

Copies of each of the foregoing agreements (in draft form prior to the closing of the Offering in the case of the Subscription Receipt Agreement and the Indenture) may be inspected during regular business hours at the offices of the Trust, at Suite 3900, 205 - 5th Avenue S.W., Calgary, Alberta, until the expiry of the 30-day period following the date of the final short form prospectus. Copies of each of the foregoing agreements, except the Subscription Receipt Agreement and the Indenture, are available on www.sedar.com.  Copies of the Subscription Receipt Agreement and the Indenture will be available on www.sedar.com following the closing of the offering.

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.

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 is Olympia Trust Company at its principal offices in Calgary, Alberta and at the principal offices of its agent in Toronto, Ontario.

STATUTORY AND CONTRACTUAL RIGHTS OF WITHDRAWAL AND RESCISSION

Securities legislation in certain of the provinces of Canada provides purchasers with the right to withdraw from an agreement to purchase securities. This right may be exercised within two Business Days after receipt or deemed receipt of a prospectus and any amendment. In several of the provinces, securities legislation further provides a purchaser with remedies for rescission or, in some jurisdictions, damages if the prospectus and any amendment contains a misrepresentation or is not delivered to the purchaser, provided that the remedies for rescission or damages are exercised by the purchaser within the time limit prescribed by the securities legislation of the purchaser’s province. The purchaser should refer to any applicable provisions of the securities legislation of the province in which the purchaser resides for the particulars of these rights or consult with a legal advisor.

In addition, original purchasers of Subscription Receipts will have the benefit of a contractual right of rescission exercisable following the issuance of Trust Units to such purchasers.  See “Description of Subscription Receipts”.

62

AUDITORS’ CONSENTS

Consent of KPMG LLP

The Board of Directors of StarPoint Energy Ltd.

We have read the preliminary short form prospectus (the “Prospectus”) of StarPoint Energy Trust (the “Trust”) dated May 11, 2005 relating to the qualification for distribution of 16,400,000 subscription receipts and 60,000 debentures of the Trust.  We have complied with Canadian generally accepted standards for an auditors’ involvement with offering documents.

We consent to the incorporation by reference in the Prospectus of our report to the unitholders of StarPoint Energy Trust on the balance sheet of StarPoint Energy Trust as at December 31, 2004.  Our report is dated March 16, 2005.

We consent to the incorporation by reference in the Prospectus of our report to the shareholders of StarPoint Energy Ltd. on the consolidated balance sheets of StarPoint Energy Ltd. as at December 31, 2004 and December 31, 2003 and the consolidated statements of operations and retained earnings (deficit) and cash flows for the year ended December 31, 2004 and for the period from the commencement of operations on September 5, 2003 to December 31, 2003.  Our report is dated March 16, 2005.

We consent to the use in the Prospectus of our report to the directors of Upton Resources Inc. on the consolidated balance sheet of Upton Resources Inc. as at December 31, 2003 and the consolidated statements of operations and retained earnings and cash flows for the year then ended.  Our report is dated December 6, 2004.

We consent to the use in the Prospectus of our report to the shareholders of E3 Energy Inc. on the consolidated balance sheets of E3 Energy Inc. as at December 31, 2004 and 2003 and the consolidated statements of operations and retained earnings and cash flows for the years then ended.  Our report is dated March 24, 2005.

We consent to the use in the Prospectus of our report to the shareholders of Great Northern Exploration Ltd. on the consolidated balance sheets of Great Northern Exploration Ltd. as at December 31, 2003 and 2002 and the consolidated statements of operations and retained earnings and cash flows for the years then ended.  Our report is dated March 17, 2004.

(signed) “KPMG LLP”

Chartered Accountants

Calgary, Canada

May 11, 2005

63

Consent of Collins Barrow Calgary LLP

The Board of Directors of StarPoint Energy Ltd.

We have read the preliminary short form prospectus (the “Prospectus”) of StarPoint Energy Trust (the “Trust”) dated May 11, 2005 relating to the qualification for distribution of 16,400,000 subscription receipts and 60,000 debentures of the Trust.

We consent to the use in the Prospectus of our report to the directors of Selkirk Energy Canada Ltd., 977529 Alberta Ltd., 3072202 Nova Scotia Company and Five Spot Energy Ltd. on the combined balance sheet of Selkirk Energy Group as at January 31, 2004 and the combined statements of income and retained earnings and cash flows for the year then ended.  Our report is dated November 12, 2004.

(signed) “Collins Barrow Calgary LLP”

Chartered Accountants

Calgary, Canada

May 11, 2005

64

Consents of PricewaterhouseCoopers LLP

The Board of Directors of StarPoint Energy Ltd.

We have read the preliminary short form prospectus (the “Prospectus”) of StarPoint Energy Trust (the “Trust”) dated May 11, 2005 relating to the qualification for distribution of 16,400,000 subscription receipts and 60,000 debentures of the Trust.

We consent to the use in the Prospectus of our report to the unitholders of APF Energy Inc. on the consolidated balance sheets of APF Energy Trust as at December 31, 2004 and December 31, 2003 and the consolidated statements of operations and accumulated earnings and cash flows for the years then ended.  Our report is dated February 25, 2005.

(signed) “PricewaterhouseCoopers LLP”

Chartered Accountants

Calgary, Canada

May 11, 2005

The Board of Directors of StarPoint Energy Ltd.

We have read the preliminary short form prospectus (the “Prospectus”) of StarPoint Energy Trust (the “Trust”) dated May 11, 2005 relating to the qualification for distribution of 16,400,000 subscription receipts and 60,000 debentures of the Trust.

We consent to the use in the Prospectus of our report to the directors of EnCana Corporation on the schedule of revenues, royalties and operating expenses of the EnCana Assets for the years ended December 31, 2004, 2003 and 2002.  Our report is dated April 29, 2005.

(signed) “PricewaterhouseCoopers LLP”

Chartered Accountants

Calgary, Canada

May 11, 2005

65

SCHEDULE “A” - FINANCIAL STATEMENTS OF E3

A - 1

Consolidated Financial Statements of

E3 ENERGY INC.

Years ended December 31, 2004 and 2003

AUDITORS’ REPORT TO THE SHAREHOLDERS

We have audited the consolidated balance sheets of E3 Energy Inc. as at December 31, 2004 and 2003 and the consolidated statements of operations and retained earnings and cash flows for the years then ended. These financial statements are the responsibility of the company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audit in accordance with Canadian generally accepted auditing standards. Those standards require that we plan and perform an audit to obtain reasonable assurance whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation.

In our opinion, these consolidated financial statements present fairly, in all material respects, the financial position of the company as at December 31, 2004 and 2003 and the results of its operations and its cash flows for the years then ended in accordance with Canadian generally accepted accounting principles.

(Signed) “KPMG LLP”

Chartered Accountants

Calgary, Canada

March 24, 2005

E3 ENERGY INC.

Consolidated Balance Sheet

December 31, 2004, with comparative figures for 2003

	2004				2003
					(Restated –
					Notes 3(a) and 7)
Assets
Current assets:
Cash	$			30,910	$		33,003
Accounts receivable	1,588,985				2,060,254
Prepaid expenses and deposits	135,368				164,723
	1,755,263				2,257,980
Property, plant and equipment (note 5)	34,816,921				22,486,290
Future income tax asset (note 12)	—				688,969
	$	36,572,184			$	25,433,239
Liabilities and Shareholders’ Equity
Current liabilities:
Accounts payable and accrued liabilities	$		3,166,556		$		4,165,407
Income taxes payable	—				36,824
Bank loan (note 6)	7,900,000				6,150,000
	11,066,556				10,352,231
Future income tax liability (note 12)	1,322,714				—
Asset retirement obligations (notes 3(a) and 7)	1,840,740				1,523,948
	14,230,010				11,876,179
Shareholders’ equity:
Share capital (note 8)	15,685,001				10,125,027
Contributed surplus (note 11)	494,000				137,420
Retained earnings	6,163,173				3,294,613
	22,342,174				13,557,060
Subsequent event (note 16)
	$		36,572,184		$		25,433,239

See accompanying notes to consolidated financial statements.

E3 ENERGY INC.

Consolidated Statements of Operations and Retained Earnings

Year ended December 31, 2004, with comparative figures for 2003

	2004				2003
					(Restated – Notes 3(a) and 7)
Revenue:
Petroleum and natural gas sales	$	17,344,165			$	7,409,963
Royalties	(2,990,274			)	(1,370,430		)
	14,353,891				6,039,533
Expenses:
Operating	3,869,982				1,829,083
General and administrative	1,659,359				520,315
Transportation	643,096				245,973
Stock-based compensation (notes 2(h) and 9)	356,580				84,584
Interest	285,725				232,336
Asset retirement accretion	104,268				68,449
Depletion and depreciation	3,963,827				1,933,562
	10,882,837				4,914,302
Earnings before income taxes	3,471,054				1,125,231
Income taxes (reduction) (note 12):
Current	12,043				43,577
Future	590,451				(2,430,445		)
	602,494				(2,386,868		)
Net earnings	2,868,560				3,512,099
Retained earnings, beginning of year	3,294,613
As previously reported					(249,605		)
Effect of change in accounting for:
Asset retirement obligations (notes 2 and 7)	—				32,119
	3,294,613				(217,486		)
Retained earnings, end of year	$		6,163,173		$	3,294,613
Net earnings per share:
Basic	$		0.10		$	0.16
Diluted	$		0.09		$	0.16

See accompanying notes to consolidated financial statements.

E3 ENERGY INC.

Consolidated Statements of Cash Flow

Year ended December 31, 2004, with comparative figures for 2003

	2004			2003
				(Restated – Notes 3(a) and 7)
Cash provided from (used in):
Operations:
Net earnings	$	2,868,560		$	3,512,099
Items not affecting cash:
Depletion and depreciation	3,963,827			1,933,562
Asset retirement accretion	104,268			68,449
Stock-based compensation	356,580			84,584
Future income taxes (reduction)	590,451			(2,430,445		)
	7,883,686			3,168,249
Change in non-cash working capital	220,720			336,805
	8,104,406			3,505,054
Financing:
Proceeds from share issue, net of issue costs	6,981,205			3,694,518
Increase in bank loan	1,750,000			2,450,000
Change in non-cash working capital	—			(13,795		)
	8,731,205			6,130,723
Investments:
Corporate acquisition	—			(2,011,407		)
Property, plant and equipment additions	(16,081,933		)	(11,752,579		)
Change in non-cash working capital	(755,771		)	1,403,092
	(16,837,704		)	(12,360,894		)
Decrease in cash	(2,093		)	(2,725,117		)
Cash, beginning of year	33,003			2,758,120
Supplemental cash flow information (note 13)
Cash, end of year	$	30,910		$	33,003

See accompanying notes to consolidated financial statements.

E3 ENERGY INC.

Notes to Consolidated Financial Statements

Years ended December 31, 2004 and 2003

1.Nature of operations:

E3 Energy Inc. (the “Company” or “E3”) is actively engaged in the exploration for, and development and production of natural gas, crude oil and natural gas liquids in the Western Canadian Sedimentary Basin. The Company is subject to the provisions of the Canada Business Corporations Act and its common shares are publicly listed on the Toronto Stock Exchange and trade under the symbol “ETE”.

2.Significant account policies:

The consolidated financial statements have been prepared by management in accordance with Canadian generally accepted accounting principles (“GAAP”) within the framework of the following accounting policies.

(a)Principles of consolidation and basis of presentation:

The consolidated financial statements reflect the activities of the Company and its wholly-owned subsidiaries from the respective dates of acquisition of the subsidiary companies. Inter-company transactions and balances are eliminated upon consolidation.

A portion of the Company’s exploration, development and production activities are conducted jointly with others. These consolidated financial statements reflect only the Company’s proportionate working interest in such activities.

(b)Measurement uncertainty:

Amounts recorded for future depletion and depreciation, the provision for future site restoration costs and the ceiling test calculation are based upon estimates of proved petroleum and natural as reserves, production rates, prices, future costs and other relevant assumptions. By their nature, these estimates are subject to measurement uncertainty, and the impact on the financial statements of future periods could be material. The Company’s independent qualified reserve engineering firms evaluate the Company’s reserve estimates annually.

(c)Petroleum and natural gas operations:

(i)Capitalized costs:

The Company follows the full cost method of accounting for its petroleum and natural gas operations. Under this method all costs related to the exploration for and development of petroleum and natural gas reserves are capitalized into a single Canadian cost centre. Such costs include lease acquisition costs, geological and geophysical expenses, costs of drilling both productive and non-productive wells, gathering and production facilities, lease rentals on non-producing properties, interest on debt directly related to certain acquisitions, and certain other overhead expenditures directly related to exploration and development activities. Proceeds from the disposal of petroleum and natural gas interests are applied against capitalized costs, without any gain or loss being realized, unless such disposal would alter the rate of depletion by 20 percent or more.

Petroleum and natural gas assets are evaluated at least annually to determine that the costs are recoverable and do not exceed the fair value of the properties. The costs are assessed to be recoverable if the sum of the undiscounted cash flows expected from the production of proved reserves and the lower of cost and market of unproved properties exceed the carrying value of the petroleum and natural gas assets. If the carrying value of the petroleum and natural gas assets is not assessed to be recoverable, an impairment loss is recognized to the extent that the carrying value exceeds the sum of the discounted cash flows expected from the production of proved and probable reserves and the lower of cost and market of unproved properties. The cash flows are estimated using the future product prices and costs and are discounted using the risk-free rate.

2

(ii)Depletion and depreciation:

Capitalized costs under the full cost accounting method are depleted and depreciated using the unit-of-production method based upon the proved petroleum and natural gas reserves as determined by independent reservoir engineers. In determining costs subject to depletion the Company includes estimated future costs to be incurred in developing proved reserves including the associated asset retirement csots not yet recognized on the Company’s financial statements and excludes salvage values and the costs of unproved properties. The costs of acquiring and evaluating unproved properties are excluded from costs subject to depletion until it is determined whether or not proved reserves are attributable to the properties or until impairment occurs. For depletion and depreciation purposes, relative volumes of petroleum and natural gas production and reserves are converted at the energy equivalent conversion rate of six thousand cubic feet of natural gas to one barrel of crude oil.

Depreciation on office furniture and other equipment is provided over its useful lives using the declining balance method at a rate of 20 percent.

(iii)Asset retirement obligations:

An asset retirement obligation is recorded as a liability in the period in which a legal obligation is incurred as a result of an acquisition, construction, development and/or normal use of the assets.

The associated asset retirement costs are capitalized as part of the carrying amount of the long-lived asset and depleted and depreciated using a unit-of-production method over the estimated gross proved reserves. Subsequent to the initial measurement of the asset retirement obligations, the obligations are adjusted at the end of each year to reflect the passage of time of changes in the estimated future cash flows underlying the obligation.

(d)Flow-through shares:

The resource expenditures deductions for income tax purposes related to exploration and development activities funded by flow-through share arrangements are renounced to investors in accordance with income tax legislation. To recognize the foregone tax benefits to the Company, the future income tax liability and share capital are adjusted by the estimated cost of the renounced tax deduction when the shares are issued.

3

(e)Per share amounts:

Basic earnings per common share are computed by dividing earnings by the weighted average number of common shares outstanding during the year. Diluted per share amounts reflect the potential dilution that could occur if the Company’s outstanding stock options to purchase common shares were exercised and converted to common shares. The treasury stock method of calculating diluted per share amounts is used whereby any proceeds from the exercise of stock options in addition to the unrecognized amount of stock-based compensation expense are assumed to be used to purchase common shares of the Company at the average market price during the respective period.

(f)Income taxes:

The Company follows the liability method of accounting for income taxes. Future income taxes are calculated based on temporary differences arising from the difference between the tax basis of an asset or liability and its carrying value on the balance sheet using tax rates anticipated to apply in the periods when the temporary differences are expected to reverse. The effect on future taxes for a change in tax rates is recognized in income in the period that includes the enactment date. Future income tax assets are recognized to the extent that realization of such assets is more likely than not.

(g)Revenue recognition:

Revenue associated with the sales of petroleum and natural gas production owned by the Company is recognized when ownership title passes from the Company to its customers and delivery has taken place.

(h)Stock-based compensation plan:

The Company has a stock-based compensation plan as described in Note 9.

Beginning in 2003, the fair value of stock options are expensed over the vesting period. For stock options issued prior to 2003, pro-forma disclosure of the effect on net earnings and earnings per share had the fair value been expensed is provided. The liability for stock options that have been expensed is recorded in contributed surplus until the options are exercised.

4

(i)Derivative financial instruments:

The Company may use derivative financial or hedging instruments to mange its exposure to market risks relating to commodity prices, foreign currency exchange rates, interest rates and power costs, as described in note 14. The Company does not utilize derivative financial instruments for speculative purposes.

Hedge accounting is used when there is a high degree of correlation between price movements in the derivative financial or hedging instrument and the hedged item. The Company documents all relationships between hedging instruments and hedged items. This process includes linking these instruments to identifiable assets and liabilities on the balance sheet or to specific firm commitments or forecasted transactions. The Company also assesses, both at the hedging instrument’s inception and on an ongoing basis, whether the derivatives instruments used in hedging transactions are highly effective in offsetting changes in fair values or cash flow of hedged items. If the determined correlating ceases to exist, hedge accounting is no longer utilized and mark-to-market accounting is used whereby future changes in the market value of the derivative financial instruments are recognized as gains or losses in the period of change.

(j)Comparative amounts:

Certain prior period amounts have been reclassified to conform to current year presentation.

3.Changes in accounting policies:

(a)Asset retirement obligations:

Effective January 1, 2004, the Company retroactively adopted the new Canadian accounting standard for asset retirement obligations with a restatement of prior periods. The new standard requires the Company to record the fair value of an asset retirement obligation as a liability in the period in which it incurs a legal obligation associated with the retirement of tangible long-lived assets that result from the acquisition, construction, development and/or normal use of the assets. The associated asset retirement costs are capitalized as part of the carrying amount of the long-lived asset and depleted using a unit of production method over gross proved reserves. Subsequent to the initial measurement of the asset retirement obligations, the obligations are adjusted at the end of each period to reflect the passage of time and changes in the estimated future cash flows underlying the obligation. The effect of the adoption of the new standard on the financial statements is disclosed in note 7.

5

(b)Stock based compensation:

During the fourth quarter of 2003, the Company prospectively adopted the fair-value method of accounting for stock options granted to employees, officers and directors. The Company records stock based compensation expense on the Consolidated Statement of Operations for all options granted on or after January 1, 2003, with a corresponding increase recorded as contributed surplus. Compensation expense for options granted during 2003 and 2004 are based on the estimated fair values at the time of the grant and recognized over the vesting period of the option. As a result of adopting this accounting standard, the Company recognized $357 thousand of compensation expense during 2004 (2003 - $137 thousand of which $52 thousand was capitalized to property, plant and equipment (see note 5)). For options granted prior to January 1, 2003, the Company continues to disclose the pro-forma earnings impact of related stock based compensation expense (see note 9).

(c)Full cost accounting - ceiling test:

For the year ended December 31, 2003, the Company adopted the recommendations of the new Canadian accounting guideline on the full cost method of oil and gas accounting. This guideline modifies the existing ceiling test calculation. Under the new guideline, oil and gas assets are evaluated in each reporting period to determine that the costs are recoverable and do not exceed the fair value of the properties. The costs are assessed to be recoverable if the sum of the undiscounted cash flows expected from the production of proved reserves and the lower of cost and market of unproved properties exceed the carrying value of the oil and gas assets. If the carrying value of the oil and gas assets is not assessed to be recoverable, an impairment loss is recognized to the extent that the carrying value exceeds the sum of the discounted cash flows expected from the production proved and probable reserves and the lower of cost and market of unproved properties. The cash flows are estimated using future product process and costs and are discounted using the market risk-free rate.

Prior to January 1, 2003, the ceiling test used an undiscounted estimate of future net revenues from the production of proved reserves, using period end prices and costs, plus the lower of costs or market of unproved properties less estimated future costs for administration, financing, site restoration and taxes.

6

4.Corporate acquisition:

Effective July 31, 2003 the Company acquired all of the issued and outstanding shares of a private company involved in the exploration, development and production of crude oil and natural gas in East Central Alberta. The Company has accounted for this transaction as an asset purchase versus a business combination since the private company did not constitute a business. The private company was primarily represented by only one identifiable producing property and no employees were retained.

The purchase was accounted for based on the fair value of assets acquired:

Consideration:
Cash and transaction costs	$	1,584,433
Non-cash stock-based compensation fees	52,836
	1,637,269
Issue of 2,718,890 common shares of E3 Energy Inc.	2,582,946
	$	4,220,215
Net assets acquired:
Property, plant and equipment	$	7,881,729
Future site restoration costs	(31,200		)
	7,850,529
Non-cash working capital surplus	496,660
Current bank indebtedness assumed	(426,974		)
Operating demand loan	(3,700,000		)
	$	4,220,215

5.Property, plant and equipment:

	2004			2003
				(restated)
Petroleum and natural gas interests	$	33,164,026		$	19,611,758
Accumulated depletion	(4,965,613		)	(1,702,164		)
	28,198,413			17,909,594
Production equipment and processing facilities	7,594,933			4,892,235
Office equipment	179,177			139,687
	7,774,110			5,031,922
Accumulated depreciation	(1,155,602		)	(455,226		)
	6,618,508			4,576,696
Property, plant and equipment	$	34,816,921		$	22,486,290

7

During 2004, the Company capitalized, as part of property, plant and equipment, certain overhead expenses of $779 thousand (2003 - $388 thousand) directly related to exploration and development activities.

At December 31, 2004, property, plant and equipment included $1.7 million (2003 - $1.2 million) relating to unproved properties, which have been excluded from the depletion calculation. Future development costs related to proved non-producing and proved undeveloped reserves of $2.1 million ($223 thousand) are included in the depletion calculation.

At December 31, 2004, the future commodity prices used in the ceiling test were based on commodity price forecasts of the Company’s independent reserve engineers adjusted for transportation and quality differentials specific to the Company’s reserves. The following table summarizes the future benchmark prices used in the ceiling test:

	WTI Oil ($US/bbl)			Edmonton Light Crude Oil ($Cdn/bbl)			AECO Gas ($Cdn/Mmbtu)			Foreign Exchange ($US/Cdn)
2005	$	40.87		$	50.89		$	7.00		$	0.78
2006	37.20			46.16			6.44			0.78
2007	34.51			42.69			6.11			0.78
2008	31.84			39.25			5.81			0.78
2009	30.16			37.08			5.52			0.78
Annual escalation thereafter	1.5		%	1.5		%	1.8		%

6.Credit facilities:

As at December 31, 2004, the Company has bank credit facilities of $15 million, comprised of a $13.5 million revolving operating demand facility and a $1.5 million acquisition and development facility with a Canadian chartered bank. Amounts drawn on the revolving operating demand facility bear interest at the lenders prime lending rate plus 0.5 percent. At December 31, 2004, the Company had $7.9 million bank debt outstanding.

The bank credit facility contains restrictive covenants requiring the maintenance of certain financial ratios, a limitation on the distribution of capital, payment of dividends, and incurrence of additional debt. At December 31, 2004 the Company was in compliance with these covenants.

The credit facilities are secured by a fixed and floating debenture in the amount of $35 million covering all of the Company assets.

8

7.Asset Retirement obligations:

The Company adopted the new standard for the recognition of obligations associated with the retirement of long-lived assets. The change was effective January 1, 2004 and the revision was applied retroactively. The impact was as follows:

Consolidated Balance Sheet - As at December 31, 2003

	As reported		Change			As restated
Assets:
Net property, plant and equipment	$	21,168,955	$	1,317,335		$	22,486,290
Liabilities and shareholders equity:
Asset retirement obligation	—		1,523,948			1,523,948
Future site restoration	197,931		(197,931		)	—
Retained earnings	3,303,295		(8,682		)	3,294,613

Consolidated Statements of Earnings - Year ended December 31, 2003

	As reported		Change			As restated
Depletion, depreciation and amortization	$	1,819,633	$	113,929		$	1,933,562
Site restoration	141,577		(141,577		)	—
Accretion	—		68,449			68,449
Net earnings	3,552,900		(40,801		)	3,512,099
Net earnings per share, basic	$	0.17	$	(0.01	)	$	0.16
Net earnings per share, diluted	$	0.16	$	(0.00	)	$	0.16

The Company estimates the total inflated and undiscounted amount of cash flows required to settle its asset retirement obligations is approximately $4,500,000, the majority of which will be incurred during 2013 and 2034. A credit-adjusted risk-free rate of 6% was used to calculate the fair value of the asset retirement obligation.

A reconciliation of the asset retirement obligations is provided below:

	2004		2003
Asset retirement obligations:
Balance, beginning of year	$	1,523,948	$	380,024
Liabilities incurred in year	212,524		1,075,475
Accretion expense	104,268		68,449
Balance, end of year	$	1,840,740	$	1,523,948

9

8.Share capital:

(a)Authorized:

Unlimited number of common shares

Unlimited number of cumulative redeemable convertible non-voting Class A preferred shares

Unlimited number of non-cumulative redeemable convertible non-voting Class B preferred shares

Unlimited number of preferred shares issuable in series

(b)Issued and outstanding:

	Number of shares	Amount
Balance, January 1, 2003	18,399,359	$	5,696,103
Tax effect of flow-through shares	—	(1,986,617		)
Revision of shares issued on Reorganization	423	—
Issued on flow-through share private placement	3,809,524	4,000,000
Issue costs, net of tax of $138,077	—	(169,405		)
Acquisition of private company (note 4)	2,718,890	2,582,946
Exercise of stock options	4,000	2,000
Balance, December 31, 2003	24,932,196	10,125,027
Issued for cash	5,000,000	7,500,000
Issue costs, net of tax of $194,796	—	(325,499		)
Tax effect of flow-through shares	—	(1,616,027		)
Exercise of stock options	3,000	1,500
Balance, December 31, 2004	29,935,196	$	15,685,001

(c)Flow-through shares:

On June 25, 2003, the Company issued 3,809,524 flow-through common shares on a bought deal” basis at a price of $1.05 per common share for gross proceeds of $4,000,000. Under the terms of the flow-through share agreement, the Company was committed to spend 100% of the gross proceeds on qualifying crude oil and natural gas expenditures prior to December 31, 2004. As at December 31, 2004, the Company had fully incurred and discharged this expenditures commitment.

10

9.Stock based compensation:

(a)Outstanding stock options:

The Company has a stock option plan for the benefit of its directors, officers, employees and certain consultants. The Company has granted options to purchase common shares, whereby each option permits the holder to purchase one common share of the Company at the stated exercise price. The options vest over a two to three year term and are exercisable on a cumulative basis over ten years. At December 31, 2004, 2,471,500 options with a weighted average exercise price of $0.76 were outstanding and exercisable at various dates to March 18, 2014. The exercise price of each option equals the market price of the Company’s common shares on the date of the grant.

The following table summarizes the information about the share options as at December 31,:

	2004				2003
	Share options		Weighted average exercise price		Share options		Weighted average exercise price
Outstanding at beginning of year	2,414,500		$	0.74	1,395,000		$	0.50
Granted	60,000		1.61		1,023,500		1.06
Exercised	(3,000	)	0.50		(4,000	)	0.50
Outstanding at end of year	2,471,500		$	0.76	2,414,500		$	0.74
Options exercisable at year end	1,800,833		$	0.62	1,001,000		$	0.53

(b)Exercise price range:

		Outstanding options			Exercisable options
	Number of options	Weighted average price		Weighted average remaining life	Number of options	Weighted average price
$0.50 - 1.00	1,590,600	$	0.52	8.00 years	1,480,500	$	0.51
$1.01 - 1.50	823,500	$	1.16	8.90 years	320,333	$	1.15
$1.51 - 2.00	57,500	$	1.62	9.30 years	—	$	—
Total	2,471,500	$	0.76	8.30 years	1,800,833	$	0.62

11

(c)Proforma net income - fair value based method of stock option accounting:

The following table discloses pro forma net income and earnings per common share had the Company applied the fair value method to account for all stock options outstanding that were granted up to December 31, 2002. Stock options granted after that date have been expensed as general and administrative costs.

	2004		2003
Fair value of stock options granted	$	217,962	$	217,962
Earnings:
As reported (2003 restated)	2,868,560		3,512,099
Pro forma	2,650,598		3,294,137
Earnings per common share:
Basic, as reported (2003 restated)	0.10		0.16
Pro forma	0.09		0.15
Diluted, as reported (2003 restated)	0.09		0.16
Pro forma	0.09		0.15

(d)Estimated fair value of stock options:

The Company determined the fair value of stock options issued using the modified Black-Scholes option pricing model under the following assumptions:

	2004	2003
Weighted-average fair value ($/option)	1.39	0.69
Risk-free interest rate (%)	4.20	4.85
Estimated hold period prior to exercise (years)	10	10
Volatility in the price of the Company’s shares (%)	86.29	110.62

10.Per share amounts:

In the calculation of diluted per share amounts, options under the stock option plan are assumed to have been converted or exercised on the later of the beginning of the year and the date granted. The treasury stock method is used to determine the dilutive effect of stock options. The treasury stock method assumes that proceeds received from the exercise of in-the-money stock options are used to repurchase common shares at the average market rate.

	2004	2003
Weighted average shares outstanding:
Basic	29,387,215	21,530,222
Shares issued pursuant to options	1,137,577	676,328
Diluted	30,524,792	22,206,550

12

11.Contributed surplus:

	2004		2003
Balance, beginning of year	$	137,420	$	—
Stock based compensation	356,580		137,420
Stock based compensation on options exercised	—		—
Balance, end of year	$	494,000	$	137,420

12.Income taxes:

(a)Reconciliation of effective tax rate to the Canadian federal tax rate:

The provision for income taxes reflects an effective tax rate that differs from the results which would be obtained by applying the expected statutory income tax rate to earnings before taxes. The difference results from the following:

	2004			2003
				(restated)
Earnings before income taxes	$	3,471,054		$	1,125,231
Combined federal and provincial statutory tax rate	38.62		%	40.62		%
Expected income taxes	1,340,521			457,069
Add (deduct) the tax effect of:
Non-deductible provincial Crown royalties	445,176			195,446
Federal resources allowance	(596,839		)	(285,554		)
Stock-based compensation	137,711			55,820
Change in enacted tax rates and revisions to tax pools	(299,325		)	377,796
Change in valuation allowance	(439,477		)	(3,233,135		)
Other	2,684			2,113
Future income taxes (reduction)	590,451			(2,430,445		)
Current and capital tax	12,043			43,577
	$	602,494		$	(2,386,868	)

13

(b)Future income taxes:

	2004			2003
Future tax assets:
Non-capital losses carried forward	$	—		$	(63,012	)
Property, plant and equipment	1,624,481			(769,414		)
Share issue costs and other	(400,264		)	(394,516		)
	1,224,217			(1,226,942		)
Add valuation allowance	98,497			537,973
Net future tax (asset) liability	$	1,322,714		$	(688,969	)

13.Supplemental cash flow information:

(a)Increase (decrease) in non-cash working capital items:

	2004			2003
Change in non-cash working capital:
Accounts receivable and other current assets	$	500,624		$	952,662
Accounts payable and accrued liabilities	(1,035,675		)	773,440
	$	(535,051	)	$	1,726,102
Change in non-cash working capital related to:
Operating activities	$	220,720		$	336,805
Financing activities	—			(13,795		)
Investing activities	(755,771		)	1,403,092
	$	(535,051	)	$	1,726,102

(b)Other cash flow information:

	2004		2003
Interest paid	$	246,458	$	130,212
Income taxes paid	48,867		6,753

14

14.Financial instruments and Risk Management:

(a)Commodity risk:

From time to time, the Company may employ derivative financial instruments and physical arrangements, primarily commodity price hedges, to manage fluctuations in petroleum and natural gas market prices. The Company may use physical fixed price arrangements, future contracts, swaps, collars and put options with respect to a portion of its petroleum and natural gas production in order to achieve a more predictable cash flow. The Company does not utilize derivative financial statements for speculative purposes. Derivative financial instrument contracts accounted for as hedges are not recognized in the Company’s Consolidated Balance Sheet. Gains and losses related to derivative financial instruments designated as commodity price hedges are deferred and recognized in product revenues upon sale of the related hedged production.

The Company enters into hedge transactions on crude oil and natural gas. The agreements entered into are forward transactions providing the Company with a range of fixed prices on the commodities sold. Oil and gas revenues for the year ended December 31, 2004 include losses of $1.6 million (2003 - $416 thousands) on these transactions.

The following table outlines the financial agreements in place at December 31, 2004:

Product	Physical /Financial	Term	Daily notional volume	Price received
Crude oil:
Swap	Financial	Jan 05 - Dec 06	750 bblsl	C$57.80 per bbl
Power (electricity):
Swap	Financial	Jan 04 - Dec 05	24 MW	C$47.50 per MWh

(b)Credit risk:

A substantial portion of the Company’s accounts receivable are with customers in the petroleum and natural gas industry and are subject to normal industry credit risks which may expose the Company to certain losses in the event that counterparties or customers default on payment or contract settlement. As such, the Company’s customers are subject to an internal credit review to minimize risk of non-payment. The carrying value of accounts receivable reflects management’s assessment of the credit risk associated with these customers.

15

(c)Interest rate risk:

Financial instruments, which subject the Company to interest rate risk are limited to bank indebtedness. The Company’s current credit facility agreement calculates interest based on the bank’s prime lending rate plus 0.5 percent per annum.

(d)Fair value of financial assets and liabilities

The fair value of financial instruments is determined by reference to various market data and other valuation techniques as appropriate. The Company’s financial instruments consists of cash and cash equivalents, accounts receivable and accounts payable. The fair value of financial instruments is not estimated by management to be materially different from the carrying values since these deemed financial instruments are near maturity.

15.Commitments:

The Company has entered into an operating lease for office space. Future minimum lease payments under this agreement are as follows:

2005	$	121
2006	123
2007	123
2008	82

16.Subsequent event:

On January 7, 2005 the Company closed a previously announced Plan of Arrangement (the “Arrangement”) between the Company and Star Point Energy Ltd. (“StarPoint”). The arrangement effected a business combination and a conversion into a royalty trust. The Arrangement resulted in the shareholders of both E3 and StarPoint receiving Trust units in a new crude oil and natural gas energy trust that owns substantially all of E3’s and StarPoint’s existing producing assets. In addition, the shareholders of both E3 and StarPoint received shares in a separate, publicly traded, growth-orientated oil and gas exploration company, which owns certain of StarPoint’s exploration assets and undeveloped land acreage.

16

SCHEDULE “B” - FINANCIAL STATEMENTS OF UPTON

B - 1

Consolidated Financial Statements of

UPTON RESOURCES INC.

Year ended December 31, 2003

AUDITORS’ REPORT TO THE DIRECTORS

We have audited the balance sheet of Upton Resources Inc. as at December 31, 2003 and the consolidated statements of operations and retained earnings and cash flows for the year then ended. These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audit.

We conducted our audit in accordance with Canadian generally accepted auditing standards. Those standards require that we plan and perform an audit to obtain reasonable assurance whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation.

In our opinion, these consolidated financial statements present fairly, in all material respects, the financial position of the Company as at December 31, 2003 and the results of its operations and its cash flows for the year then ended in accordance with Canadian generally accepted accounting principles.

The financial statements as at and for the year ended December 31, 2002 were audited by other auditors who expressed an opinion without reservation on these statements in their report dated February 21, 2003.

(signed) “KPMG LLP”

Chartered Accountants

Calgary, Canada

December 6, 2004

UPTON RESOURCES INC.

Consolidated Balance Sheet

December 31, 2003, with comparative figures for 2002

(Amounts in thousands of dollars)

	2003		2002
Assets
Current assets:
Accounts receivable	$	10,177	$	12,908
Property and equipment (notes 2, 3 and 12)	124,355		135,558
Future income taxes (note 6)	1,167		1,420
	$	135,699	$	149,886
Liabilities and Shareholders’ Equity
Current liabilities:
Accounts payable	$	13,738	$	15,617
Stock based compensation (note 5)	1,542		—
Bank debt (note 4)	36,034		50,104
	51,314		65,721
Abandonment and restoration provision (note 3)	6,085		4,790
Future income tax liability (note 6)	15,474		13,409
	72,873		83,920
Shareholders’ equity:
Capital stock (note 5)	24,640		23,277
Retained earnings	38,186		42,689
	62,826		65,966
Commitments (note 11)
Subsequent event (note 14)
	$	135,699	$	149,886

See accompanying notes to the consolidated financial statements

On behalf of the Board:
(signed) “Paul Colborne”	Director
Paul Colborne
(signed) “Brett Herman”	Director
Brett Herman

UPTON RESOURCES INC.

Consolidated Statement of Operations and Retained Earnings

Year ended December 31, 2003, with comparative figures for 2002

(Amounts in thousands of dollars except per share amounts)

	2003			2002
Revenues:
Oil and gas sales	$	72,174		$	69,187
Less:
Royalties and production taxes, net of Alberta Royalty Tax Credits	15,617			14,314
	56,557			54,314
Expenses:
Production and operating	10,581			9,489
General and administration	6,902			4,433
Interest on bank debt	2,145			1,852
Depletion and depreciation (note 3)	35,416			26,120
Abandonment and restoration provision	1,295			972
	56,339			42,866
Earnings before taxes	218			12,007
Taxes (note 6):
Capital taxes	2,304			2,212
Current taxes	352			—
Future taxes	2,065			3,147
	4,721			5,359
Net earnings (loss) for the year	(4,503		)	6,648
Retained earnings, beginning of year	42,689			36,250
Normal course issuer bid purchases and share cancellations (note 5)	—			(209		)
Retained earnings, end of year	$	38,186		$	42,689
Net earnings (loss) per share (note 9):
Basic	$	(0.22	)	$	0.34
Diluted	(0.22		)	0.33

See accompanying notes to the consolidated financial statements.

UPTON RESOURCES INC.

Consolidated Statements of Cash Flows

Year ended December 31, 2003, with comparative figures for 2002

(Amounts in thousands of dollars)

	2003			2002
Cash flows provided from (used in):
Operations:
Net earnings (loss) for the year	$	(4,503	)	$	6,648
Items not affecting cash:
Depletion and depreciation	35,416			26,120
Abandonment and restoration provision	1,295			972
Future income taxes	2,065			3,147
Shares issued for services performed	665			—
Stock-based compensation	1,542			—
	36,480			36,887
Net (increase) decrease in non-cash working capital balances (note 13)	3,002			(8,994		)
	39,482			27,893
Financing:
Increase (decrease) in bank debt	(14,070		)	22,341
Shares purchased	—			(297		)
Net issue of capital stock for cash	698			12,990
	(13,372		)	35,034
Investment:
Additions to property and equipment	(24,213		)	(69,260		)
Net (increase) decrease in non-cash working capital balances (note 13)	(2,150		)	6,321
	(26,363		)	(62,939		)
Foreign exchange (non-cash)	253			12
Cash, beginning and end of year	$	—		$	—

See accompanying notes to the consolidated financial statements.

UPTON RESOURCES INC.

Notes to Consolidated Financial Statements

Year ended December 31, 2003

(Tabular dollar amounts in thousands of dollars except per share amounts)

General:

Upton Resources Inc. (the “Company”) is incorporated under the laws of Saskatchewan and its principal activity is the exploration, development and production of oil and gas properties.

1.Significant accounting policies:

The consolidated financial statements of the Company have been prepared by management in accordance with Canadian generally accepted accounting principles. In the preparation of these financial statements, management has made estimates and assumptions that affect the recorded amounts of certain of the Company’s assets, liabilities, revenues and expenses. The most significant estimates related to the amounts recorded for the depletion and depreciation of property, plant and equipment and the provision for future site restoration costs as well as the cost recovery assessment for property and equipment. While it is the opinion of management that these consolidated financial statements have been properly prepared within reasonable limits of materiality and within the framework of the significant accounting policies summarized below, actual results differ from the estimates made.

(a)Consolidation:

These consolidated financial statements include the accounts of the Company and its subsidiaries, each of which are wholly-owned.

(b)Capitalized costs:

(i)Capitalized costs:

The Company follows the full cost method of accounting, whereby all costs related to the acquisition, exploration for and development of oil and gas reserves, whether productive or unproductive, are capitalized and accumulated in separate cost centres for Canada and the United States. Proceeds from the disposition of oil and gas properties reduce capitalized costs with no gain or loss recognized unless such disposition would significantly alter the depletion and depreciation rate.

(ii)Depletion and depreciation:

Depletion of exploration and development costs and depreciation of production equipment are provided on the unit-of-production method based upon estimated proven oil and as reserves after royalties in each area of interest. For purposes of this calculation, reserves and production of natural gas are converted to common units based on their approximate relative energy content. The cost of acquiring and evaluating unproven properties are initially excluded from the depletion calculation. These properties are assessed periodically for impairment. When proved reserves are assigned or the property is considered to be impaired, the cost of the property or the amount of the impairment is added to the costs subject to depletion.

(iii)Ceiling test:

Effective December 31, 2003 the Company adopted the Canadian standard relating to full cost accounting for oil and gas entities. Under the new standard, petroleum and natural gas properties and production equipment are evaluated in each reporting period to determine that the carrying amount in a cost center is recoverable and does not exceed the fair value of the properties in the cost center.

The carrying amounts are assessed to be recoverable when the sum of the undiscounted cash flows expected from the production of proved reserves, the lower of cost and market of unproved properties and the cost of major development projects exceeds the carrying amount of the cost center. When the carrying amount is not assessed to be recoverable, an impairment loss is recognized to the extent that the carrying amount of the cost center exceeds the sum of the discounted cash flows expected from the production of proved and probable reserves, the lower of cost and market of unproved properties and the cost of major development projects of the cost center. The cash flows are estimated using expected future product prices and costs and are discounted using a risk-free interest rate.

For the periods prior to December 31, 2003, the Company calculated a ceiling test whereby the carrying value of petroleum and natural gas properties and production equipment, net of recorded future income taxes and accumulated provision for future site restoration and abandonment costs, was compared annually and quarterly to an estimate of future net revenues from the production of proved reserves. Net revenues were estimated using period ending prices less estimated future general and administrative expenses, financing costs, income taxes and capital expenditures. Should this comparison have indicated an excess carrying value, the excess was charged against operations as additional depletion and depreciation.

(c)Abandonment and restoration provision:

The annual provision for future abandonment and site restoration costs is based on estimates made by management and is charged to income using the unit of production method where the ratio of current year production to proven reserves determines the proportion of site restoration costs to be expensed. The accumulated amount represents the aggregate of such annual provisions less the aggregate of actual site restoration expenses incurred and adjustments resulting from property dispositions.

(d)Joint ventures:

Substantially all exploration and production activities are conducted jointly with others. These financial statements reflect only the Company’s proportionate interest in such activities.

2

(e)Foreign currency translation:

The Company translates the foreign denominated monetary assets and liabilities of integrated foreign operations at the exchange rate prevailing at the year-end, non-monetary assets and liabilities are translated at historical rates of exchange, and revenues and expenses are translated at the monthly average rate of exchange. Exchange gains and losses arising on translation of the accounts are included in consolidated earnings.

(f)Hedging activities:

The Company enters into contracts to hedge crude oil prices on a portion of its crude oil production to protect its future earnings and cash flows from the potential adverse impact of low crude oil prices and not for speculative purposes. Gains or losses on these contracts are included in revenues at the time of sale of the related hedged production.

In addition, the Company enters into contracts to fix the U.S./Canadian dollar exchange rate as well as contracts to fix interest rates on banker’s acceptances entered into by the Company. Gains or losses on these contracts are included in revenues as the contracts expire.

(g)Future income taxes:

Income taxes are calculated using the liability method of accounting for income taxes. Under this method, future income tax liabilities and future income tax assets are recorded based on the differences between the carrying amount of assets and liabilities in the consolidated balance sheet and their tax basis income tax rates substantively enacted at the balance sheet date. The effect of change in rates on future income tax liabilities and assets is recognized in the period in which the change occurs. A valuation allowance is recorded against any future income tax assets if it is more likely than not that the asset will not be realized.

(h)Stock-based compensation plans:

Effective January 1, 2002, the Company prospectively adopted the new Canadian accounting standard relating to stock based compensation. Under this standard, the Company continues to follow the intrinsic method of accounting for stock options granted to employees whereby the proceeds received on the exercise of options are included in a share capital and no compensation expense is recognized. For stock-based compensation to non-employees, the Company will calculate a fair value using an opinion pricing model, and recorded the expense to earnings over the term of the options.

Prior to the adoption of this plan the Company did not recognize any expense related to its stock-based compensation for share options granted to employees or directors. The impact on pro-forma earnings and pro-forma earnings per share, using the fair value method was disclosed in notes to the financial statements. Any consideration paid by employees on exercise of stock options or purchase of stock is credited to share capital.

3

(i)Use of estimates:

The amounts recorded for depletion and deprecation of petroleum and natural gas properties and equipment and the provision for abandonment and restoration costs are based on estimates. The costs and other relevant assumptions. By their nature, these estimates are subject to measurement uncertainty and the effect on the financial statements of changes in such estimates in future periods, could be significant.

(j)Earnings per share:

Earnings per share is calculated using the weighted average number of common shares outstanding during the year. Diluted earnings per share is calculated under the treasury stock method (see note 9).

2.Change in accounting policy:

On December 31, 2003 the Company adopted the new Canadian standard relating to full cost accounting for oil and gas entities. The new standard amends the ceiling test calculation applied by the Company to its oil and gas assets. The adoption of this new standard resulted in an impairment of the U.S. cost center of totaling approximately $250,000. There was no impairment to the Canadian cost center as a result of applying this standard.

3.Property and equipment:

	2003			2002
Petroleum and natural gas properties	$	340,462		$	316,289
Other property and equipment	3,545			3,505
	344,007			319,794
Less accumulated depletion and depreciation	(219,652		)	(184,236		)
	$	124,355		$	135,558

4

Capitalized expenditures relating to unproven properties which includes land costs and related seismic costs excluded from the depletion base are as follows:

	2003		2002
Canada	$	3,396	$	4,364
United States	1,588		1,507
	$	4,984	$	5,871

During the year ended December 31, 2003 the Company capitalized general and administrative overhead costs of approximately $480,000 (2002 - $349,000) relating to exploration and development activity.

On December 31, 2003 the Company realized a ceiling test impairment of the U.S. cost center totaling approximately $250,000. There was no impairment to the Canadian cost center as a result of this test. The crude oil and natural gas prices used in the ceiling tests were obtained from third parties and represent management’s best estimate of the future pricing environment for the Company as at December 31, 2003.

The following table summarizes the benchmark prices used in the ceiling test calculations.

Year	WTI Oil	Foreign Exchange Rate	Edmonton Light Crude Oil	AECO Gas
	($U.S./bbl)	($Cdn/bbl)
2004	29.63	0.75	37.99	6.04
2005	26.80	0.75	34.24	5.36
2006	25.76	0.75	32.87	4.80
2007	26.14	0.75	33.37	4.91
2008	26.53	0.75	33.87	4.98
2009	26.93	0.75	34.38	5.05
Escalate thereafter	1.5% per year		1.5% per year	1.5% per year

At December 31, 2002, the Company calculated its year end ceiling tests using the December monthly corporate average wellhead price of $40.08 per barrel and sales gas price of $5.16 per thousand cubic feet. No ceiling test write-down was required as a result of this test at December 31, 2002.

5

At December 31, 2003, the estimated total future site restoration costs to be amortized over the remaining proved reserves totaled approximately $11,855,000 (2002 - $10,532,000). A liability of $6,085,000 (2002 - $4,790,000) has been recognized to date for these future site restoration costs.

Total depletable assets have been reduced by the estimated salvage value of $12,714,000 (2002 - $11,533,000) and have been increased for future development costs of $7,165,000.

4.Bank debt:

	2003		2002
Credit facility	$	36,034	$	50,104

The Company had a $50,000,000 (2002 - $55,000,000) revolving demand credit facility with a banking syndicate. As at December 31, 2003 the Company had drawn $36,034,000 (2002 - $50,104,000) from the credit facility consisting of a $6,034,000 demand loan and $30,000,000 in bankers’ acceptances. The demand loan interest was paid monthly in arrears at the bank’s pricing grid which was dependent on the Company’s ratio of total debt to the most recent quarterly annualized cash flow. The bankers’ acceptance interest was paid in advance and bears interest at the bank’s prime acceptance fee rate with a stamp fee which was also subject to the bank’s pricing grid. At December 31, 2003, the demand loan carried an annual rate of the bank’s prime rate plus 0.375 percent and the banker’s acceptances carried a stamp fee of 1.375 percent.

The credit facility was reviewed annually by the bank and provided certain covenants are met, no principal repayments will be required in the next twelve months. As at December 31, 2003 the Company was in compliance with its debt covenants.

Security for the loan facility included a $150,000,000 fixed and floating charge demand debenture over the Company’s oil and gas properties and a general assignment of book debts of the company.

6

5.Capital stock:

(a)Authorized:

Unlimited number of common shares

(b)Issued and outstanding:

	Number of shares		Amount
Balance, December 31, 2001	17,162,444		$	10,364
Share issued (note 12)	3,499,970		12,880
Share issue costs	—		(24		)
Tax benefit on issue costs	—		11
Options exercised	55,500		134
Shares purchased and cancelled under normal course issuer bid	(86,000	)	(88		)
Balance, December 31, 2002	20,631,914		23,277
Shares issued for services performed	156,919		665
Option exercised	307,200		698
Balance, December 31, 2003	21,096,033		$	24,640

(c)Stock-based compensation:

In November 2003, the Company changed its stock option plan to allow for options to be settled for their intrinsic value in cash or common shares. The plan allows for the option holder to receive in cash or shares the difference between the five prior days average trading price less the options exercise price. As a result of the amendment to the plan, the Company now recognizes the potential liability that could arise if all option holders elected the cash settlement alternative at the period end share price. Provision is made for all vested options. As at December 31, 2003 a liability of $1,542,000 was recognized for this expense.

7

At December 31, 2002 the Company had adopted the new CICA 3870 standard for reporting stock-based compensation for stock options granted after January 1, 2002. As required by Canadian generally accepted accounting principles, the impact on net earnings and net earnings per share of such compensation costs, using the fair value method, is disclosed. The total fair value of the Company’s options on June 22, 2004 was $498,416.

Net earnings (loss):
Reported	$	6,648
Pro-forma	6,384
Net earnings (loss) per common share:
Reported	$	0.34
Pro-forma	0.33

The fair value for options granted to employees and directors was estimated at the date of grant using a Black-Scholes Option Pricing Model with the following assumptions for 2002:

Volatility factor of expected market price	$	0.45
Weighted average risk free rate	4.29		%
Weighted average expected life in years	3.75
Weighted average expected annual dividends per share	—

A summary of the status of the Company’s stock option plan as of December 31, 2003 and 2002, and changes during the years then ended is presented below:

	2003				2002
	Shares		Weighted- average exercise price		Shares		Weighted- average exercise price
	(000’s)				(000’s)
Outstanding, beginning of year	1,739		$	3.28	1,486		$	3.15
Granted	—		—		396		3.47
Exercised	(307	)	2.27		(55	)	2.41
Cancelled	(370	)	2.86		(74	)	2.15
Forfeited (cancelled)	(15	)	3.61		(14	)	3.42
Outstanding, end of year	1,047		$	3.72	1,739		$	3.28
Options exercisable, end of year	1,047				1,355

8

The following table summarized information about fixed stock options outstanding at December 31, 2003.

		Options outstanding				Options exercisable
Range of exercise prices	Number outstanding at December 31, 2002	Weighted- average remaining contractual life (years)	Weighted- average exercise price			Number exercisable at December 31, 2002	Weighted- average exercise price
$ 1.00 to $1.99	—	0.0	$	0.00		—	$	0.00
$ 2.00 to $2.99	304,000	0.5	$	2.54		304,000	$	2.54
$ 3.00 to $4.99	655,200	2.76	$	3.64		655,200	$	3.64
$ 5.00 to $8.99	25,000	0.50	$	5.05		25,000	$	5.05
$ 9.00 to $9.99	63,000	1.04	$		9.75	63,000	$		9.75
	1,047,200	1.94	$	3.72		1,047,200	$	3.72

6.Income taxes:

The provision for future income taxes reflects an effective tax rate that differs from the expected Canadian income tax rate. The differences are as follows:

	2003			2002
Expected combined Canadian federal and provincial income tax rate	43.48		%	44.59		%
Expected provision for (recovery of) income taxes	$	95		$	5,354
Increase (decrease) resulting from:
Royalties and production taxes paid to the Crown	2,912			2,824
Resource allowance on Canadian resource income	(3,849		)	(5,051		)
Tax rate change	(537		)	—
Previously unrecognized U.S. losses	2,439			(91		)
Provision to actual adjustment	543			—
Stock based compensation	959			—
Capital taxes	2,304			2,212
Other permanent differences	(145		)	111
	$	4,721		$	5,359

9

The future income tax liability or benefit is composed of temporary differences and future income tax reductions.  The following table shows the tax-affected amounts of those items with a tax value in excess of their net book value:

	2003				2002
Share issue costs	$	38			$	63
Tax value of property and equipment in excess of net book value	(3,422			)	(3,381			)
Future site restoration deductions	2,281				1,602
Partnership deferred income	(13,204			)	(10,280			)
Other future deductions	—				7
Future income tax benefit (liability)	$		(14,307	)	$		(11,989	)
Future income tax asset (liability) is comprised of:
	2003				2002
Upton Resources U.S.A., Inc.	$	1,167			$	1,420
Upton Resources Inc.	(15,474			)	(13,409			)
	$		(14,307	)	$		(11,989	)

At December 31, the Company had deductions totaling approximately $91,474,000 (December 31, 2002 - $95,977,000) and which were available to claim against future taxable income:

In addition, the Company has tax deductions totaling approximately $30,612,000 which may be claimed against future income in the United States. At December 31, 2003, the tax value of the U.S. assets exceeded the net book value by $5,607,000. Of this amount, $1,167,000 is recorded as a future tax benefit. Based on management’s best estimate, this is the amount estimated as more likely than not to be realized in the near future. A future tax asset not been recognized for the remaining $4,440,000.

10

7.Related party transactions:

At December 31, 2003 and 2002 the Company has the following transactions and balances with companies controlled by certain directors and officers of the Company:

	2003		2002
Accounts receivable	$	1	$	77
Accounts payable	22		—

The Company operates oil wells for companies in which certain directors have ownership interest. These transactions were made under normal business terms and conditions and at the same rates as with non-related parties.

Included in accounts receivable is a non-interest bearing loan which had been offered to employees and officers in 1998 for the purpose of acquiring shares in the Company. At December 31, 2003, the Company had non-interest bearing loans due from its officers of $74,100 (2002 - $103,601) and employees of $12,900 (200 - $27,281). The loan was used to purchase shares and is secured by an assignment of these shares that are held in escrow until the loans are repaid. Loans are secured by the outstanding shares held in escrow. The value of the shares in escrow at December 31, 2003 is $82,695.

8.Segmented information by geographic segment:

	Canada		United States			Consolidated
Year ended, December 31, 2003
Revenues	$	65,197	$	6,977		$	72,174
Earnings before taxes	5,828		(5,610		)	218
Net earnings (loss)	1,107		(5,610		)	(4,503		)
Net property and equipment expenditures	22,788		1,425			24,213
Identifiable assets	112,319		23,380			135,699
Year ended, December 31, 2002
Revenues	61,155		8,032			69,187
Earnings before taxes	11,802		205			12,007
Net earnings (loss)	6,443		205			6,648
Net property and equipment expenditures	71,307		9,733			81,040
Identifiable assets	118,485		31,401			149,886

11

9.Per share information:

	2003			2002
Earnings per common share:
Basic	$	(0.22	)	$	0.34
Diluted	$	(0.22	)	$	0.33
Weighted average number of basic common shares outstanding	20,726,334			19,524,412
Weighted average number of diluted common shares outstanding	20,882,504			19,916,356

In computing the diluted net income per common share, under the treasury stock method, the following number of shares were added to the weighted average number of common shares for the dilutive effect of employee stock options. For the year-ended December 31, 2003, 156,171 common shares were added (2002 — 391,943).

10. Financial instruments and hedging activity:

(a)Fair values:

The Company’s financial instruments recognized in the financial statements consist of accounts receivable, account payable and bank debt. The fair value of the accounts receivable and payable approximate their carrying amount due to the short-term maturity of these instruments, while the fair value of the bank debt credit facility approximates its carrying amount as the interest rate is a floating market rate.

(b)Hedging activity:

The Company utilizes certain derivative financial instruments including crude oil swap contracts, crude oil option contracts, foreign exchange swap and foreign exchange interest rate option contracts. The Company enters into these contracts to manage its cash flow exposure to the volatility of crude oil prices foreign exchange rates and interest rates. Financial derivative contracts outstanding at December 31, 2003 were as follows:

Term	Quantity/Day	Price/Barrel
Crude oil options (swap)
January 1, 2004 to December 31, 2004	2,000 barrels	Fixed U.S. $29.00 WTI
January 1, 2004 to December 31, 2004	50 barrels	Fixed U.S. $30.02 WTI

The fair value of these collars based on quotes provided by brokers would result in a loss of U.S. $889,698 (CDN $1,153,493) if terminated at December 31, 2003.

12

Financial derivative contracts outstanding at December 31, 2002 were as follows:

Term	Quantity/Day		Price/Barrel
Crude oil options (collars)
May 1, 2002 to April 30, 2003	500 barrels	Call	U.S. $28.10 WTI
		Put	U.S. $24.00 WTI
June 1, 2002 to May 31, 2003	500 barrels	Call	U.S. $26.05 WTI
		Put	U.S. $22.00 WTI
September 1, 2002 to August 31, 2003	500 barrels	Call	U.S. $28,10. WTI
		Put	U.S. $24.00 WTI
January 1, 2003 to December 31, 2003	500 barrels	Call	U.S. $27.10 WTI
		Put	U.S. $23.00. WTI

Term	Quantity/Day		Price/Barrel
Crude oil options (swaps)
January 1, 2003 to December 31, 2003	500 barrels	Fixed	U.S. $26.75 WTI

The fair value of these collars based on quotes provided by brokers would result in a loss of U.S. $804,902 (CDN $1,269,813) if terminated at December 31, 2002.

Financial derivative contracts entered into subsequent to year-end are as follows:

Term	Quantity/Day		Price/Barrel
Crude oil options (swaps)
February 1, 2003 to December 31, 2004	500 barrels	Call	U.S. $30.00 WTI
		Put	U.S. $25.00 WTI
May 1, 2003 to December 31, 2003	500 barrels	Call	U.S. $28.00 WTI
		Put	U.S. $25.00 WTI
Crude oil options (swaps)
June 1, 2003 to December 31, 2003	500 barrels	Fixed	U.S. $28.00 WTI

13

Foreign exchange swap

On September 6, 2002, Upton entered into an average rate forward foreign exchange contract. Based on monthly average rates, Upton will trade U.S. $1,000,000 per month at a strike price of U.S. $1.58 for the months of January through December 2003.

The fair value of this contract, based on quotes provided by brokers, would result in a gain of U.S. a $62,317 (Cdn $98,311) if terminated on December 31, 2002.

Interest rate hedge:

In the third quarter, Upton entered into Forward Rate Agreements and hedged banker’s acceptance rates on a portion of its debt for the period November 18, 2002 through October 8, 2003. Interest rate hedges outstanding as of December 31, 2002 were as follows:

Term	Amount		Interest rate
November 18, 2002 to February 18, 2003	$	6,000,000	3.05
January 2, 2003 to April 20, 2003	6,000,000		3.07
January 9, 2003 to April 10, 2003	6,000,000		3.06
February 18, 2003 to May 20, 2003	6,000,000		2.86
April 10, 2003 to July 10, 2003	6,000,000		3.41
April 10, 2003 to July 10, 2003	6,000,000		3.19
May 20, 2003 to August 19, 2003	6,000,000		3.20
July 10, 2003 to October 9, 2003	6,000,000		3.27
July 10, 2003 to October 9, 2003	6,000,000		3.24
July 20, 2003 to October 9, 203	6,000,000		3.10

The fair value of these contracts based on quotes provide by brokers, would result in a loss of $48,017, if terminated on December 31, 2002.

Interest rate hedges entered to subsequent to December 31, 2002 are as follows:

Term	Amount		Interest rate
August 19, 2003 to November 18, 2003	$	7,000,000	3.04

14

11. Commitments:

At December 31, 2003, the Company had non-cancellable long-term commitments related to its head office lease with the following future payments:

2004	$	251,658
2005	265,153
2006	265,683
2007	265,638
Thereafter	199,229

12. Acquisitions:

On April 25, 2002, pursuant to a Plan of Arrangement, the Company acquired all the outstanding shares of Empire Energy Inc. (“Empire”). The previous shareholders of Empire received, for each of their Empire shares, $0.5345 in cash and 0.134 of a common share of the Company. The acquisition was accounted for using the purchase method and the purchase price was allocated as follows:

Purchase price:
Net working capital deficiency assumed	$	373
Property and equipment	41,976
Future income tax liability	(11,709			)
Site abandonment and restoration liability assumed	(64			)
Long-term debt	(3,552			)
	$		27,024

Consideration
Cash	$	13,960
3,499,970 common shares issued (note 5)	12,880
Cost of acquisition	184
	$		27,024

15

13. Supplemental cash flow disclosures:

(a)Change in non-cash working capital:

	2003				2002
Accounts receivable	$	2,731			$	(4,653		)
Accounts payable	(1,879			)	1,980
	852				(2,673			)
Less: changes in non-cash working capital related to investing	2,150				6,321
	$		3,002		$		(8,994	)

(b)Cash payments made relating to the following:

	2003			2002
Taxes paid	$	2,656		$	1,806
Interest paid	$		2,145	$		1,663

14. Subsequent event:

On January 27, 2004, StarPoint Energy Ltd. acquired all of the outstanding shares of the Company. The acquisition was accounted for using the purchase method of accounting and the purchase price was allocated as follows:

Consideration:
Issue of 23,700,625 StarPoint Energy Ltd. common shares	$	75,158
Transaction costs	125
Total consideration	$		75,283

16

Purchase price of the Company at fair value:
Property and equipment	$	97,846
Goodwill	41,508
Working capital	(6,834			)
Bank debt	(36,660			)
Asset retirement obligation	(9,205			)
Future income taxes	(11,372			)
	$		75,283

The total of 23,700,625 common shares was issued at an ascribed value of $3.17 per share. The ascribed per share value was based upon an adjusted closing price on StarPoint Energy Ltd.’s common shares on the Toronto Stock Exchange, on the date immediately prior to the date that the Arrangement Agreement with the Company was entered into.

17

SCHEDULE “C” - FINANCIAL STATEMENTS OF SELKIRK

C - 1

Selkirk Energy Group

Financial Statements

October 31, 2004

(unaudited)

Collins Barrow Calgary LLP

1400 First Alberta Place

777 - 8th Avenue S.W.

Calgary, Alberta, Canada

T2P 3R5

T. 403.298.1500

F. 403.298.5814

email: calgary@collinsbarrow.com

Auditors’ Report

To the Directors of

Selkirk Energy Canada Ltd.

977529 Alberta Ltd.

3072202 Nova Scotia Company

Five Spot Energy Ltd.

We have audited the combined balance sheet of Selkirk Energy Group as at January 31, 2004 and the combined statements of income and retained earnings and cash flows for the year then ended.  These combined financial statements are the responsibility of the management of Selkirk Energy Group.  Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with Canadian generally accepted auditing standards. Those standards require that we plan and perform an audit to obtain reasonable assurance whether the combined financial statements are free of material misstatement.  An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the combined financial statements.  An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall combined financial statement presentation.

In our opinion, these combined financial statements present fairly, in all material respects, the financial position of the Group as at January 31, 2004 and the results of its operations and its cash flows for the year then ended in accordance with Canadian generally accepted accounting principles.

(signed) “Collins Barrow Calgary LLP”

CHARTERED ACCOUNTANTS

Calgary, Alberta

November 12, 2004

Selkirk Energy Group

Combined Balance Sheets

	October 31,		January 31,
	2004		2004		2003
	(unaudited)		(audited)		(unaudited)
			(restated -		(restated -
			note 3)		note 3)
Assets
Current assets
Cash and cash equivalents	$	2,640,709	$	3,848,159	$	727,124
Accounts receivable	1,531,040		2,572,690		2,804,055
Crown deposits and other	312,630		277,216		195,640
ARTC receivable	1,353,191		784,391		191,802
Income taxes recoverable	16,183		—		—
	5,853,753		7,482,456		3,918,621
Property and equipment (note 4)	28,807,822		24,768,969		16,806,055
	$	34,661,575	$	32,251,425	$	20,724,676
Liabilities
Current liabilities
Accounts payable and accrued liabilities	$	2,630,891	$	5,852,425	$	13,310,328
Income taxes payable	—		11,538		3,433
Demand loan payable (note 5)	21,942		34,030		1,101,941
Due to shareholders (note 6)	519,989		465,157		1,945
	3,172,822		6,363,150		14,417,647
Asset retirement obligations (note 7)	518,013		509,824		343,568
Future income taxes	3,223,000		2,468,000		100,000
	6,913,835		9,340,974		14,861,215
Shareholders’ Equity
Share capital (note 8)	20,542,900		19,042,900		5,752,900
Retained earnings	7,204,840		3,867,551		110,561
	27,747,740		22,910,451		5,863,461
	$	34,661,575	$	32,251,425	$	20,724,676

Approved by,
(signed) “Janice Lambert”	, Director, Selkirk Energy Canada Ltd.
(signed) “Steve MacKay”	, Director, 977529 Alberta Ltd.

Selkirk Energy Group

Combined Statements of Income and Retained Earnings

	Nine Months Ended October 31,				Year Ended January 31,
	2004		2003		2004		2003
	(unaudited)		(unaudited)		(audited)		(unaudited)
			(restated -		(restated -		(restated -
			note 3)		note 3)		note 3)
Revenue
Petroleum and natural gas sales	$	12,606,439	$	11,631,754	$	15,410,229	$	3,517,120
Less: royalties	3,050,734		3,272,021		4,135,470		812,559
	9,555,705		8,359,733		11,274,759		2,704,561
Alberta Royalty Tax Credit	568,800		573,300		592,600		191,800
Interest	26,950		30,216		50,070		1,443
	10,151,455		8,963,249		11,917,429		2,897,804
Expenses
Operating costs	1,490,261		1,274,244		1,738,232		573,393
General and administrative	597,623		580,602		779,418		650,267
Depletion, depreciation and accretion	3,971,282		2,071,134		3,263,184		1,440,150
	6,059,166		3,925,980		5,780,834		2,663,810
Income before income taxes	4,092,289		5,037,269		6,136,595		233,994
Income taxes - current	—		11,588		11,605		3,433
- future	755,000		1,805,000		2,368,000		100,000
	755,000		1,816,588		2,379,605		103,433
Net income	3,337,289		3,220,681		3,756,990		130,561
Retained earnings, beginning of period	3,867,551		110,561		110,561		—
Dividends paid	—		—		—		20,000
Retained earnings, end of period	$	7,204,840	$	3,331,242	$	3,867,551	$	110,561

Selkirk Energy Group

Combined Statements of Cash Flows

	Nine Months Ended October 31,						Year Ended January 31,
	2004			2003			2004			2003
	(unaudited)			(unaudited)			(audited)			(unaudited)
				(restated -			(restated -			(restated -
				note 3)			note 3)			note 3)
Operating activities
Net income	$	3,337,289		$	3,220,681		$	3,756,990		$	130,561
Items not affecting cash Depletion, depreciation and accretion	3,971,282			2,071,134			3,263,184			1,440,150
Future income taxes	755,000			1,805,000			2,368,000			100,000
Funds from operations	8,063,571			7,096,815			9,388,174			1,670,711
Net change in non-cash working capital balances	(505,232		)	(614,773		)	(641,662		)	(251,887		)
	7,558,339			6,482,042			8,746,512			1,418,824
Financing activities
Proceeds on issuance of share capital	1,500,000			13,290,000			13,290,000			5,752,900
Dividends paid	—			—			—			(20,000		)
Due to shareholders	54,832			461,124			463,212			1,945
Demand loan payable increase (decrease)	(12,088		)	(1,068,026		)	(1,067,911		)	1,101,941
	1,542,744			12,683,098			12,685,301			6,836,786
Investing activities
Property and equipment expenditures	(8,001,946		)	(8,408,298		)	(11,059,842		)	(17,903,326		)
Net change in non-cash working capital balances	(2,306,587		)	(8,120,724		)	(7,250,936		)	10,374,840
	(10,308,533		)	(16,529,022		)	(18,310,778		)	(7,528,486		)
Net increase (decrease) in cash	(1,207,450		)	2,636,118			3,121,035			727,124
Cash and cash equivalents, beginning of period	3,848,159			727,124			727,124			—
Cash and cash equivalents, end of period	$	2,640,709		$	3,363,242		$	3,848,159		$	727,124
Supplemental cash flows information:
Interest paid	$	191		$	54,047		$	54,161		$	20,505

Selkirk Energy Group

Notes to Combined Financial Statements

October 31, 2004

(Information as at, and for the period ended October 31, 2004, October 31, 2003 and January 31, 2003 is unaudited)

1.Basis of presentation

These financial statements have been prepared on a combined basis, including the accounts of the Selkirk Energy Partnership and its four Partners (collectively, the “Selkirk Energy Group”).

The Partnership commenced business on February 1, 2002, and has a fiscal year ending January 31.  The accounts of the corporate Partners have been conformed to correspond to the Partnership fiscal year.  Substantially, all of the assets and liabilities of the Partners are held by the Partnership, with the exception of income taxes payable, future income taxes, Alberta Royalty Tax Credits receivable, the demand loan payable, and the amount due to shareholders.

The Partners and their respective ownership interests in the Partnership are set out below:

	Units of Partnership Owned
	October 31, 2004	January 31, 2004 and 2003
3072202 Nova Scotia Company	646,785	600,042
977529 Alberta Ltd.	646,785	600,042
Five Spot Energy Ltd.	646,785	600,042
Selkirk Energy Canada Ltd. (“SECL”)	17,673,828	16,396,531
	19,614,183	18,196,657

977529 Alberta Ltd., 3072202 Nova Scotia Company, and Five Spot Energy Ltd. each hold rights to acquire additional units in the Partnership to increase their interests to 25% in aggregate.  The additional units are issuable for aggregate proceeds of $5.1 million.

These combined financial statements do not necessarily reflect Selkirk Energy Group’s results of operations, financial position and cash flows in future periods, nor do they necessarily reflect the results of operations, financial position and cash flows that would have been realized had the Group been a single legal entity during the periods presented.

2.Summary of significant accounting policies

(a)Cash and cash equivalents

Cash and cash equivalents consists of cash and banker’s acceptances with initial maturities of less than 90 days.

(b)Joint ventures

Substantially all of the Group’s oil and gas business operations are conducted jointly with others, and accordingly these combined financial statements reflect only the Group’s proportionate interest in such activities.

(c)Petroleum and natural gas operations

The Group follows the full cost method of accounting for petroleum and natural gas operations and accordingly capitalizes all exploration and development costs.  These costs include land acquisition, geological and geophysical costs, drilling on producing and non-producing properties, wellhead and gathering equipment, other carrying charges on unproven properties and related overhead.

Capitalized costs are depleted and depreciated using the unit-of-production method based on estimated total proven petroleum and natural gas reserves.  For the purpose of this calculation, production and reserves of petroleum and natural gas are converted to equivalent units based on the relative energy content of six thousand cubic feet of natural gas to one barrel of oil.  Costs of acquiring and evaluating unproved properties are excluded from costs subject to depletion and depreciation until it is determined that proved reserves are attributable to the properties or impairment occurs.  Gains or losses on sales of properties are recognized only when crediting the proceeds to costs would result in a change of 20% or more in the depletion and depreciation rate.

Impairment is recognized if the carrying amount of oil and natural gas properties, less the cost of unproved properties not subject to depletion (the “adjusted carrying amount”) exceeds the estimated undiscounted future cash flows from the Group’s proved reserves.  The future cash flows are based on forecasted prices and costs estimated by independent engineers.  If recognized, the magnitude of the impairment is then measured by comparing the adjusted carrying amount to the estimated discounted future cash flows of the Group’s proved plus probable reserves, and discounted at the Group’s risk-free interest rate using forecasted prices and costs.  For purposes of the ceiling test, future cash flows are calculated exclusive of indirect costs such as financing charges, general and administrative expenses and income taxes.  Any impairment recognized is recorded as additional depletion and depreciation expense.

The Group records the estimated costs of retiring tangible long lived assets such as oil and gas wells and related equipment.  The asset retirement obligation is recognized in the period an original expenditure is made and when a reasonable estimate of the fair market value can be made.  The asset retirement cost, equal to the fair value of the retirement obligation, is capitalized as part of the cost of the related long-lived asset and allocated to expense on a basis consistent with depletion and depreciation.  The liability is increased each reporting period with the accretion being charged to income until the property is abandoned or sold.

The amounts recorded for depletion and depreciation of property and equipment and the provision for asset retirement obligations are based on estimates.  These calculations are based on independent engineering estimates of proved reserves, production rates, petroleum and natural gas prices, future costs and other relevant assumptions.  By their nature, these estimates are subject to measurement uncertainty and the effect on the financial statements from changes in such estimates in future years could be significant.

(d)Office assets

Furniture and office equipment are recorded at cost and depreciated on a declining balance basis at rates of 20-35% per year.

(e)Income taxes

Income taxes are accounted for using the liability method of income tax allocation. Under the liability method, income tax assets and liabilities are recorded to recognize future income tax inflows and outflows arising from the settlement or recovery of assets and liabilities at their carrying values.  Income tax assets are also recognized for the benefits from tax losses and deductions that cannot be identified with particular assets or liabilities, provided those benefits are more likely than not to be realized.  Future income tax assets and liabilities are determined based on the tax laws and rates that are anticipated to apply in the period of realization.

(f)Revenue recognition

Revenue from the sale of petroleum and natural gas is recognized based on volumes delivered to customers at contractual delivery points and rates.  The costs associated with the delivery, including operating and maintenance costs, transportation, and production-based royalty expenses are recognized in the same period in which the related revenue is earned and recorded.

3.Changes in accounting policies

(a)   Full Cost Accounting

On February 1, 2004, the Group adopted the Canadian Institute of Chartered Accountants (“CICA”) Accounting Guideline AcG-16, “Oil and Gas Accounting - Full Cost”.  The new guideline modifies the ceiling test calculation and outlines additional disclosure requirements.  Under the full cost method of accounting, a limit is placed on the carrying amount of oil and natural gas properties.  A “ceiling test” is performed to recognize and measure impairment, if any.

Prior to adopting the new policy, the Group computed the ceiling test based on a comparison of the net book value of petroleum and natural gas properties, net of recorded provision for related asset retirement obligations and future income taxes and the value of unproven properties at the lower of cost and net realizable value, to

the undiscounted future net revenue from the production of proven reserves, net of estimated future site restoration and abandonment costs, general and administrative costs and income taxes.

There is no impact on the Group’s reported financial results as a result of applying this new policy.

(b)Asset retirement obligations

On February 1, 2004, the Group adopted the CICA Handbook Section 3110, “Asset Retirement Obligations” retroactively with restatement of prior periods.

Prior to adopting the new standard, the Company accumulated the provision for future site restoration costs on the balance sheet, and an amount was charged to earnings, on a unit of production method based on proved reserves.  The accumulated liability on the balance sheet was reduced for actual expenditures incurred.

As a result of adopting this new standard, the accounts of the Partnership and the combined financial statements for prior periods have been increased (decreased) as follows:

	October 31, 2003		January 31,
			2004		2003
Property and equipment	$	361,903	$	391,546	$	322,668
Liabilities	367,437		387,424		305,868
Retained earnings	16,800		16,800		—
Depreciation, depletion and accretion	22,334		12,678		(16,800		)

4.Property and equipment

	October 31, 2004
	Cost		Accumulated Depletion and Depreciation		Net Book Value
Petroleum and natural gas properties	$	37,358,379	$	8,591,900	$	28,766,479
Office assets	88,463		47,120		41,343
	$	37,446,842	$	8,639,020	$	28,807,822

			January 31, 2004				January 31, 2003
	Cost		Accumulated Depletion and Depreciation		Net Book Value		Net Book Value
Petroleum and natural gas properties	$	29,368,346	$	4,648,300	$	24,720,046	$	16,743,797
Office assets	86,713		37,790		48,923		62,258
	$	29,455,059	$	4,686,090	$	24,768,969	$	16,806,055

As at October 31, 2004 and January 31, 2004, costs of undeveloped properties of $693,269 and $876,978, respectively (2003 - $870,318 and $458,980, respectively) have been excluded from the calculation of depletion, depreciation and amortization.

During the period ended October 31, 2004, the Group capitalized $97,424 (2003 - $93,800) of a total of $695,047 (2003 - $674,402) in general and administrative expenses. During the year ended January 31, 2004, the Group capitalized $124,880 (2003 $173,383) of a total of $904,298 (2003 - $823,650) in general and administrative expenses.

5.Demand loan payable

The demand loan is payable to the parent company of Selkirk Energy Canada Ltd. and bears interest at the U.S. short-term Applicable Federal Rate, compounded monthly.  The loan is unsecured, and is repayable on demand.

6.Due to shareholders

The amounts due to shareholders are non-interest bearing, unsecured and without stated terms of repayment.

7.Asset retirement obligations

The reconciliation of the beginning and ending aggregate carrying amount of the asset retirement obligations associated with the retirement of oil and natural gas properties is as follows:

	October 31, 2004			January 31,
				2004		2003
				(restated -		(restated -
				note 3)		note 3)
Balance, beginning of period	$	509,824		$	343,568	$	—
Liabilities incurred (reduced)	(10,163		)	149,078		343,568
Accretion expense	18,352			17,178		—
Balance, end of period	$	518,013		$	509,824	$	343,568

Total estimated future retirement costs of $1,098,876 and $1,106,269 for October 31, 2004 and January 31, 2004, respectively (2003 - $1,014,944 and $832,295, respectively), expected at the time of abandonment, have been discounted using a credit-adjusted risk-free rate of 5.00%.  Most of these obligations are not expected to be paid for several years and will be funded from general Group resources at the time of abandonment.

8.Share capital

(a)Authorized

Authorized share capital for each Partner is as follows:

3072202 Nova Scotia Company

100,000 common shares

100,000 preferred shares

977529 Alberta Ltd. and Five Spot Energy Ltd.

Unlimited number of voting common shares

Unlimited number of non-voting common shares

Unlimited number of preferred shares

Selkirk Energy Canada Ltd.

Unlimited number of common shares

(b)Issued

	October 31, 2004			January 31,
				2004		2003
		Stated		Stated		Stated
	Number	Value		Value		Value
3072202 Nova Scotia Company
Common voting shares	100	$	100	$	100	$	100
977529 Alberta Ltd.
Common voting shares	50	50		50		50
Common non-voting shares	50	50		50		50
Five Spot Energy Ltd.
Common voting shares	50	50		50		50
Common non-voting shares	50	50		50		50
Selkirk Energy Canada Ltd.
Common voting shares (January 31, 2004 - 1,000 shares, January 31, 2003 - 300 shares)	1,100	20,542,600		19,042,600		5,752,600
		$	19,042,900	$	19,042,900	$	5,752,900

9.Related party transactions

(a)During the year, 654835 Alberta Ltd., a company whose principal shareholder is related to 977529 Alberta Ltd., was paid $37,000 in consulting fees.

(b)During the period ended October 31, 2004 and year ended January 31, 2004, the Group paid interest of $191 and $54,161 respectively (2003 - $54,047 and $20,505, respectively) to the parent company of Selkirk Energy Canada Ltd.

These transactions are in the normal course of operations and are measured at the exchange amount which is the amount of consideration established and agreed to by the related parties.

10.Subsequent event

On November 8, 2004, the Partners and their shareholders entered into agreements to sell all of the outstanding shares of the Partners, and the underlying interests in the Partnership, to Starpoint Energy Ltd.   Subsequent to the issuance of additional shares by a Partner for $5.1 million cash, and the conversion of $520,000 of shareholder loans to contributed surplus, all of the shares of each Partner will be sold for proceeds of $60 million plus working capital.

11.Financial instruments

(a)Credit risk management

Accounts receivable includes amounts due for petroleum and natural gas sales and from joint venture partners.  Petroleum and natural gas sales are contracted primarily to BP Canada Energy Company, and joint venture receivables are due from established resource companies.  The credit risk associated with these items is consistent with the normal risk for such receivables in the industry.

(b)Fair values

The carrying value of the Group’s financial assets and liabilities approximated their fair value at October 31, 2004, due to the short-term nature of the assets and liabilities.

12.Commitment

The Group has office lease commitments expiring April 30, 2005 of approximately $45,700 per year plus operating costs.

SCHEDULE “D” - FINANCIAL STATEMENTS OF APF

D - 1

	PricewaterhouseCoopers LLP Chartered Accountants 111 5th Avenue SW, Suite 3100 Calgary, Alberta Canada T2P 5L3 Telephone +1 (403) 509 7500 Facsimile +1 (403) 781 1825

AUDITORS’ REPORT

To the Unitholders of APF Energy Trust

We have audited the consolidated balance sheets of APF Energy Trust as at December 31, 2004 and 2003 and the consolidated statements of operations and accumulated earnings and cash flows for the years then ended. These financial statements are the responsibility of the Trust’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with Canadian generally accepted auditing standards. Those standards require that we plan and perform an audit to obtain reasonable assurance whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation.

In our opinion, these consolidated financial statements present fairly, in all material respects, the financial position of the Trust as at December 31, 2004 and 2003 and the results of its operations and its cash flows for the years then ended in accordance with Canadian generally accepted accounting principles.

Calgary, Alberta	Chartered Accountants
February 25, 2005

PricewaterhouseCoopers refers to the Canadian firm of PricewaterhouseCoopers LLP and the other member firms of PricewaterhouseCoopers International Limited, each of which is a separate and independent legal entity.

CONSOLIDATED BALANCE SHEET

($000s except for per unit amounts) As at December 31	2004		2003
			Restated (note 3)
ASSETS
Current assets
Cash	567		1,381
Accounts receivable	42,200		27,542
Derivative asset (note 7)	3,313		—
Other current assets	7,162		5,549
	53,242		34,472
Asset retirement fund	3,271		2,342
Goodwill (note 5)	118,478		48,230
Property, plant and equipment (note 6)	687,179		413,706
	862,170		498,750
LIABILITIES
Current liabilities
Accounts payable and accrued liabilities	52,677		36,698
Derivative liability (note 7)	3,141		—
Distribution payable (note 4)	9,415		5,963
	65,233		42,661
Future income taxes (note 9)	86,711		63,991
Long-term debt (note 8)	169,000		98,000
Convertible debentures (note 10)	47,697		47,719
Asset retirement obligations (note 11)	30,993		21,803
Derivative liability (note 7)	335		—
	399,969		274,174
UNITHOLDERS’ EQUITY
Unitholders’ investment account (note 12)	610,194		324,318
Contributed surplus (note 13)	289		1,241
Accumulated earnings	126,862		77,226
Accumulated distributions (note 4)	(276,293	)	(179,363	)
Convertible debenture conversion feature (note 10)	1,149		1,154
	462,201		224,576
	862,170		498,750

Contractual obligations and commitments (note 16)

See accompanying notes to consolidated financial statements

Approved by the Board of Directors

Martin Hislop	Donald Engle
Director	Director

CONSOLIDATED STATEMENT OF OPERATIONS AND ACCUMULATED EARNINGS

($000s except for per unit amounts) For the year ended December 31	2004			2003
				Restated (note 3)
Revenue
Oil and gas	253,213			173,196
Realized derivative loss – net (note 7)	(16,329		)	(3,565		)
Unrealized derivative gain – net (note 7)	223			—
Royalties expense, net of ARTC	(47,710		)	(32,473		)
Transportation	(5,245		)	(4,174		)
	184,152			132,984
Expenses
Operating	51,788			32,370
General and administrative	10,635			10,023
Interest on long-term debt (note 8)	5,405			4,171
Convertible debenture interest and financing charges (note 10)	5,263			2,669
Depletion, depreciation and accretion	85,997			53,389
Unit-based compensation expense (recovery) (note 13)	(877		)	1,241
Capital and other taxes	3,321			2,720
	161,532			106,583
Income before future income taxes	22,620			26,401
Recovery of future income taxes (note 9)	(27,016		)	(14,207		)
Net income	49,636			40,608
Accumulated earnings – beginning of period, as previously reported	77,226			35,589
Change in accounting policy (note 3)	—			1,029
Accumulated earnings – end of period, as restated	126,862			77,226
Net income per unit – basic	$	1.02		$	1.31
Net income per unit – diluted (1)	$	1.02		$	1.29

(1) Convertible debenture interest has been added back to net income to calculate net income per unit – diluted.

See accompanying notes to consolidated financial statements

54 > APF ENERGY TRUST

CONSOLIDATED STATEMENT OF CASH FLOWS

($000s except for per unit amounts) For the year ended December 31	2004		2003
			Restated (note 3)
Cash flows from operating activities
Net income	49,636		40,608
Items not affecting cash
Depletion, depreciation and accretion	85,997		53,389
Debenture accretion and amortization of deferred financing charges	692		362
Future income taxes	(27,016	)	(14,207	)
Unrealized derivative gain – net (note 7)	(223	)	—
Unit-based compensation expense (recovery) (note 13)	(877	)	1,241
Asset retirement expenditures (note 11)	(1,083	)	(374	)
Cash flow from operations	107,126		81,019
Net change in non-cash working capital items (note 15)	(10,473	)	5,823
Asset retirement fund contribution – net	(929	)	(1,558	)
Net cash provided by operating activities	95,724		85,284
Cash flows from investing activities
Corporate acquisitions (note 5)	(65,405	)	(58,259	)
Additions to property, plant and equipment	(68,779	)	(33,601	)
Purchase of oil and natural gas properties	(10,351	)	(29,238	)
Proceeds on sale of properties	505		9,284
Changes in non-cash working capital – investing items	5,205		2,961
Net cash used in investing activities	(138,825	)	(108,853	)
Cash flows from financing activities
Issue of units for cash	90,451		55,670
Issue of units for cash under DRIP	33,895		1,329
Issue of units for cash upon exercise of stock options/rights	3,799		1,749
Net proceeds (repayment) of convertible debentures	—		47,681
Unit issue costs	(5,270	)	(3,467	)
Net proceeds (repayment) of long-term debt	7,126		(12,920	)
Cash distributions, net of distribution reinvestment	(91,166	)	(68,440	)
Changes in non-cash working capital – financing items	3,452		2,398
Net cash provided by financing activities	42,287		24,000
Change in cash during the period	(814	)	431
Cash – beginning of period	1,381		950
Cash – end of period	567		1,381

Supplemental information (note 14)

See accompanying notes to consolidated financial statements

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, 2004 and 2003

NOTE 1.BASIS OF PRESENTATION

APF Energy Trust (the “Trust”)

The Trust is an open-end investment trust under the laws of the Province of Alberta.

APF Energy Inc. (“Energy”)

Energy was incorporated and organized for the purpose of acquiring, developing, exploiting and disposing of oil and natural gas properties, including certain initial properties and granting a royalty thereon to the Trust.

APF Energy Limited Partnership (“LP”)

LP was formed for the purpose of acquiring, developing, exploiting and disposing of oil and natural gas properties and granting a royalty thereon to the Trust.

Tika Energy Inc. (“Tika”)

Tika is a wholly owned subsidiary of Energy and was incorporated in Wyoming for the purpose of acquiring, developing, exploiting and disposing of coalbed methane gas properties in the United States.

NOTE 2.SIGNIFICANT ACCOUNTING POLICIES

Consolidation

These consolidated financial statements include the accounts of the Trust, Energy, LP and Tika and are referred to collectively as “APF” or “the Trust” Investments in jointly controlled companies and unincorporated joint ventures are accounted for using the proportionate consolidation method, whereby the Trust’s proportionate share of revenues, expenses, assets and liabilities are included in the accounts.

Revenue recognition

Revenue associated with the sale of crude oil, natural gas and natural gas liquids owned by the Trust are recognized when title passes from the Trust to its customers.

Property, plant and equipment

APF uses the full cost accounting method for oil and gas exploration, development and production activities as set out in CICA Accounting Guideline 16 (“AcG-16”), “Oil and Gas Accounting – Full Cost”. The cost of acquiring oil and natural gas properties as well as subsequent development costs are capitalized and accumulated in a cost center. Maintenance and repairs are charged against income, and renewals and enhancements, which extend the economic life of the property, plant and equipment, are capitalized. Gains and losses are not recognized upon disposition of oil and natural gas properties unless such a disposition would alter the rate of depletion by at least 20 percent.

All other equipment is carried at the lesser of depreciated cost and fair value.

Ceiling test

AcG-16 requires that a ceiling test be performed at least annually to assess the carrying value of oil and gas assets. A cost centre is tested for recoverability using undiscounted future cash flows from proved reserves and forward indexed commodity prices, adjusted for contractual obligations and product quality differentials. A cost centre is written down to its fair value when its carrying value, less the cost of unproved properties, is in excess of the related undiscounted cash flows.  Fair value is estimated using accepted present value techniques that incorporate risk and uncertainty when determining expected future cash flows. Unproved properties are excluded from the ceiling test calculation and subject to a separate impairment test.

Depletion, depreciation and accretion

In accordance with the full cost accounting method, all crude oil and natural gas acquisition, exploration, and development costs, including asset retirement costs, are accumulated in a cost center. The aggregate of net capitalized costs and estimated future development costs, less the cost of unproved properties and estimated salvage value, is amortized using the unit-of-production method based on current period production and estimated proved oil and gas reserves calculated using constant prices.

All other equipment is depreciated over the estimated useful life of the respective assets.

Oil and gas reserves

The estimation of reserves is a subjective process. Forecasts are based on engineering data, projected future rates of production, estimated commodity prices, and consider the timing of future expenditures. The Trust expects reserve estimates to be revised based on the results of future drilling activity, testing, production levels and economics of recovery based on cash flow forecasts.

Goodwill

Goodwill is the residual amount that results when the purchase price of an acquired business exceeds the fair value of the net identifiable assets and liabilities of the acquired business. Net identifiable liabilities acquired include an estimate of future income taxes. In accordance with CICA Handbook Section 3062 (“HB 3062”), “Goodwill and Other Intangibles” goodwill for the reporting unit, the consolidated Trust, is tested at least annually for impairment. Impairment is charged to income during the period in which it is deemed to have occurred.

The test for impairment is the comparison of the book value of net assets to the fair value of the Trust. If the fair value of the Trust is less than its book value, the impairment loss is measured by allocating the fair value of the Trust to the identifiable assets and liabilities at their fair values. The excess of the Trust’s fair value over the identifiable net assets is the implied fair value of goodwill. If this amount is less than the book value of goodwill, the deference is the impairment amount and would be charged to income during the period.

Unit-based compensation expense

Effective December 31, 2003, the Trust prospectively adopted CICA Handbook Section 3870, “Stock-based Compensation and Other Stock-based Payments.” The standard requires that equity instruments awarded to employees after December  31, 2002 be measured at fair value and recognized over the related vesting period with a corresponding increase to contributed surplus. When rights are exercised by employees and directors of the Trust, the consideration paid is recorded to the unitholders’ investment account along with related non-cash compensation expense previously recognized in contributed surplus.

APF has established a Trust Units Options Plan (the “Plan”) and a Trust Unit Incentive Rights Plan (the “Rights Plan”) for employees and independent directors that are described in Note 13. The exercise price of the rights granted under the Rights Plan may be reduced in future periods based on future operating performance in accordance with the terms of the Rights Plan.

The Trust uses a Black-Scholes option-pricing model to estimate the fair value of rights awarded under the Rights Plan at the grant date. The fair value ascribed to awarded rights is not subsequently revised for any change in underlying assumptions. Unit-based compensation expense is adjusted prospectively for rights cancelled under the Rights Plan during the period.

The new accounting standard resulted in the Trust recognizing an expense of $1.24 million for the year ended December 31, 2003, with a corresponding increase to contributed surplus. In conformity with the amended accounting standard, the Trust has elected to disclose pro forma results for equity instruments awarded to employees prior to January 1, 2003, as if CICA Handbook Section 3870, “Stock-based Compensation and Other Stock-based Payments” had been adopted retroactively.

There was no impact on the Trust’s cash flow as a result of adopting the new standard. See Note 13 for additional information on compensation plans.

Income taxes

The Trust is an inter vivos trust for income tax purposes. As such, the Trust is taxable on income that is not distributed or distributable to unitholders. As the Trust distributes all of its taxable income to the unitholders no current provision for income taxes has been recorded. Should the Trust incur any income taxes, the funds available for distribution would be reduced accordingly.

The provision for income taxes is recorded in Energy using the liability method of accounting for income taxes. Future income taxes are recorded to the extent the accounting bases of assets and liabilities differ from their corresponding tax values using substantively enacted income tax rates. Accumulated future income tax balances are adjusted to reflect changes in income tax rates that are substantively enacted during the period with the adjustment recognized in net income.

The determination of the Trust’s income and other tax liabilities are subject to audit and potential reassessment after the lapse of considerable time. Accordingly, actual income tax liabilities or recoveries may differ significantly from estimates.

Trust unit calculations

The Trust applies the treasury stock method to determine the dilutive effect of Trust unit rights and Trust unit options. Under the treasury stock method, outstanding and exercisable instruments that will have a dilutive effect are included in per unit – diluted calculations, ordered from most dilutive to least dilutive.

The dilutive effect of convertible debentures is determined using the “if-converted” method whereby if the current market price per unit is in excess of the stated conversion price per unit the weighted-average number of potential units assumed issued are included in the per unit – diluted calculations. The units issued upon conversion are included in the denominator of per unit – basic calculations from the date of conversion. Consequently, units assumed issued are weighted for the period the convertible debentures were outstanding, and units actually issued are weighted for the period the units were outstanding.

Measurement uncertainty

The timely preparation of financial statements in conformity with Canadian generally accepted accounting principles (“GAAP”) requires that management make estimates and assumptions and use judgment regarding assets, liabilities, revenues, and expenses. Such estimates primarily relate to unsettled transactions and events as of the date of the financial statements. Accordingly, actual results may differ from estimated amounts as future confirming events occur.

Amounts recorded for depreciation, depletion, and amortization, asset retirement costs and obligations, and amounts used for ceiling test and impairment calculations are based on estimates of oil and natural gas reserves and future costs required to develop those reserves. By their nature, these estimates are subject to measurement uncertainty, and the impact on the financial statements of future periods could be material.

NOTE 3.CHANGES IN ACCOUNTING POLICIES

Asset retirement obligations

Effective January 1, 2004, the Trust retroactively adopted CICA Handbook Section 3110, “Asset Retirement Obligations” (ARO). The standard requires that the fair value of an asset retirement obligation be recognized in the period in which it is incurred. The present value of the asset retirement obligation is recognized as a liability with the corresponding asset retirement cost capitalized as part of property, plant and equipment. The asset retirement obligation will increase over time due to accretion and the asset retirement cost will be depreciated on a basis consistent with depreciation and depletion. APF previously used the unit-of-production method to match estimated future retirement costs with the revenues generated over the life of the petroleum and natural gas properties based on total estimated proved reserves and an estimated future liability.

The following table summarizes the impact of the new standard on the 2003 comparative period:

	As at and for the year ended December 31, 2003
($000s except for per unit amounts)	As reported		Change		As restated
Consolidated Balance Sheet
Assets
Property, plant, and equipment	401,286		12,420		413,706
Liabilities
Future income taxes	64,222		(231	)	63,991
Asset retirement obligation	—		21,803		21,803
Site restoration liability	10,410		(10,410	)	—
Unitholders’ Equity
Opening accumulated earnings	35,589		1,029		36,618
Consolidated Statement of Operations
Depletion, depreciation, and accretion	50,417		2,972		53,389
Site restoration	3,327		(3,327	)	—
Recovery of future income taxes	(14,333	)	126		(14,207	)

See Note 11 for additional information on asset retirement obligations.

Derivative instruments and hedging relationships

Effective January 1, 2004, the Trust prospectively adopted CICA Accounting Guideline 13 (“AcG-13”), “Hedging Relationships” and the amended Emerging Issues Committee Abstract 128, “Accounting for Trading, Speculative or Non Trading Derivative Financial Instruments” In accordance with these standards, all unrealized derivative instruments that either do not qualify as a hedge under AcG-13, or are not designated as a hedge, are recorded as a derivative asset or a derivative liability on the consolidated balance sheet with any changes in fair value during the period recognized in income. Prior to January 1, 2004, the Trust recognized gains and losses on derivative contracts at the time of settlement.

In order to apply hedge accounting, an entity must formally document the hedging arrangement and sufficiently demonstrate the Effectiveness of the hedging relationship. Based on a review of the Trust’s derivative position at January 1, 2004, the majority of derivative contracts did not qualify for hedge accounting. Consequently, the Trust recorded $1.30 million liability as an estimate for the fair value of its derivative position on January 1, 2004, which was comprised of a $0.40 million unrealized loss on crude oil and natural gas derivative instruments and a $0.90 million unrealized loss on interest rate swaps. In accordance with the transitional provisions of the new guideline, the Trust recorded a corresponding deferred derivative loss, which was amortized into income during 2004 upon settlement of the underlying derivative instruments. There was no impact on the Trust’s cash flow as a result of adopting this new guideline. See Note 7 for additional disclosure on derivative instruments.

Financial instruments with a conversion feature

Effective December 31, 2004, the Trust retroactively adopted the revised CICA Handbook Section 3860 (“HB 3860”), “Financial Instruments - Presentation and Disclosure” for financial instruments that may be settled at the issuer’s option in cash or its own equity. The revised standard requires the Trust to classify proceeds from convertible debentures issued on July 3, 2003 as either debt or equity based on fair value measurement and the substance of the contractual arrangement. The Trust previously presented the convertible debenture proceeds (net of financing costs) and related interest obligations as equity on the consolidated balance sheet on the basis that the Trust could settle its obligations in exchange for Trust units.

The Trust’s obligation to make scheduled payments of principal and interest constitutes a financial liability under the revised standard and exists until the instrument is either converted or redeemed. The holders’ option to convert the financial liability into Trust units is an embedded conversion option. Gross proceeds of $50 million received at issuance were allocated $48.82 million to debt and $1.18 million to the equity conversion feature. At December 31, 2003, after conversions and accretion, the debt component was $47.72 million and the equity component was $1.15 million. Underwriter costs and professional fees associated with the issuance totalled $2.32 million and will be amortized into income on a straight-line basis over the term of the instrument. At December 31, 2003, $2.04 million was included in other current assets.

The following table summarizes the impact of the revised standard on the 2003 comparative period:

	As at and for the year ended December 31, 2003
($000s except for per unit amounts)	As reported		Change		As restated
Consolidated Balance Sheet
Assets
Other current assets (includes deferred financing)	3,506		2,043		5,549
	3,506		2,043		5,549
Liabilities
Accounts payable and accrued liabilities	36,711		(13	)	36,698
Convertible debentures	—		47,719		47,719
	36,711		47,706		84,417
Unitholders’ Equity
Unitholders investment account	324,317		1		324,318
Convertible debentures	46,466		(46,466	)	—
Accumulated interest on convertible debentures	(2,317	)	2,317		—
Convertible debenture conversion feature	—		1,154		1,154
	368,466		(42,994	)	325,472
Consolidated Statement of Operations
Convertible debenture interest and financing charges	—		2,669		2,669

There was no impact on the Trust’s cash flow as a result of adopting the revised standard. See Note 10 for additional information on convertible debentures.

NOTE 4.DISTRIBUTIONS

	For the year ended December 31
($000s except for per unit amounts)	2004			2003
				Restated (note 3)
Cash flow from operations	107,126			81,019
Add (deduct):
Abandonment fund contributions	(2,012		)	(1,932		)
Cash retained to fund operations	(6,368		)	(21,556		)
Working capital change	(1,816		)	11,182
Distributions	96,930			68,713
Distributed to date	87,515			62,750
Distribution payable	9,415			5,963
	96,930			68,713
Opening accumulated distributions	179,363			110,650
Closing accumulated distributions	276,293			179,363
Actual distribution declared per unit	$	2.00		$	2.20

NOTE 5.ACQUISITIONS

On June 4, 2004, the Trust acquired the issued and outstanding shares of Great Northern Exploration Ltd. (“Great Northern”). During 2003, APF acquired the issued and outstanding shares of Hawk Oil Inc. (“Hawk Oil”) on February 5, Nycan Energy Corp. (“Nycan”) on April 28, and CanScot Resources Ltd. (“CanScot”) on September 26. The purchase price allocation for each acquisition and components of consideration paid is as follows:

	Great Northern		CanScot		Nycan		Hawk Oil
($000)	2004		2003		2003		2003
Net assets acquired at assigned values:
Working capital deficiency	(4,857	)	178		928		(634	)
Property, plant and equipment	255,941		32,980		47,495		57,146
Undeveloped land and seismic	22,943		—		—		—
Goodwill	70,248		16,884		8,792		11,078
Debt assumed	(63,874	)	(6,150	)	(8,870	)	(7,900	)
Financial derivatives	(1,103	)	—		—		—
Asset retirement obligation	(7,866	)	(388	)	(580	)	(263	)
Future income taxes	(49,084	)	(7,399	)	(13,266	)	(18,266	)
Net assets acquired	222,348		36,105		34,499		41,161
Purchase price comprised of:
Trust units	156,943		15,433		—		37,710
Cash	63,250		—		—		2,856
Bank debt	—		19,689		34,374		—
Acquisition costs	2,155		983		125		595
Purchase price	222,348		36,105		34,499		41,161

The following table highlights investing cash flows associated with corporate acquisitions completed in 2004 and 2003:

	Great Northern		CanScot		Nycan		Hawk Oil
($000)	2004		2003		2003		2003
Net assets acquired	222,348		36,105		34,499		41,161
Deduct:
Debt assumed (cash acquired)	—		(156	)	(212	)	5
Trust units issued	(156,943	)	(15,433	)	—		(37,710	)
Net cash flows from corporate acquisitions	65,405		20,516		34,287		3,456

NOTE 6.PROPERTY, PLANT AND EQUIPMENT

($000)	2004		2003
Property, plant, and equipment	907,819		548,229
Accumulated depletion, depreciation, and accretion	(220,640	)	(134,523	)
	687,179		413,706

Future development costs of $48.22 million (2003 – $25.00 million) related to total proved reserves were included as depletable costs in the calculation of depletion, depreciation and accretion. Costs related to unproved properties totalled $28.45 million (2003 – $10.80 million) and were excluded from depletable costs. All costs of unproved properties, net of any associated revenues, have been capitalized. Ultimate recoverability of these costs will be dependent upon the finding of proved oil and natural gas reserves. The Trust performed a separate impairment review of assets excluded from the ceiling test and determined that $nil (2003 – $nil) should be charged to income during the year.

The Trust capitalized $0.50 million (2003 – $0.46 million) of administrative costs during the year associated with coalbed methane projects considered to be in the pre-production stage.

The prices used in the ceiling test evaluation of the Trust’s natural gas, crude oil and natural gas liquids reserves at December 31, 2004 were as follows:

			Foreign
	WTI Oil		Exchange	WTI Oil		AECO Gas
Year	($U.S./bbl)		($U.S./$Cdn.)	($Cdn./bbl)		($Cdn./mmbtu)
2005	42.76		1.1667	48.95		6.43
2006	40.56		1.1931	47.37		6.56
2007	39.44		1.2202	47.26		6.28
2008	37.77		1.2561	46.74		6.04
2009	37.14		1.2961	47.31		5.83
2010 – 2016 (1)	37.41		1.2961	47.56		5.87
Remainder (2)	2.00	%	1.2961	2.00	%	2.00	%

(1) Represents the average for the period noted

(2) Percentage change represents the annual change each year from 2014 to the end of the reserve life

NOTE 7.RISK MANAGEMENT AND FINANCIAL INSTRUMENTS

The Trust has entered into various derivative instruments and physical contracts to manage fluctuations in commodity prices, foreign currency exchange rates, utility prices, and interest rates in the normal course of operations. A derivative instrument meets the definition of a financial instrument because it involves the exchange of financial assets, usually cash, and not the delivery or acceptance of oil and gas inventory. Conversely, a physical contract is not a financial instrument because it involves the delivery or acceptance of physical product. In conformity with AcG-13 and EIC 128 (see note 3), the following information only presents positions related to financial instruments.

The estimated fair value of unrealized derivative instruments is reported on the consolidated balance sheet with any change in the unrealized positions recorded to income. The following is a summary of the change in unrealized amounts from January 1, 2004 to December 31, 2004:

	Deferred
	derivative loss
	recognized on	Total realized		Total
($000)	transition	gain/(loss)		gain/(loss)
Fair value of contracts, January 1, 2004	1,300			(1,300	)
Fair value of derivative contracts entered into during the period				(14,806	)
Fair value of derivative contracts realized during the period		(16,329	)	16,329
Fair value of contracts, December 31, 2004				223
Premiums received on sold call options				(386	)
FV of contracts and premiums received, December 31, 2004				(163	)

The following is a summary of unrealized fair value financial positions by risk management activity at December 31, 2004:

($000)	Total unrealized gain/(loss)
Commodity price
Crude oil	(2,298	)
Natural gas	2,059
Utilities	32
Foreign currency	1,103
Interest rate	(673	)
	223
Premiums received on sold call options	(386	)
	(163	)

The following highlights the balance sheet classification of unrealized fair value financial positions at December 31, 2004:

($000)	Unrealized asset (liability)
Current asset	3,313
Long-term asset	—
Current liability	(3,141	)
Long-term liability	(335	)
	(163	)

Commodity price risk

Commodity price risk is defined as fluctuations in crude oil, natural gas, and natural gas liquid prices. The Trust uses derivative instruments as part of its risk management approach to manage commodity price fluctuations and stabilize cash flows available for unitholder distributions and future development programs. At December 31, 2004, the Trust had recorded a $2.30 million unrealized loss on outstanding crude oil derivative instruments and a $2.06 million unrealized gain on outstanding natural gas derivative instruments.

Crude oil and natural gas derivative instruments outstanding at the end of 2004 are as follows:

	Type of	Average	Average daily
Period	commodity	contract	daily quantity	Price per bbl, GJ or mmbtu
January to March 2005	Crude oil	Swap	1,500 bbls	$U.S. 35.78
January to March 2005	Crude oil	Collar	1,000 bbls	$U.S. 38.00 to $U.S. 44.95
January to March 2005	Crude oil	Sold call	500 bbls	$U.S. 42.37 ($U.S. 3.19 premium)
April to June 2005	Crude oil	Swap	667 bbls	$U.S. 36.66
April to June 2005	Crude oil	Collar	2,000 bbls	$U.S. 39.25 to $U.S. 44.94
April to June 2005	Crude oil	Sold call	500 bbls	$U.S. 40.95 ($U.S. 3.45 premium)
July to September 2005	Crude oil	Collar	1,000 bbls	$U.S. 41.00 to $U.S. 51.30
January to March 2005	Natural gas	Sold call	5,000 GJ	$Cdn. 11.80
January to March 2005	Natural gas	Collar	5,000 GJ	$Cdn. 7.00 to $Cdn. 11.35
April to October 2005	Natural gas	Collar	5,000 mmbtu	$U.S. 6.50 to $U.S. 6.90
April to October 2005	Natural gas	Collar	10,000 GJ	$Cdn. 6.25 to $Cdn. 7.20

Electricity price risk

The Trust’s electricity cost management activities had an unrealized gain of $0.03 million at year end. APF had assumed a fixed price electricity contract through the acquisition of Great Northern. At December 31, 2004, the Trust had a 2MW (7x24) contract with a fixed price of $46.40/MWh for calendar 2005.

Foreign currency risk

The Trust’s foreign currency risk management activities had an unrealized gain of $1.10 million at year end. Foreign currency risk is the risk that a variation in the U.S./Cdn. exchange rate will negatively impact the Trust’s operating and financial results.  At December 31, 2004, the Trust had entered into contracts to sell U.S. dollars at a fixed rate in exchange for Canadian dollars as follows:

		Amount
Term	Type of Contract	($U.S. 000)	Exchange rate ($U.S. / $Cdn.)
January to April 2005	Forward	5,000	1.3550
January to April 2005	Forward	5,000	1.3680
January to December 2005	Collar	5,000	1.2300 to 1.2700
January to December 2005	Collar	10,000	1.2000 to 1.2600

The costless collar arrangements have counterparty call options on December 30, 2005 whereby the Trust’s counterparty can extend the $5.00 million contract term for calendar 2006 at 1.3100 and the $10.00 million contract term for calendar 2006 at 1.2700.

Interest rate risk

The Trust’s interest rate risk management activities had an unrealized loss of $0.67 million at year end. The Trust had entered into various derivative instruments to manage its interest rate exposure on debt instruments. At December 31, 2004 the Trust had fixed the interest rate on a portion of its debt as follows:

Term	Amount ($000)	Interest rate
January 2005 to November 2005	20,000	3.58% plus stamping fee
January 2005 to May 2006	20,000	3.60% plus stamping fee
January 2005 to March 2007	20,000	3.58% plus stamping fee
January 2005 to September 2007	20,000	3.65% plus stamping fee

Fair value of financial assets and liabilities

The fair values of financial instruments presented on the consolidated balance sheet, other than long-term borrowings, approximate their carrying amount due to the short-term nature of those instruments. The estimated fair values of long-term borrowings approximated its fair value due to the floating rate of interest charged under the facilities.

NOTE 8.LONG - TERM DEBT

At December 31, 2004, APF had a revolving credit and term facility for $200 million (2003 – $150 million) with a syndicate of Canadian financial institutions. The facility may be drawn down or repaid at any time but there are no scheduled repayment terms. The credit facility bears interest based on a sliding scale tied to APF’s debt-to-cash flow ratio: from a minimum of the bank’s prime rate to a maximum of the bank’s prime rate plus 1.625 percent (2003 – 0.125 to 1.625 percent) or where available, at Banker’s acceptances rates plus a stamping fee of 1.00 to 2.25 percent (2003 – 1.125 to 2.00 percent). The facility contains an option to extend the revolving period for an additional 364 days at the option of the lenders upon notice from the Trust no earlier than 180 days and no less than 90 days prior to the end of the initial revolving period, being October 31, 2005. If not extended, the outstanding principal converts to a one-year non-revolving reducing loan for a term of one year. From the date of conversion to a one-year term facility, APF will pay one-sixth of the outstanding principal after 180 days and one-twelfth of the outstanding principal every 90 days thereafter.

The debt is collateralized by a $300 million demand debenture containing a first fixed charge on all crude oil and natural gas assets of APF as required by the lenders and a floating charge on all other property together with a general assignment of book debts. At December 31, 2004, the interest rate was bank prime of 4.25 percent plus 0.125 percent (2003 – 4.5 percent plus 0.125 percent).

NOTE 9.INCOME TAXES

The Trust applies substantively enacted income tax rates to derive its future income tax liability and the related provision (recovery) during the year. The Trust recorded a future income tax recovery of $27.02 million during the year (2003 – $14.21 million). The acquisition of Great Northern increased the future tax liability by $49.08 million resulting from temporary differences between tax bases and the fair value assigned to assets and liabilities acquired.

Federal corporate income tax rate reductions received Royal Accent during 2003. The applicable tax rate on resource income will ultimately be reduced from 28 per cent to 21 per cent over a five-year period, provide for the deduction of crown royalties and eliminate the deduction for resource allowance. The tax provision differs from the amount computed by applying the combined Canadian federal and provincial income tax statutory rates to income before future income tax recovery as follows:

($000)	2004		2003
Income before income taxes	22,620		26,401
Statutory tax rate	40.32	%	42.75	%
Expected tax provision (recovery)	9,120		11,286
Adjustments:
Net income of the Trust	(26,191	)	(19,886	)
Resource allowance	(1,625	)	(2,250	)
Non-deductible crown charges	2,056		669
Capital tax	972		1,163
Rate reduction	(2,088	)	(3,717	)
Revision to tax pool estimates	(8,972	)	—
Other	(288	)	(1,472	)
Recovery of future income taxes	(27,016	)	(14,207	)
Future tax liability comprised of:
Accounting basis for capital assets in excess of tax basis	102,663		80,269
Asset retirement obligations	(11,197	)	(7,775	)
Derivative contracts	(59	)	—
Future tax losses likely to be utilized	(4,696	)	(8,503	)
	86,711		63,991

The petroleum and natural gas properties and facilities owned by Energy and LP have an approximate tax bases of $185.00 million (2003 – $70.00 million) available for future use as deductions from taxable income. Included in the tax bases are non-capital loss carry forwards of $6.60 million (2003 – $22.30) which expire during years 2005 through 2010. No current income taxes were paid or payable in 2004 or 2003.

Taxable income of the Trust is comprised of income from royalties, adjusted for crown royalties and resource allowance, less deductions for Canadian oil and natural gas property expense (COGPE), which is claimed at a rate of 10 percent on a declining balance basis and issue costs which are claimed at 20 percent per year on a straight-line basis. Any losses that occur in the Trust must be retained in the Trust and may be carried forward and deducted from taxable income for a period of seven years. The tax bases held within the Trust at December 31, 2004 was $214.00 million (2003 – $122.30 million).

NOTE 10.CONVERTIBLE DEBENTURES

On July 3, 2003, APF issued $50.0 million of 9.40 percent unsecured subordinated convertible debentures (“convertible debentures”) for proceeds of $50.0 million ($47.7 million net of issue costs). Interest is paid semi-annually on January 31 and July 31 and the instruments mature on July 31, 2008.

The debentures are convertible at the holder’s option into fully paid and non-assessable Trust units at any time prior to July 31, 2008, at a conversion price of $11.25 per Trust unit. The holder will receive accrued and unpaid interest up to and including the conversion date. The debentures are not redeemable by the Trust before July 31, 2006, except under certain circumstances. The convertible debentures become redeemable at $1,050 per convertible debenture, in whole or in part, after July 31, 2006 and redeemable at $1,025 after July 31, 2007 and before maturity.

The convertible debentures are a debt security with an embedded conversion option and the following summarizes the accounting for the principal amount of the convertible debentures since their issuance:

	Liability		Equity
($000)	component		component		Total
Issued on July 3, 2003	48,817		1,183		50,000
Accretion of liability during 2003	89		—		89
Conversions into Trust units during 2003	(1,187	)	(29	)	(1,216	)
Carrying value at December 31, 2003	47,719		1,154		48,873
Accretion of liability during 2004	193		—		193
Conversions into Trust units during 2004	(215	)	(5	)	(220	)
Carrying value at December 31, 2004	47,697		1,149		48,846

NOTE 11.ASSET RETIREMENT OBLIGATIONS

The following table presents the reconciliation of the beginning and ending aggregate asset retirement obligation associated with the retirement of oil and gas properties:

($000)	2004		2003
Asset retirement obligation, beginning of year	21,803		12,961
Liabilities acquired	7,866		4,673
Liabilities incurred	834		3,249
Liabilities settled	(1,083	)	(374	)
Accretion expense	1,573		1,294
Asset retirement obligation, end of year	30,993		21,803

The total undiscounted amount of estimated cash flows required to settle the obligation is $108.29 million (2003 - $70.72 million), which has been discounted using a credit-adjusted risk free rate of eight percent and an inflation factor of one and one-half percent. Most of these obligations are not expected to be paid for several years, or decades, in the future and will be funded from general company resources and the fund reserved for site reclamation and abandonment. The abandonment fund is currently funded at $0.53 million per quarter through cash flow from operations.

NOTE 12.UNITHOLDERS’ INVESTMENT ACCOUNT

The per unit calculations for the year ended December 31, 2004 was based on weighted average Trust units outstanding of 48.49 million (2003 – 30.97 million). In computing net income per unit - diluted, 0.33 million units (2003 – 0.33 million)  were added to the weighted average number of units outstanding for the year, reflecting the dilutive effect of employee options and rights. An additional 4.32 million Trust units (2003 – 2.18 million) were added to the weighted average number of units outstanding for the year relating to the assumed conversion of debentures. Interest on debentures assumed to be converted into Trust units totalled $5.26 million (2003 – $2.67 million) and was added back to net income for per unit - diluted calculations.

	December 31, 2004			December 31, 2003
Trust units	Units (000)	($000)		Units (000)	($000)
Balance – beginning of period	34,074	324,318		22,942	214,405
Corporate acquisitions (note 5)	12,885	156,943		5,333	53,143
Issued for cash	7,877	90,451		5,352	55,670
Cost of units issued	—	(5,270	)	—	(3,467	)
Regular DRIP	516	5,764		24	273
Premium DRIP	3,031	33,895		117	1,329
Issued on conversion of debentures	19	220		108	1,216
Issued on exercise of options/rights	442	3,799		199	1,749
Allocated from contributed surplus	—	74		—	—
Balance – end of period	58,845	610,194		34,074	324,318

Unitholders’ rights plan

In 2003, the Trust created a Unitholders’ Rights Plan and authorized the issuance of one right in respect of each Trust unit outstanding. Each right would entitle a unitholder under certain circumstances to acquire upon payment of an exercise price of $50.00, the number of Trust units having an aggregate market price equal to twice the exercise price of the rights.

Units issued for cash

The Trust issued Trust units on two separate occasions: 4.77 million Trust units at $11.60 per unit for gross proceeds of $55.27  million on February 4, 2004; and 3.10 million Trust units at $11.30 per unit for gross proceeds of $35.03 million on September  8, 2004.

Distribution reinvestment program

Commencing December 2003, the Trust initiated a distribution reinvestment plan (“DRIP”). The DRIP permits eligible unitholders to direct their distributions to the purchase of additional units at 95 percent of the average market price as defined in the plan (“Regular DRIP”). The premium distribution component permits eligible unitholders to elect to receive 102 percent of the cash the unitholder would otherwise have received on the distribution date (“Premium DRIP”). Participation in the Regular DRIP and Premium DRIP is subject to proration by the Trust. Unitholders who participate in either the Regular DRIP or the Premium DRIP are also eligible to participate in the optional unit purchase plan as defined in the DRIP

NOTE 13.UNIT-BASED COMPENSATION PLANS

APF has established a Trust Units Options Plan (the “Plan”) and a Trust Unit Incentive Rights Plan (the “Rights Plan”) for employees and independent directors. Pursuant to the Plan arrangement, employees, directors and long-term consultants may be granted options to purchase Trust units. The exercise price for each option granted was not less than the market price of the Trust’s units on the grant date and the contractual term of each option is not to exceed five years. Options granted before February 1, 1998 vested immediately; options granted after January 28, 1998 vested in one-third increments on the first, second and third anniversaries of their grant date. The Plan was replaced in 2001 with the Rights Plan. No additional options have been granted under the Plan since 2001. A summary of the change in the Plan during 2004 and 2003 is as follows:

	December 31, 2004			December 31, 2003
			Weighted			Weighted
			average			average
Trust unit options	Options (000)		price ($)	Options (000)		price ($)
Balance – beginning of period	126		9.59	244		9.13
Granted	—		—	—		—
Exercised	(46	)	9.45	(107	)	8.55
Cancelled	—		—	(11	)	9.42
Balance – end of period	80		9.68	126		9.59
Exercisable – end of period	80		9.68	60		9.48

The following table summarizes Plan related information at December 31, 2004:

	December 31, 2004
	Weighted
	average		Weighted		Weighted
	remaining	Options	average	Options	average
	contractual life	outstanding	exercise	exercisable	exercise
	(years)	(000)	price ($)	(000)	price ($)
Range
7.00 to 7.99	0.18	1	7.15	1	7.15
8.00 to 8.99	0.68	—	8.85	—	8.85
9.00 to 9.99	1.16	79	9.70	79	9.70
	1.16	80	9.68	80	9.68

Under the Rights Plan, employees, directors and long-term consultants may be granted rights to purchase Trust units. The exercise price for each right granted is not to be less than the market price of the Trust’s units on the grant date and the contractual term of each right is not to exceed ten years. The exercise price of the rights is adjusted downwards from time to time by the amount, if any, that distributions to unitholders in any calendar quarter exceeds a percentage of the Trust’s net book value of property, plant, and equipment, as determined by the Trust.

A summary of the change in the Rights Plan during 2004 and 2003 is as follows:

	December 31, 2004				December 31, 2003
			Weighted				Weighted
			average				average
Trust unit rights	Rights (000)		price ($)		Rights (000)		price ($)
Balance – beginning of period	1,824		9.09		429		9.37
Granted	952		11.91		1,538		9.78
Exercised	(395	)	8.49		(92	)	9.05
Cancelled	(510	)	9.43		(51	)	9.67
Balance – before price reduction	1,871		10.56		1,824		9.72
Reduction of exercise price	—		(0.72	)	—		(0.63	)
Balance – end of period	1,871		9.84		1,824		9.09
Exercisable – end of period	241		8.50		47		8.58

The following table summarizes Rights Plan related information at December 31, 2004:

	December 31, 2004
	Weighted
	average		Weighted		Weighted
	remaining	Rights	average	Rights	average
	contractual	outstanding	exercise	exercisable	exercise
Range	life (years)	(000)	price ($)	(000)	price ($)
7.00 to 7.99	7.17	140	7.68	52	7.68
8.00 to 8.99	8.26	808	8.38	156	8.38
9.00 to 9.99	8.45	17	9.43	5	9.49
10.00 to 10.99	8.75	83	10.59	28	10.59
11.00 to 11.99	9.39	823	11.56	—	—
	8.70	1,871	9.84	241	8.50

In conformity with CICA Handbook Section 3870, “Stock-based Compensation and Other Stock-based Payments” discussed in note 2, no compensation cost has been recognized for unit-based compensation granted prior to January 1, 2003. In accordance with the transitional provisions, the Trust has disclosed pro forma results as if the new standard had been adopted retroactively. At December 31, 2004, proforma net income and earnings per share would not have been materially different from those disclosed in the consolidated statement of operations and accumulated earnings.

The fair value of rights granted after December 31, 2002 was estimated using a Black-Scholes option-pricing model incorporating the following assumptions: risk-free interest rates ranging from 3.01 to 4.62 percent; volatility ranging from 16.14 and 22.63 percent; expected rights term of five years; and dividend yield rates ranging from 11.10 to 13.87 percent, representing the difference between the anticipated distribution and price reduction yields. The initial fair value ascribed to rights granted under the Rights Plan is not subsequently revised for changes in any of the underlying assumptions and is recorded as compensation expense evenly over the contractual vesting period. Compensation expense is adjusted prospectively for rights cancelled under the Rights Plan during the period.

The Trust recorded a recovery of compensation expense of $0.88 million during 2004 (2003 – expense of $1.24 million) related to vested rights issued under the Rights Plan with a corresponding increase to contributed surplus. When rights are exercised by employees and directors of the Trust, the consideration paid is recorded to the unitholders’ investment account along with related non-cash compensation expense previously recognized in contributed surplus.

NOTE 14.SUPPLEMENTAL CASH FLOW INFORMATION

Twelve months ended December 31 ($000)	2004	2003
Cash payments related to certain items
Interest	957	4,070
Interest on debentures	4,947	30
Interest rate swap settlement	901	—
Capital and other taxes	3,507	3,389

NOTE 15.NET CHANGE IN NON-CASH WORKING CAPITAL ITEMS

Twelve months ended December 31 ($000)	2004		2003
Change in working capital items
Accounts receivable	(551	)	1,016
Other current assets	(1,415	)	(397	)
Accounts payable and accrued liabilities	(8,893	)	5,204
Derivatives liabilities	386		—
	(10,473	)	5,823

NOTE 16.CONTRACTUAL OBLIGATIONS AND COMMITMENTS

APF is involved in certain legal actions that occurred in the normal course of business. APF is required to determine whether a contingent loss is probable and whether that loss can be reasonably estimated. When the loss has satisfied both criteria, it is charged to income. Management is of the opinion that losses, if any, arising from such legal actions would not have a material effect on these financial statements.

The Trust leases its office premises through an arrangement deemed to be an operating lease for accounting purposes. As such, the Trust is not required to record its lease obligation as a liability nor does it record its leased premises as an asset. The estimated operating lease commitments for the Trust’s leased office premises for the next five years are as follows:

($000)
2005	1,398
2006	1,213
2007	1,252
2008	1,083
2009	934
Thereafter	934

AUDITORS’ REPORT TO THE SHAREHOLDERS

We have audited the balance sheets of Great Northern Exploration Ltd. as at December 31, 2003 and 2002 and the statements of operations and retained earnings and cash flows for the years then ended.  These financial statements are the responsibility of the company’s management.  Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with Canadian generally accepted auditing standards.  Those standards require that we plan and perform an audit to obtain reasonable assurance whether the financial statements are free of material misstatement.  An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements.  An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation.

In our opinion, these financial statements present fairly, in all material respects, the financial position of the company as at December 31, 2003 and 2002 and the results of its operations and its cash flows for the years then ended in accordance with Canadian generally accepted accounting principles.

(Signed) “KPMG LLP”

Chartered Accountants

Calgary, Canada

March 17, 2004

CONSOLIDATED FINANCIAL STATEMENTS

CONSOLIDATED BALANCE SHEET

As at December 31,			2003	2002
			$	$
ASSETS
Current assets
Accounts receivable			12,456,000	5,192,000
Prepaid expenses			609,000	382,000
			13,065,000	5,574,000
Property and equipment	(note 5	)	120,491,000	34,789,000
			133,556,000	40,363,000
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities
Accounts payable			19,754,000	10,656,000
Bank debt	(note 6	)	38,555,000	5,107,000
			58,309,000	15,763,000
Future income taxes	(note 11	)	8,097,000	—
Future site restoration	(note 7	)	630,000	136,000
			67,036,000	15,899,000
Shareholders’ equity
Share capital	(note 8	)	54,281,000	22,866,000
Contributed surplus	(note 3	)	136,000	—
Retained earnings			12,103,000	1,598,000
			66,520,000	24,464,000
Subsequent events	(note 14	)	133,556,000	40,363,000

On behalf of the Board of Directors:

James M. Saunders

Director

Warren Steckley

Director

(See accompanying notes to the consolidated financial statements)

CONSOLIDATED STATEMENT OF OPERATIONS AND RETAINED EARNINGS

Year ended December 31,			2003		2002
			$		$
Revenue
Petroleum and natural gas sales			51,317,000		12,170,000
Royalties, net			(9,928,000	)	(1,965,000	)
			41,389,000		10,205,000
Expenses
Operating			9,617,000		2,626,000
General and administrative			1,363,000		938,000
Financial charges			1,172,000		220,000
Depletion and depreciation			12,021,000		2,848,000
			24,173,000		6,632,000
Earnings before taxes			17,216,000		3,573,000
Capital taxes			306,000		116,000
Future income taxes	(note 11	)	6,405,000		1,663,000
			6,711,000		1,779,000
Net earnings			10,505,000		1,794,000
Retained earnings (deficit), beginning of year			1,598,000		(196,000	)
Retained earnings, end of year			12,103,000		1,598,000
Net earnings per share
Basic			0.30		0.08
Diluted			0.29		0.07

(See accompanying notes to the consolidated financial statements)

MANAGEMENT’S DISCUSSION AND ANALYSIS

CONSOLIDATED STATEMENT OF CASH FLOW

Year ended December 31,			2003		2002
			$		$
Cash flow related to the following activities
Operating
Net earnings for the period			10,505,000		1,794,000
Items not affecting cash:
Depletion and depreciation			12,021,000		2,848,000
Stock-based compensation	(note 3	)	136,000		—
Future income taxes			6,405,000		1,663,000
Cash flow from operations			29,067,000		6,305,000
Changes in non-cash operating working capital items			3,717,000		(706,000	)
			32,784,000		5,599,000
Financing
Change in bank debt			33,448,000		(8,888,000	)
Share issuance, net			33,106,000		4,276,000
			66,554,000		(4,612,000	)
Cash available for investment activities			99,338,000		987,000
Investing
Property and equipment additions			(96,880,000	)	(13,602,000	)
Site restoration expenditures			(348,000	)	—
Changes in non-cash investing working capital items			(2,110,000	)	4,401,000
			(99,338,000	)	(9,201,000	)
Change in cash			—		(8,214,000	)
Cash, beginning of year			—		8,214,000
Cash, end of year			—		—

(See accompanying notes to the consolidated financial statements)

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

YEAR ENDED DECEMBER 31, 2003

(tabular amounts in thousands of dollars, unless otherwise stated)

1.NATURE OF OPERATIONS

The shareholders of Great Northern Exploration Ltd. (“the Company”), approved a name change from Ascot Energy Resources Ltd. (“Ascot”) and a share consolidation on the basis of one new share for every five existing common shares at the Annual and Special Meeting held on September 26, 2002. All share data including number of common shares outstanding, per share data and stock options outstanding have been adjusted to reflect the share consolidation.

On July 10, 2002, the Company acquired all the shares of Great Northern Exploration Ltd. (“Great Northern”), a private corporation. Great Northern was incorporated on August 9, 2001 and commenced active operations in September 2001.

The transaction has been accounted for as a reverse takeover of the Company by Great Northern. Accordingly, the results of operations for 2002 include those of Great Northern from the date of incorporation and those of the Company from the date of the acquisition to December 31, 2002.

The Company is engaged primarily in the exploration for and development and production of petroleum and natural gas in Western Canada.

2.SIGNIFICANT ACCOUNTING POLICIES

a)Basis of Presentation

The consolidated financial statements include the accounts of Great Northern Exploration Ltd. (the “Company”) and its wholly-owned subsidiaries.

The Company’s financial statements have been prepared in accordance with Canadian generally accepted accounting principles and reflect the following policies:

b)Petroleum and Natural Gas Operations

I)CAPITALIZED COSTS

The Company follows the full cost method of accounting for petroleum and natural gas operations whereby all costs of exploring for and developing oil and gas properties and related reserves are capitalized into a single Canadian cost center. Costs include land acquisition costs, geological and geophysical expenditures, costs of drilling both productive and non-productive wells, well equipment and certain other overhead expenditures related to exploration.

Gains or losses on the sale or disposition of oil and gas properties are not ordinarily recognized except under circumstances which result in a significant revision of depletion rates.

II)DEPLETION AND DEPRECIATION

Petroleum and natural gas properties and related equipment, excluding undeveloped properties, are depleted and depreciated using the unit-of-production method based on estimated gross proved reserves. For purposes of this calculation, petroleum and natural gas reserves are converted at the energy equivalent conversion rate of six thousand cubic feet of natural gas to one barrel of crude oil. In determining its depletion base, the Company includes estimated future costs to be incurred in developing proved reserves and excludes salvage values and the cost of unproved properties. Costs of acquiring and evaluating unproved properties are excluded from the depletion base until it is determined whether proved reserves are attributable to the properties or impairment occurs.

III)CEILING TEST

In applying the full-cost method, the Company calculates a “ceiling test” to capitalized costs to ensure that such costs do not exceed future net revenues from estimated production of proven reserves, using prices and costs in effect at the Company’s year end, less administrative, financing, site restoration and abandonment, and income tax expenses, plus the costs of unproven properties. Any reduction in value as a result of the ceiling test is charged to operations as an element of depletion and depreciation expense. Undeveloped land is evaluated for impairment at each balance sheet date.

c)Joint Ventures

Substantially all of the Company’s exploration and development activities are conducted jointly with others and, accordingly, the financial statements reflect only the Company’s proportionate interest in such activities.

d)Flow-through Shares

The Company from time to time issues flow-through shares. Under these financing agreements, shares are issued at a fixed price with the resultant proceeds used to fund exploration and development work within a defined time period. The exploration and development expenditures funded by flow-through arrangements are renounced to investors in accordance with the appropriate tax legislation. A future tax liability is recorded and share capital is reduced by the estimated tax benefits transferred to shareholders.

e)Future Site Restoration and Abandonment Costs

Estimated future costs relating to site restoration and abandonment of petroleum and natural gas properties and related facilities are accrued on a unit of production basis over the estimated life of the proved reserves. Costs are based on engineering estimates, net of expected recoveries, based upon current prices and in accordance with current legislation, technology and industry standards.

f)Future Income Taxes

Income taxes are calculated using the liability method of tax allocation. Temporary differences arising from the difference between the tax basis of an asset or liability and its carrying amount on the balance sheet are used to calculate future income tax liabilities or assets. The effect on future income tax liabilities or assets of a change in tax rates is recognized in net income in the period in which the change occurs.

g)Stock-Based Compensation Plan

The Company has a stock-based compensation plan which is described in note 9. As of January 1, 2003, the Company adopted a new accounting standard on stock-based compensation. Stock option expense is recorded as general and administrative expense for all options granted on or after January 1, 2003, with a corresponding increase recorded to contributed surplus. The expense related to options issued during 2002 is disclosed as proforma information in note 9.

The fair value of options granted are estimated at the date of the grant using the Black-Scholes valuation model. Upon the exercise of the stock options, consideration paid by employees or directors together with the amount previously recognized in contributed surplus, is credited to share capital.

h)Per Share Amounts

Per share amounts are calculated on the basis of the weighted average number of common shares outstanding during the period.

The treasury stock method of calculating diluted per share amounts is used whereby any proceeds from the exercise of stock options or other dilutive instruments are assumed to be used to purchase common shares at the average market price during the period.

i)Revenue Recognition

Petroleum and natural as sales are recognized as revenue at the time the respective commodities are delivered to purchasers.

j)Financial Instruments

Settlement of crude oil and natural gas swap agreements, which have been arranged as a hedge against commodity price, are reflected in revenues at the time of sale of the related hedged production.

k)Measurement Uncertainty

The amount recorded for depletion and depreciation of property and equipment, the provision for site restoration costs and the ceiling test calculation are based upon estimates of gross proved reserves, production rates, crude oil and natural gas prices, future costs and other relevant assumptions. By their nature, these estimates are subject to measurement uncertainty, and the impact on the financial statements of future periods could be material.

3.CHANGE IN ACCOUNTING POLICY

Stock-Based Compensation Plan

In September 2003, the Canadian Institute of Chartered Accountants (“CICA”) amended Handbook Section 3870 - “Stock-based Compensation and Other Stock-based Payments”. Pursuant to new transitional rules approved by the CICA, the Company early adopted the amended standard on a prospective basis and now records stock-based compensation expense in the Consolidated Statement of Operations for all common share options granted to employees and directors on or after January 1, 2003. As a result of adopting this amended standard, net earnings for the year ended December 31, 2003 decreased by $136 thousand and contributed surplus increased by an equal amount.

Common share options granted prior to January 1, 2003 do not result in a compensation expense and the Company continues to disclose the proforma earnings impact of related stock-based compensation expense for these options (note 9).

4.BUSINESS COMBINATION

On July 10, 2002, the business transaction between Ascot and Great Northern was formally approved. This reverse takeover by Great Northern of Ascot resulted in Ascot issuing 6.5 common shares for each 1 share of Great Northern in which there were 14,052,000 Great Northern common shares issued and outstanding. Total shares issued pursuant to the business transaction were 91,338,000 or 18,267,600 common shares after the above mentioned share consolidation.

The Company acquired all of the shares of Great Northern and has accounted for the transaction as an acquisition of the

Company by Great Northern.

	$
Net assets acquired
Property and equipment	20,573
Working capital	626
Future income tax asset	3,215
Long-term debt	(13,995	)
Transaction costs	(2,167	)
Purchase price - common share equity value	8,252

5.PROPERTY, PLANT AND EQUIPMENT

		Accumulated
		Depletion and	Net
2003	Cost	Depreciation	Book Value
	$	$	$
Petroleum and natural gas properties	134,644	14,219	120,425
Office equipment	88	22	66
	134,732	14,241	120,491

		Accumulated
		Depletion and	Net
2002	Cost	Depreciation	Book Value
	$	$	$
Petroleum and natural gas properties	37,457	2,702	34,755
Office equipment	47	13	34
	37,504	2,715	34,789

The Company has capitalized, as part of petroleum and natural gas properties, indirect exploration overhead relating to property acquisition, exploration and development activities of $553 thousand for the year ended December 31, 2003 (2002 - $147 thousand).

Undeveloped land costs of $9.4 million (2002 - $6.0 million) have been excluded from the amount subject to depletion and depreciation.

6.CREDIT FACILITIES

	2003	2002
	$	$
Prime rate advances	8,555	107
Bankers’ acceptances	30,000	5,000
	38,555	5,107

Subsequent to December 31, 2003, the Company amended its demand revolving credit facility to a maximum of $70 million. The credit facility bears interest at the lenders’ prime rate or at the Bankers’ Acceptance rate plus a stamping fee of 1.25%. The $70 million borrowing base is subject to a semi-annual and annual review by the lender. The credit facility is secured by a first fixed and floating charge debenture in the amount of $100 million covering all the Company’s assets.

7.SITE RESTORATION AND ABANDONMENTS

At December 31, 2003, total future removal and site restoration costs to be accrued over the life of the remaining proved reserves were estimated, net of recoveries, at $7.7 million (2002 - $2.1 million) of which $630 thousand (2002 - $136 thousand) has been accrued. This estimate is subject to change based on amendments to environmental laws and as new information concerning operations becomes available.

8.SHARE CAPITAL

a)Authorized

Unlimited number of common voting shares

Unlimited number of preferred shares, issuable in series

b)Issued

	Number of
	Shares	Amount
		$
Balance, December 31, 2001	17,065,100	11,890
Issued for cash	1,202,500	550
Acquisition of Ascot Energy Resources Ltd.	10,726,182	8,252
Exercise of stock options	110,500	85
Flow-through shares issued	1,379,400	4,000
Tax benefit renounced to shareholders	—	(1,705	)
Share issue costs, net of tax effect	—	(206	)
Balance, December 31, 2002	30,483,682	22,866
Issued on private placement	4,000,000	13,800
Issued on private placement	3,750,000	15,000
Exercise of stock options	125,000	142
Flow-through shares issued	1,100,000	6,050
Tax benefit renounced to shareholders	—	(2,456	)
Share issue costs, net of future tax	—	(1,121	)
Balance, December 31, 2003	39,458,682	54,281

In December 2003, 1,100,000 flow-through common shares were issued at a price of $5.50 per share for gross proceeds of $6.1 million. Under the terms of the flow-through agreement, the Company is required to expend $6.1 million on qualifying crude oil and natural gas expenditures prior to December 31, 2004. As at December 31, 2003, the Company had incurred qualifying expenditures in the amount of $0.6 million.

9.STOCK-BASED COMPENSATION

The Company has implemented a Stock Option Plan for directors and employees. Options under the Plan vest over a four year period with 25% vesting upon each anniversary date of the grant. As of December 31, 2003, there were 3,001,250 common shares reserved for issuance to eligible participants. At December 31, 2003, 3,405,875 (2002 - 2,474,875) options with exercise prices between $0.77 and $4.55 were outstanding and exercisable at various dates to December 11, 2008. The exercise price of each option equals the market price of the Company’s common shares on the date of the grant.

The following tables summarize the information about the share options as at December 31:

			2003				2002
			Weighted				Weighted
			average				average
			exercise				exercise
Fixed Options	Shares		price		Shares		price
Outstanding at beginning of year	2,474,875		$	1.36	1,397,500		$	0.77
Granted	1,268,875		$	3.80	1,200,875		$	1.99
Exercised	(125,000	)	$	1.15	(110,500	)	$	0.77
Cancelled	(212,875	)	$	2.23	(13,000	)	$	0.77
Outstanding at end of year	3,405,875		$	2.22	2,474,875		$	1.36
Options exercisable at year end	637,000		$	1.01	232,375		$	0.77

	Options outstanding				Options exercisable
	Number	Weighted			Number
	outstanding	average	Weighted		exercisable	Weighted
	at	remaining	average		at	average
	December 31,	contractual	exercise		December 31,	exercise
Range of exercise prices	2003	life (years)	price		2003	price
$0.77 - $1.50	1,192,750	7.9	$	0.77	497,250	$	0.77
$1.85 - $2.20	975,225	8.5	$	2.01	139,750	$	1.87
$2.63 - $3.95	564,275	9.1	$	3.27	—	$	—
$4.00 - $4.55	673,625	8.8	$	4.22	—	$	—
	3,405,875		$	2.22	637,000	$	1.01

For options granted to employees from January 1, 2002 to December 31, 2002, the Company follows the settlement method of accounting. Since all options were granted with an exercise price equal to the market price at the date of the grant, no compensation cost has been charged to income at the time of the 2002 option grants. Had compensation cost for the Company’s stock options been determined based on the fair market value at the grant dates of the awards, the Company’s net earnings and net earnings per share for the year ended December 31, 2002 would have been the pro forma amounts indicated following:

	2003	2002
	$	$
Net earnings
As reported	10,505	1,794
Pro forma	10,345	1,750
Net earnings per common share - basic
As reported	0.30	0.08
Pro forma	0.30	0.08
Net earnings per common share - diluted
As reported	0.29	0.07
Pro forma	0.28	0.07

For options granted after January 1, 2003, the Company follows the fair value method (note 3).

The weighted average fair market value of options granted in the year ended December 31, 2003 are $1.39 per option. The fair market of each option granted was estimated on the date of grant using the Modified Black-Scholes option-pricing model with the following assumptions:

	2003			2002
Risk-free interest rate	4.50		%	4.00		%
Estimated hold period prior to exercise (years)	5			4
Volatility in the price of the Company’s common shares	38		%	44		%
Dividend per share	$	0.00		$	0.00

10. PER SHARE AMOUNTS

Basic per share amounts are calculated using the weighted average number of shares outstanding during the year.

In the calculation of diluted per share amounts, options under the stock option plan are assumed to have been converted or exercised on the later of the beginning of the year and the date granted. The treasury stock method assumes that proceeds received from the exercise of in-the-money stock options are used to repurchase common shares at the average market rate.

	2003	2002
Weighted average shares outstanding (thousands)
Basic	34,865	23,024
Diluted	36,318	24,016

11. INCOME TAXES

The provision for income tax differs from the result which would be obtained by applying the combined Federal and Provincial statutory income tax rates to income before taxes. This difference results from the following:

	2003		2002
	$		$
Earnings (loss) before taxes	17,216		3,573
Statutory income tax rate	40.6	%	42.8	%
Expected income tax	6,990		1,529
Increase (decrease) resulting from:
Non-deductible crown charges	2,769		760
Resource allowance	(3,044	)	(597	)
Statutory rate adjustment	(310	)	(224	)
Other	—		23
Change in valuation allowance	—		172
Provision for taxes	6,405		1,663

The future income tax liability is comprised of temporary differences related to the following:

	2003		2002
	$		$
Property and equipment	(9,572	)	(928	)
Statutory tax rate adjustment	339		286
Future site restoration	201		44
Share issue	759		313
Non-capital losses	946		827
Valuation allowance	(770	)	(542	)
Future income taxes	8,097		—

12. SUPPLEMENTAL CASH FLOW INFORMATION

Changes in non-cash working capital:

	2003		2002
	$		$
Accounts receivable	(7,264	)	(3,187	)
Prepaid expenses	(227	)	509
Accounts payable	9,098		6,373
Changes in non-cash working capital	1,607		3,695
These changes relate to the following activities:
Operating activities	3,717		(706	)
Investing activities	(2,110	)	4,401
	1,607		3,695

Amounts paid during the year relating to interest expense and capital taxes are as follows:

	2003	2002
	$	$
Interest paid in the year	1,204	220
Capital taxes paid in the year	210	—
	1,414	220

13. FINANCIAL INSTRUMENTS

The Company is exposed to fluctuations in commodity prices, interest rates and Canada/U.S. exchange rates. The Company, when appropriate, utilizes financial instruments to manage its exposure to these risks.

a) Commodity Price Risk Management

Financial instruments are entered into by the Company to protect the downside prices received on the sale of a portion of its crude oil and natural gas production. The agreements entered into are forward transactions providing the Company with a range of fixed prices on the commodities sold. Petroleum and natural gas revenue for the year ended December 31, 2003 include losses of $1.7 million (2002 - $133 thousand loss) on those transactions.

The following contracts were outstanding as at December 31, 2003:

Commodity	Type	Term	Volume	Price	Index
Natural gas	Fixed	January 2004 - March 2004	6,000 GJ’s/d	$6.57/GJ	AECO
Crude oil	Fixed	January 2004 - March 2004	600 bbls/d	US $28.70/bbl	WTI
Crude oil	Fixed	April 2004 - June 2004	600 bbls/d	US $27.50/bbl	WTI
Crude oil	Fixed	July 2004 - September 2004	400 bbls/d	US $28.25/bbl	WTI
Crude oil	Fixed	October 2004 - December 2004	300 bbls/d	US $27.30/bbl	WTI

The estimated fair value at December 31, 2003 of these transactions, had the contracts been settled at that time, would be a loss of $487 thousand.

b) Credit Risk Management

The Company has estimated that the fair value of its financial instruments, which include accounts receivable, accounts payable and accrued liabilities, and long-term debt, approximate their carrying values.

The majority of the Company’s accounts receivable are with other companies in the oil and gas industry and are subject to normal industry credit risk.

14. SUBSEQUENT EVENTS

On January 22, 2004, the Company acquired crude oil and natural gas assets that produce approximately 580 barrels of oil equivalent per day of production for approximately $23 million. The acquisition included working interests in existing Company operated producing properties, gas processing facilities, infrastructure and undeveloped land.

As a result of completion of the above mentioned acquisition, the Company renegotiated its credit facilities as described in note 6.

On February 2, 2004, the Company issued 4,250,000 common shares at a price of $4.50 per share for gross proceeds of $19.1 million.

GREAT NORTHERN EXPLORATION LTD.

CONSOLIDATED BALANCE SHEET

	March 31,	December 31,
	2004	2003
	(unaudited)	(Restated – note 3)
	$	$
ASSETS
Current assets
Accounts receivable	11,473,000	12,456,000
Prepaid expenses	546,000	609,000
	12,019,000	13,065,000
Property and equipment (note 4)	160,448,000	125,718,000
	172,467,000	138,783,000
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities
Accounts payable	21,916,000	19,754,000
Bank debt (note 5)	45,596,000	38,555,000
	67,512,000	58,309,000
Future income taxes	9,641,000	8,097,000
Asset retirement obligations (note 8)	7,866,000	6,923,000
	85,019,000	73,329,000
Shareholders’ equity
Share capital (note 6)	72,859,000	54,281,000
Contributed surplus	251,000	136,000
Retained earnings	14,338,000	11,037,000
	87,448,000	65,454,000
Subsequent event (note 10)	172,467,000	138,783,000

(See accompanying notes to the consolidated financial statements)

GREAT NORTHERN EXPLORATION LTD.

CONSOLIDATED STATEMENT OF OPERATIONS AND RETAINED EARNINGS

Three months ended March 31,	2004			2003
				(Restated – note 3)
	(unaudited)
	$			$
Revenue
Petroleum and natural gas sales	19,529,000			8,895,000
Royalties, net	(3,909,000		)	(2,019,000		)
	15,620,000			6,876,000
Expenses
Operating	3,892,000			1,367,000
General and administrative	304,000			324,000
Financial charges	538,000			51,000
Depletion, depreciation and accretion (note 8)	5,591,000			1,531,000
	10,325,000			3,273,000
Earnings before taxes	5,295,000			3,603,000
Capital taxes	94,000			29,000
Future income taxes	1,900,000			1,402,000
	1,994,000			1,431,000
Net earnings	3,301,000			2,172,000
Retained earnings, beginning of period	12,103,000			1,598,000
Retroactive application of change in accounting policy (note 3(b))	(1,066,000		)	(390,000		)
Retained earnings, end of period	14,338,000			3,380,000
Net earnings per share
Basic	$	0.08		$	0.07
Diluted	$	0.08		$	0.07

(See accompanying notes to the consolidated financial statements)

GREAT NORTHERN EXPLORATION LTD.

CONSOLIDATED STATEMENT OF CASH FLOW

Three months ended March 31,	2004		2003
			(Restated – note 3)
	(unaudited)
	$		$
Cash flow related to the following activities
Operating
Net earnings for the period	3,301,000		2,337,000
Items not affecting cash:
Depletion, depreciation and accretion	5,591,000		1,366,000
Future income taxes	1,900,000		1,402,000
Stock-based compensation	115,000		—
Cash flow from operations	10,907,000		5,105,000
Changes in non-cash operating working capital items	520,000		1,584,000
	11,427,000		6,689,000
Financing
Change in bank debt	7,041,000		3,971,000
Share issuance, net	18,222,000		32,000
	25,263,000		4,003,000
Cash available for investment activities	36,690,000		10,692,000
Investing
Property and equipment additions	(39,290,000	)	(8,974,000	)
Site restoration expenditures	(88,000	)	(41,000	)
Changes in non-cash investing working capital items	2,688,000		(1,677,000	)
	(36,690,000	)	(10,692,000	)
Change in cash	—		—
Cash, beginning of period	—		—
Cash, end of period	—		—

(See accompanying notes to the consolidated financial statements)

GREAT NORTHERN EXPLORATION LTD.

SELECTED NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

THREE MONTHS ENDED MARCH 31, 2004

(unaudited)

(tabular amounts in thousands of dollars, unless otherwise stated)

1.NATURE OF OPERATIONS

The Company is engaged primarily in the exploration for and development and production of petroleum and natural gas in Western Canada.

2.SIGNIFICANT ACCOUNTING POLICIES

a)Basis of Presentation

The consolidated financial statements include the accounts of Great Northern Exploration Ltd. (the “Company”) and its wholly-owned subsidiaries.

The interim consolidated financial statements and the notes thereto of the Company have been prepared following the same accounting policies and methods of computation as the audited consolidated financial statements of the Company as at December 31, 2003 except as disclosed in note 3.  These interim consolidated financial statements should be read in conjunction with the Company’s audited consolidated financial statements and notes thereto for the year ended December 31, 2003.

3.CHANGE IN ACCOUNTING POLICY

a)Full Cost Accounting Guideline

In January 2004, the Company adopted Accounting Guideline 16 “Oil and Gas Accounting – Full Cost”, the new guideline issued by the Canadian Institute of Chartered Accountants (“CICA”) which replaces Accounting Guideline 5, “Full Cost Accounting in the Oil & Gas Industry”.

The recoverability of a cost center is tested by comparing the carrying value of the cost center to the sum of the undiscounted cash flows expected from the cost center’s use and eventual disposition.  If the carrying value is unrecoverable the cost center is written down to its fair value using the expected present value approach.  This approach incorporates risks and uncertainties in the expected future cash flows which are discounted using a credit adjusted risk free rate.

Under Accounting Guideline 5, future net revenues for ceiling test purposes were based on proved reserves and were not discounted.  Estimated future general and administrative costs and financing charges associated with future net revenues were deducted in arriving at the “ceiling”.

There were no charges to net income, property, plant and equipment or any other reported amounts in the consolidated financial statements as a result of adopting this guideline.

b)Asset Retirement Obligation

In January 2004, the Company adopted CICA Handbook Section 3110, “Asset Retirement Obligations”.  This change in accounting policy has been applied retroactively with restatement of prior periods presented for comparative purposes.

The Company recognizes the fair value of its asset retirement obligation (“ARO”) in the period in which it is incurred and when a reasonable estimate of fair value can be made.  The fair value of the estimated ARO is recorded as a long-term liability, with a corresponding increase in the carrying amount of the related asset.  The capitalized amount is depleted on a unit-of-production basis over the life of the reserves.  The liability amount is increased each reporting period due to the passage of time and the amount of accretion is charged to earnings in the period.  Revisions to the estimated timing of cash flows or to the original estimated undiscounted cost would also result in an increase or decrease to the ARO.  Actual costs incurred upon settlement of the ARO are charged against the ARO to the extent of the liability recorded.  Any difference between the actual costs incurred upon settlement of the ARO and the recorded liability is recognized as a gain or loss in the Company’s earnings in the period in which the settlement occurs.

Previously, the Company recognized a provision for site restoration and abandonment costs calculated on the unit-of-production method over the life of the petroleum and natural gas properties based on total estimated proved reserves and the estimated future liability.

This change in accounting policy has been applied retroactively with restatement of prior periods presented for comparative purposes as follows:

Consolidated Balance Sheet as at December 31, 2003

	As Reported	Change		As Restated
	$	$		$
Assets
Property and equipment	120,491	5,227		125,718
Liabilities and shareholders’ equity
Future site restoration	630	(630	)	—
Asset retirement obligations	—	6,923		6,923
Retained earnings	12,103	(1,066	)	11,037

Consolidated Statement of Operations and Retained Earnings for the Three Months ended March 31, 2003

	As Reported	Change		As Restated
	$	$		$
Depletion and depreciation	1,366	90		1,456
Accretion	—	75		75
Net earnings	2,337	(165	)	2,172

There was no impact on the Company’s cash flow as a result of adopting this new policy.  See note 7 for additional information on the asset retirement obligation and the impact on the consolidated financial statements.

4.PROPERTY AND EQUIPMENT

	March 31, 2004
		Accumulated
		Depletion and	Net
	Cost	Depreciation	Book Value
	$	$	$
Petroleum and natural gas properties	180,938	20,549	160,389
Office equipment	92	33	59
	181,030	20,582	160,448

	December 31, 2003
		Accumulated
		Depletion and	Net
	Cost	Depreciation	Book Value
	$	$	$
Petroleum and natural gas properties	140,773	15,121	125,652
Office equipment	88	22	66
	140,861	15,143	125,718

The Company has capitalized, as part of petroleum and natural gas properties, indirect exploration overhead relating to property acquisition, exploration and development activities of $115 thousand for the three months ended March 31, 2004 (year ended December 31, 2003 - $553 thousand).

At March 31, 2004, undeveloped land costs of $9.4 million (December 31, 2003 - $9.4 million) have been excluded from the amount subject to depletion and depreciation.

5.CREDIT FACILITIES

	March 31,	December 31,
	2004	2003
	$	$
Prime rate advances	5,596	8,555
Bankers’ acceptances	40,000	30,000
	45,596	38,555

The Company has a demand revolving credit facility to a maximum of $70 million.  The credit facility bears interest at the lenders’ prime rate or at the Bankers’ Acceptance rate plus a stamping fee of 1.25%.  The $70 million borrowing base is subject to a semi-annual and annual review by the lender.  The credit facility is secured by a first fixed and floating charge debenture in the amount of $100 million covering all the Company’s assets.

6.SHARE CAPITAL

a)Authorized

Unlimited number of common voting shares

Unlimited number of preferred shares, issuable in series

b)Issued

	Number of
	Shares	Amount
		$
Balance, December 31, 2002	30,483,682	22,866
Issued on private placement	4,000,000	13,800
Issued on private placement	3,750,000	15,000
Exercise of stock options	125,000	142
Flow-through shares issued	1,100,000	6,050
Tax benefit renounced to shareholders	—	(2,456	)
Share issue costs, net of future tax	—	(1,121	)
Balance, December 31, 2003	39,458,682	54,281
Issued on private placement	4,250,000	19,125
Exercise of stock options	6,250	12
Share issue costs, net of future tax	—	(559	)
Balance, March 31, 2004	43,714,932	72,859

In December 2003, 1,100,000 flow-through common shares were issued at a price of $5.50 per share for gross proceeds of $6.1 million.  Under the terms of the flow-through agreement, the Company is required to expend $6.1 million on qualifying crude oil and natural gas expenditures prior to December 31, 2004.

Basic per share amounts are calculated using the weighted average number of shares outstanding during the year.

The reconciling items between the basic and diluted average common shares outstanding are outstanding stock options.

	Three months ended
	March 31,
	2004	2003
Weighted average shares outstanding (thousands)
Basic	42,173	30,499
Diluted	43,876	31,637

7.STOCK-BASED COMPENSATION

The Company has implemented a Stock Option Plan for directors and employees.  Options under the Plan vest over a four year period with 25% vesting upon each anniversary date of the grant.  As of March 31, 2004, there were 2,995,000 common shares reserved for issuance to eligible participants.  At March 31, 2004, 3,423,375 (December 31, 2003 - 3,405,875) options with exercise prices between $0.77 and $4.60 were outstanding and exercisable at various dates to December 11, 2008.  On April 6, 2004, 435,375 conditionally granted share options with an exercise price of $4.25 were cancelled.  The exercise price of each option equals the market price of the Company’s common shares on the date of the grant.

The following tables summarize the information about the share options:

	Three months ended					Year ended
	March 31,					December 31,
	2004					2003
			Weighted					Weighted
			average					average
			exercise					exercise
Fixed Options	Shares		price			Shares		price
Outstanding at beginning of period	3,405,875		$	2.22		2,474,875		$	1.36
Granted	93,750		$	4.33		1,268,875		$	3.80
Exercised	(6,250	)	$	2.00		(125,000	)	$	1.15
Cancelled	(70,000	)	$		4.00	(212,875	)	$		2.23
Outstanding at end of period	3,423,375		$		2.24	3,405,875		$		2.22
Options exercisable at period end	682,750		$	1.12		637,000		$	1.01

Options outstanding						Options exercisable
	Number	Weighted				Number
	outstanding	average	Weighted			exercisable	Weighted
	at	remaining	average			at	average
Range of	March 31,	contractual	exercise			March 31,	exercise
exercise prices	2004	life (years)	price			2004	price
$0.77 - $1.50	1,192,750	7.7	$	0.77		500,500	$	0.77
$1.85 - $2.20	968,975	8.3	$	2.01		133,500	$	1.86
$2.63 - $3.95	564,275	8.7	$	3.27		48,750	$	2.66
$4.00 - $4.60	697,375	8.6	$		4.26	—	$		—
	3,423,375		$	2.24		682,750	$	1.12

For options granted to employees from January 1, 2002 to December 31, 2002, the Company follows the settlement method of accounting.  Since all options were granted with an exercise price equal to the market price at the date of the grant, no compensation cost has been charged to income at the time of the 2002 option grants.  Had compensation cost for the Company’s stock options been determined based on the fair market value at the grant dates of the awards, the Company’s net earnings and net earnings per share for the year ended December 31, 2002 would have been the pro forma amounts indicated below:

	2004		2003
			(Restated – note 3)
Net earnings
As reported	$	3,301	$	2,172
Pro forma	$	3,260	$	2,146
Net earnings per common share – basic
As reported	$	0.08	$	0.07
Pro forma	$	0.08	$	0.07
Net earnings per common share – diluted
As reported	$	0.08	$	0.07
Pro forma	$	0.07	$	0.07

For options granted after January 1, 2003, the Company follows the fair value method.

The weighted average fair market value of options granted in the year ended March 31, 2004 is $1.08 per option.  The fair market of each option granted was estimated on the date of grant using the Modified Black-Scholes option-pricing model with the following assumptions:

	2004			2003
Risk-free interest rate	4.50		%	4.50		%
Estimated hold period prior to exercise (years)	5			5
Volatility in the price of the Company’s common shares	15		%	38		%
Dividend per share	$	0.00		$	0.00

8.ASSET RETIREMENT OBLIGATIONS

The Company’s asset retirement obligations are based on the Company’s net ownership in wells and facilities and management’s estimate of costs to abandon and reclaim those wells and facilities as well as an estimate of the future timing of the costs to be incurred.

The Company has estimated the present value of its total asset retirement obligations to be $7.9 million at March 31, 2004 based on a total future liability of $21.1 million.  Payments to settle asset retirement obligations occur over the operating lives of the underlying assets, estimated to be from zero to 50 years, with the majority of costs incurred between 2010 and 2026.  Estimated cash flows have been discounted at the Company’s credit-adjusted risk free rate of 8 percent and an inflation rate of 2.0 percent.

	Three months ended				Year ended
	March 31,				December 31,
	2004		2003		2003
Asset retirement obligations, beginning of period	6,923		3,155		3,155
Liabilities incurred during period	879		699		3,626
Liabilities settled during period	(88	)	(41	)	(348	)
Accretion	152		75		490
Asset retirement obligations, end of period	7,866		3,888		6,923

9.FINANCIAL INSTRUMENTS

The Company is exposed to fluctuations in commodity prices, interest rates and Canada/U.S. exchange rates.  The Company, when appropriate, utilizes financial instruments to manage its exposure to these risks.

a)Commodity Price Risk Management

Financial instruments are entered into by the Company to protect the downside prices received on the sale of a portion of its crude oil and natural gas production.  The agreements entered into are forward transactions providing the Company with a range of fixed prices on the commodities sold.  Petroleum and natural gas revenue for the three months ended March 31, 2004 include losses of $0.2 million (2003 - $1.3 million loss) on those transactions.

The following contracts were outstanding as at March 31, 2004:

Commodity	Type	Term	Volume	Price	Index
Natural gas	Fixed	April 2004 – September 2004	4,000 GJ’s/d	$5.88/GJ	AECO
Natural gas	Fixed	October 2004 – December 2004	1,333 GJ’s/d	$5.88/GJ	AECO
Crude oil	Fixed	April 2004 – June 2004	600 bbls/d	US $27.50/bbl	WTI
Crude oil	Fixed	July 2004 – September 2004	600 bbls/d	US $29.17/bbl	WTI
Crude oil	Fixed	October 2004 – December 2004	600 bbls/d	US $28.70/bbl	WTI

The estimated fair value at March 31, 2004 of these transactions, had the contracts been settled at that time, would be a loss of $1.5 million.

10.SUBSEQUENT EVENT

Recent APF Offer

On April 7, 2004, APF Energy Inc., APF Energy Trust (collectively, the “Offeror”) and Great Northern announced that the Offeror had agreed to make an offer to acquire all of the outstanding common shares of Great Northern Exploration Ltd. and all common shares which may become outstanding on the exercise of the outstanding stock options, on the basis of, at the election of the holder, either:

a)$5.05 cash for each Common Share; provided that not more than $55.2 million in cash shall be payable in the aggregate under the Offer, with the balance being paid in trust units (“APF Units”) of APF Energy Trust at an exchange rate of 0.414614 Trust Units per Common Share (the “Cash Alternative”);

b)0.414614 Trust Units for each GNEL Share (the “Trust Unit Alternative”); or

subject to the stated maximum, any combination thereof (the “Offer”) as more particularly described and upon the terms and subject to the conditions set forth in the “Offering Circular” dated April 26, 2004.

The Offer is scheduled to expire on June 1, 2004.

PricewaterhouseCoopers LLP

Chartered Accountants

111 5th Avenue SW, Suite 3100

Calgary, Alberta

Canada T2P 5L3

Telephone +1 (403) 509 7500

Facsimile +1 (403) 781 1825

Compilation Report

To the Trustee of APF Energy Trust and to the Directors of APF Energy Inc.

We have read the accompanying unaudited pro forma consolidated balance sheet as at December 31, 2004, as well as the consolidated statement of operations of APF Energy Trust (the “Trust”) for the year ended December 31, 2004, and have performed the following procedures.

1.Compared the figures in the column captioned “APF Energy Trust” to the audited financial statements of the Trust for the year ended December 31, 2004, and found them to be in agreement.

2.Compared the figures in the column captioned “Great Northern Exploration Ltd.” to the unaudited financial statements of the applicable entity for the five months ended May 31, 2004 and found them to be in agreement.

3.Compared the oil and gas revenue, royalties and operating costs in the column captioned “Rockyview Adjustments” to the accounting records for the assets to be sold by the Trust, as prepared by management of the Trust, and found them to be in agreement.

4.Made enquiries of certain officials of the Trust who have responsibility for financial and accounting matters about:

(a)the basis for determination of the pro forma adjustments; and

(b)whether the pro forma financial statements comply as to form in all material respects with Securities Acts of the various Provinces of Canada (the “Acts”).

The officials:

(a)described to us the basis for determination of the pro forma adjustments, and

(b)stated that the pro forma statements comply as to form in all material respects with the Acts.

5.Read the notes to the pro forma statements, and found them to be consistent with the basis described to us for determination of the pro forma adjustments.

PricewaterhouseCoopers refers to the Canadian firm of PricewaterhouseCoopers LLP and the other member firms of PricewaterhouseCoopers International Limited, each of which is a separate and independent legal entity.

6.Recalculated the application of the pro forma adjustments to the aggregate of the amounts in the column captioned “Pro Forma APF Energy Trust”, for December 31, 2004, as well as the year ended December 31, 2004 and found the amounts to be arithmetically correct.

A pro forma financial statement is based on management assumptions and adjustments which are inherently subjective. The foregoing procedures are substantially less than either an audit or a review, the objective of which is the expression of assurance with respect to management’s assumptions, the pro forma adjustments, and the application of the adjustments to the historical financial information. Accordingly, we express no such assurance. The foregoing procedures would not necessarily reveal matters of significance to the pro forma financial statements, and we therefore make no representation about the sufficiency of the procedures for the purposes of a reader of such statements.

Chartered Accountants

May 11, 2005

Calgary, Alberta

2

APF ENERGY TRUST

Pro Forma Consolidated Statement of Operations

For the year ended December 31, 2004

(unaudited)

			Great Northern
	APF Energy Trust		Exploration five		Great Northern				Pro Forma
	12 months ended		months ended		Exploration		Rockyview		APF Energy
($000s except for per unit amounts)	December 31, 2004		May 31, 2004		Adjustments		Adjustments		Trust
					(note 3)		(note 4)
REVENUE
Oil and gas	253,213		35,607		—		(15,988	)(h)	272,832
Realized derivative loss - net	(16,329	)	(935	)	—		—		(17,264	)
Unrealized derivative loss - net	223		—		—		—		223
Royalties expense, net of ARTC	(47,710	)	(7,042	)	(208	)(v)	3,555	(h)	(51,405	)
Transportation	(5,245	)	—		—		—		(5,245	)
	184,152		27,630		(208	)	(12,433	)	199,141
EXPENSES
Operating	51,788		7,857		—		(2,681	)(h)	56,964
General and administrative	10,635		3,932		—		—		14,567
Interest on long-term debt	5,405		811		1,366	(ii)	(1,223	)(b)	6,359
Convertible debenture interest and financing charges	5,263		—		—		(5,263	)(c)	—
Depletion, depreciation and accretion	85,997		9,577		5,272	(i)	(7,356	)(g)	93,490
Unit-based compensation expense	(877	)	192		—		270	(e)	(415	)
Capital and other taxes	3,321		—		296	(iv)	(88	)(d)	3,529
	161,532		22,369		6,934		(16,341	)	174,494
Income / (loss) before income taxes	22,620		5,261		(7,142	)	3,908		24,647
Provision for income taxes (recovery)
Current			200		(200	)(iv)	—		—
Future	(27,016	)	2,041		(2,607	)(iii)	1,426	(a)	(26,156	)
Net income / (loss) for period	49,636		3,020		(4,335	)	2,482		50,803
Net income per unit - basic and diluted	1.02								0.75

See accompanying notes to consolidated financial statements

APF ENERGY TRUST

Pro Forma Consolidated Balance Sheet

As at December 31, 2004

(Unaudited)

					Pro Forma
			Rockyview		APF Energy
($000s except for per unit amounts)	APF Energy Trust		Adjustments		Trust
			(note 2)
ASSETS
Current assets
Cash	567		—		567
Accounts receivable	42,200		—		42,200
Derivative asset	3,313		—		3,313
Other current assets	7,162		(1,543	)(d)	5,619
	53,242		(1,543	)	51,699
Asset retirement fund	3,271		—		3,271
Goodwill	118,478		—		118,478
Property, plant and equipment	687,179		(43,833	)(a)	643,346
	862,170		(45,376	)	816,794
LIABILITIES
Current liabilities
Accounts payable and accrued liabilities	52,677		—		52,677
Derivative liabilities	3,141		—		3,141
Distribution payable	9,415		—		9,415
	65,233		—		65,233
Future income taxes	86,711		2,541	(a)	89,252
Long-term debt	169,000		(24,455	)(c)	144,545
Convertible debentures	47,697		(47,697	)(d)	—
Asset retirement obligation	30,993		(795	)(a)	30,198
Derivative liabilities	335		—		335
	399,969		(70,406	)	329,563
UNITHOLDERS’ EQUITY
Unitholders’ investment account	610,194		(45,579	)(a)	636,662
			47,697	(d)
			289	(c)
			24,455	(c)
			1,149	(d)
			(1,543	)(b)
				(d)
Contributed surplus	289		270	(c)	—
			(559	)(c)
Accumulated earnings	126,862				126,862
Accumulated distributions	(276,293	)	—		(276,293	)
Convertible debenture conversion feature	1,149		(1,149	)(d)	—
	462,201		25,030		487,231
	862,170		(45,376	)	816,794

See accompanying notes to consolidated financial statements.

APF ENERGY TRUST

Notes to Pro Forma Consolidated Financial Statements

As at and for the year ended December 31, 2004

1.Basis of presentation:

The pro–forma consolidated financial statements of APF Energy Trust (the “APF Trust”), which owns a 99% interest in certain oil and gas royalties, have been prepared by management to give effect to the purchase of Great Northern Exploration Ltd. (“GNEL”) and to reflect the proposed arrangement (the “Arrangement”) relating to the creation of Rockyview Energy Inc (“Rockyview”), a public corporation concentrating on the exploration and development of oil and natural gas reserves.  GNEL was involved in oil and gas exploration, development and production in western Canada.  Pursuant to the Arrangement, APF Energy Inc (“APF Inc.”) will transfer interests in certain oil and natural properties (the “Rockyview Assets”) to Rockyview.  The arrangement is subject to regulatory, judicial and unitholder approval and is anticipated to be completed by June 15, 2005.  These pro-forma consolidated financial statements to not include the effects of the proposed combination with Starpoint Energy Trust (“Starpoint”).

The GNEL shares were purchased by APF Trust through a take-over bid, which closed June 4, 2004 (the “Acquisition”).  The pro-forma consolidated financial statements of operations gives effect to the Acquisition and the Arrangement as if they occurred January 1, 2004.

Accounting policies used in the preparation of the pro forma financial statements are in accordance with those disclosed in APF Trust’s audited consolidated financial statements as at December 31, 2004 and for the year then ended (collectively, the “APF historical financial statements”).  The pro forma statements have been prepared from information derived from and should be read in conjunction with the APF historical financial statements  In the opinion of management, the pro forma statements include all necessary adjustments for a fair presentation of the ongoing entity.

Under the Arrangement, interests in certain oil and natural gas properties, formally owned by APF Inc. will be transferred to Rockyview.  As the former APF Trust unitholders will be the controlling shareholder group of Rockyview, the assets and liabilities of Rockyview have been accounted for on a “continuity of interests” basis, and therefore no adjustment to carrying values of the assets and liabilities of APF Inc. transferred to Rockyview is required to account for the transaction.  The revenues and operating expenses transferred to Rockyview have been derived from the schedule of revenue and expenses for the properties transferred to Rockyview.

The Trust is an open–ended investment trust under the laws of the Province of Alberta.

The royalty interests (the “Royalty”) in producing oil and natural gas properties acquired from APF Inc. and APF Energy Limited Partnership (collectively “APF”) effectively transfer 99% of the economic interest in such properties to the Unitholders. The Royalty constitutes a royalty interest in the oil and natural gas properties owned by APF but does not confer ownership in the underlying resource properties. APF is permitted to borrow funds to finance the purchase of additional properties and tangibles, for capital expenditures or for other financial obligations or encumbrances in respect of the properties should the properties not generate sufficient income to repay debt. The Trust is entitled to 99% of the production and incidental revenues from the properties less all costs and expenses in respect of the properties, taxes in respect of the properties, general and administrative costs of APF and the Royalty and debt service charges (including principal repayments). The Trust is required to reimburse APF for Crown royalties and charges in respect of production allocable to the Royalty.

2.The pro-forma consolidated balance sheet gives effect to the following assumptions and adjustments:

(a)Under the Arrangement, the Rockyview Assets will be transferred to Rockyview based upon APF Inc’s carrying value. The carrying value of the Rockyview Assets was determined based on the portion of the total proven oil and natural gas reserves (discounted at 10 percent) as determined by independent reserve engineers for proved properties.  The associated asset retirement obligation of the Rockyview Assets was based upon APF Inc’s carrying value and estimated based on the Rockyview Assets transferred and assumptions as used in APF’s Trust’s consolidated financial statements.

	($000)
Oil and natural gas assets and equipment	37,146
Undeveloped land	5,180
Seismic	1,507
Future income tax asset	2,541
Total assets transferred	46,374
Asset retirement obligation	(795	)
Net assets transferred at carrying value	45,579

The above amounts are estimates, which were made by management in the preparation of the pro forma financial statements based on information available at the time.  Amendments may be made to these amounts as estimates are finalized;

(b)The future income tax on the pro forma consolidated balance sheet has been determined on the basis of the difference between the net book values of the assets and liabilities and the corresponding tax basis that will result in APF Inc. after the completion of the Arrangement. The increase in future income tax liability arises as a result of the assets transferred by APF Inc.  having a greater tax basis than the net book value;

(c)All options and rights including ones which have not vested will be exercisable as a result of the proposed combination with Starpoint; therefore, the unamortized fair value of APF options and rights has been expensed.  Contributed surplus has been reduced to reflect the assumed exercise of options and rights at January 1, 2004 for proceeds of $24.5 million.    Long term debt has been reduced to account for the proceeds that would be received from the exercise of these options and rights and applied against the outstanding principal;

(d)In order for the holders of the convertible debentures to benefit from the issue of Rockyview shares, it has been assumed that all outstanding convertible debentures will be converted; therefore, other current assets have been reduced to reflect the write-off of deferred financing costs related to the convertible debentures.   As a result of the conversion of the debentures, the value of the convertible debenture conversion feature has been transferred to unitholders’ investment.

3.Pro forma assumptions and adjustments to the statement of operations as a result of GNEL:

(i)The purchase price allocated to GNEL assets is amortized on a unit of production basis;

(ii)The interest for the change of bank debt related to the Acquisition has been recorded at 5% per annum with no deemed principal repayments;

(iii)Current taxes were adjusted to account for income taxes if the income from the Acquisition subject to the royalty calculation was in effect January 1, 2004.  The future income tax expense has been adjusted to reflect the impact on earnings of the transactions at an effective rate of 36.5%;

(iv)Saskatchewan surtax is applied to certain properties and capital taxes have been reclassified from income taxes;

(v)Alberta Royalty Tax Credit was adjusted to reduce the amount to the maximum allowable for the period.

4.Pro forma assumptions and adjustments to the statement of operations as a result of the proposed Rockyview Arrangement:

(a)The future income tax expense has been adjusted to reflect the impact on earnings of the transactions at an effective rate of 36.5%;

(b)Interest expense attributable to long term debt decreased due to the reduction in debt from applying the proceeds from the options and rights against the principal, an interest rate of 5% was used for the calculation;

(c)Convertible debenture interest and associated accretion decreased due to the assumption that the convertible debentures have been converted on January 1, 2004 in order for debenture holder’s to receive a share of Rockyview;

(d)Capital taxes have been reduced to reflect the decreased capital base of APF Trust;

(e)As a result all options and rights deemed to be exercisable, the unamortized fair value of APF’s options and rights was expensed;

(f)The net income per unit has been calculated using the number of APF Trust units, assuming the exercise of all outstanding APF Trust options, rights and convertible debentures as though they had been converted at the beginning of the year.  All options and rights including ones which have not vested are deemed to be exercisable as a result of the proposed combination with Starpoint.  It is assumed that all APF Trust unitholders will elect to receive a share in Rockyview and not elect to receive APF Inc. Notes.

Estimated APF trust units outstanding	60,623,943
Estimated conversion of APF options and rights	2,395,229
Estimated dilutive effect of convertible debentures	4,316,533
Total diluted trust units outstanding at the effective date of the arrangement	67,335,705

(g)Depreciation, depletion and accretion expense has been adjusted to reflect the application of the appropriate unit-of-production rate for the Rockyview Assets based on Rockyview’s estimated proved petroleum and natural gas reserves as determined by independent reserve engineers.

(h)The revenues, royalties, and operating expenses of Rockyview have been eliminated as a result of the proposed sale of the assets to Rockyview Energy Inc.

SCHEDULE “E” – SCHEDULE OF REVENUES, ROYALTIES AND OPERATING EXPENSES FOR THE
ENCANA ASSETS

E - 1

EnCana Assets

Schedule of Revenues, Royalties and Operating Expenses

Years Ended December 31, 2004, 2003 and 2002

($ thousands)

PricewaterhouseCoopers LLP

Chartered Accountants

111 5th Avenue SW, Suite 3100

Calgary, Alberta

Canada T2P 5L3

Telephone +1 (403) 509 7500

Facsimile +1 (403) 781 1825

April 29, 2005

Auditors’ Report

To the Directors of EnCana Corporation

At the request of EnCana Corporation, we have audited the schedule of revenues, royalties and operating expenses for the years ended December 31, 2004, 2003 and 2002 for the EnCana Assets. This financial information is the responsibility of management. Our responsibility is to express an opinion on this financial information based on our audits.

We conducted our audits in accordance with Canadian generally accepted auditing standards. Those standards require that we plan and perform an audit to obtain reasonable assurance whether the financial information is free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial information. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial information presentation.

In our opinion, the schedule of revenues, royalties and operating expenses present fairly, in all material respects, the revenues, royalties and operating expenses for the EnCana Assets for the years ended December 31, 2004, 2003 and 2002 in accordance with the basis of accounting disclosed in note 1.

Chartered Accountants

Calgary, Alberta

PricewaterhouseCoopers refers to the Canadian firm of PricewaterhouseCoopers LLP and the other member firms of PricewaterhouseCoopers International Limited, each of which is a separate and independent legal entity.

EnCana Assets

Schedule of Revenues, Royalties and Operating Expenses

($ thousands)

	Year Ended December 31,
	2004		2003		2002
Revenues	$	100,896	$	89,709	$	93,341
Royalties	4,999		5,345		4,785
	95,897		84,364		88,556
Operating expenses	17,926		17,741		16,274
Excess of revenues over operating expenses	$	77,971	$	66,623	$	72,282

See accompanying Notes to Schedule

EnCana Assets

Notes to Schedule of Revenues, Royalties and Operating Expenses

Years Ended December 31, 2004, 2003 and 2002

1.Basis of presentation

The schedule of Revenues, Royalties and Operating Expenses includes the operating results relating to the EnCana Assets.  The results have been compiled on an activity month basis.

The EnCana Assets consist of crude oil and natural gas assets which have been offered for sale and are located in East Central Alberta (Provost Battery 1 and Hayter) and South East Alberta (Alderson East, Alderson Kininvie, Countess and Suffield West).

The Schedule of Revenues, Royalties and Operating Expenses for these properties does not include any provision for the depletion and depreciation, asset retirement costs, future capital costs, impairment of unevaluated properties, administrative costs and income taxes for these properties as these amounts are based on the consolidated operations of the vendor of which these properties form only a part.

2.Significant accounting policies

(A) Joint Venture Operations

Substantially all of the EnCana Assets are operated through joint ventures therefore the schedules reflect only the vendor’s proportionate interest.

(B) Revenue Recognition

Revenues are recorded net of related transportation costs when the product is delivered.  Gas revenues are based on AECO pricing references used for sales between EnCana operating divisions and do not reflect ultimate marketing related activities.  Oil revenues are based on blended prices established by EnCana marketing for similar product delivered to a common carrier.

(C) Royalties

Royalties are recorded at the time the product is produced and sold.  Royalties are calculated in accordance with the applicable regulations and/or the terms of individual royalty agreements.  Gas crown royalties are based on the Alberta Government posted reference prices.  Oil crown royalties are taken in kind by the Government of Alberta.  The annual adjustment relating to gas cost allowance is recorded when received.

(D) Operating Expenses

Operating expenses include amounts incurred on extraction of product to the surface, gathering, field processing, treating and field storage.

EnCana Assets

Schedule of Revenues, Royalties and Operating Expenses

Three Months Ended March 31, 2005 and 2004 (unaudited)

($ thousands)

EnCana Assets

Schedule of Revenues, Royalties and Operating Expenses

($ thousands)

	Three Months Ended March 31,
	2005		2004
Revenues	$	25,596	$	21,308
Royalties	1,163		989
	24,433		20,319
Operating expenses	4,543		4,189
Excess of revenues over operating expenses	$	19,890	$	16,130

See accompanying Notes to Schedule

EnCana Assets

Notes to Schedule of Revenues, Royalties and Operating Expenses

Three Months Ended March 31, 2005 and 2004 (unaudited)

1.Basis of presentation

The schedule of Revenues, Royalties and Operating Expenses includes the operating results relating to the EnCana Assets.  The results have been compiled on an activity month basis.

The EnCana Assets consist of crude oil and natural gas assets which have been offered for sale and are located in East Central Alberta (Provost Battery 1 and Hayter) and South East Alberta (Alderson East, Alderson Kininvie, Countess and Suffield West).

The Schedule of Revenues, Royalties and Operating Expenses for these properties does not include any provision for the depletion and depreciation, asset retirement costs,  future capital costs, impairment of unevaluated properties, administrative costs and income taxes for these properties as these amounts are based on the consolidated operations of the vendor of which these properties form only a part.

2.Significant accounting policies

(A) Joint Venture Operations

Substantially all of the EnCana Assets are operated through joint ventures therefore the schedules reflect only the vendor’s proportionate interest.

(B) Revenue Recognition

Revenues are recorded net of related transportation costs when the product is delivered.  Gas revenues are based on AECO pricing references used for sales between EnCana operating divisions and do not reflect ultimate marketing related activities.  Oil revenues are based on blended prices established by EnCana marketing for similar product delivered to a common carrier.

(C) Royalties

Royalties are recorded at the time the product is produced and sold.  Royalties are calculated in accordance with the applicable regulations and/or the terms of individual royalty agreements.  Gas crown royalties are based on the Alberta Government posted reference prices.  Oil crown royalties are taken in kind by the Government of Alberta.  The annual adjustment relating to gas cost allowance is recorded when received.

(D) Operating Expenses

Operating expenses include amounts incurred on extraction of product to the surface, gathering, field processing, treating and field storage.

SCHEDULE “F” - PRO FORMA CONSOLIDATED FINANCIAL STATEMENTS

F - 1

COMPILATION REPORT ON PRO FORMA FINANCIAL STATEMENTS

To the Trustee of StarPoint Energy Trust

We have read the accompanying unaudited pro forma consolidated balance sheet of StarPoint Energy Trust (the “Trust”) as at December 31, 2004 and the unaudited pro forma consolidated statement of operations for the year then ended and have performed the following procedures:

1.Compared the figures in the columns captioned “StarPoint Energy Ltd.” to the audited consolidated financial statements of StarPoint Energy Ltd. as at December 31, 2004 and for the year then ended and found them to be in agreement.

2.Compared the figures in the columns captioned “E3 Energy Inc.” to the audited consolidated financial statements of E3 Energy Inc. as at December 31, 2004 and for the year then ended and found them to be in agreement.

3.Compared the figures in the columns captioned “Selkirk Energy Partnership” to the unaudited consolidated financial statements of the Selkirk Energy Partnership as at December 31, 2004 and for the year then ended and found them to be in agreement.

4.Compared the figures in the column captioned “APF Pro Forma” to the unaudited pro forma consolidated financial statements of APF Energy Trust as at December 31, 2004 and for the year then ended and found them to be in agreement.

5.Compared the figures in the column captioned “Encana Assets” to the audited Schedule of Revenues, Royalties and Operating Expenses for the Encana Assets for the year ended December 31, 2004 and found them to be in agreement.

6.Made enquires of certain officials of the Trust who have responsibility for financial and accounting matters about:

(a)the basis for the determination of the pro forma adjustments; and

(b)whether the pro forma consolidated financial statements comply as to form in all material respects with the regulatory requirements of the various Securities Commissions and similar regulatory authorities in Canada.

The officials:

(a)described to us the basis for determination of the pro forma adjustments; and

(b)stated that the pro consolidated forma financial statements comply as to form in all material respects with the regulatory requirements of the various Securities Commissions and similar regulatory authorities in Canada.

7.Read the notes to the pro forma consolidated financial statements, and found them to be consistent with the basis described to us for determination of the pro forma adjustments.

8.Recalculated the application of the pro forma adjustments to the aggregate of the amounts in the applicable columns captioned “StarPoint Energy Ltd.”, “E3 Energy Inc.”, “Selkirk Energy Partnership”, and “APF Pro Forma Total”, as at December 31, 2004 and for the year then ended December 31, 2004 and found the amounts in the column captioned “StarPoint Trust Pro Forma Total” to be arithmetically correct.

A pro forma financial statement is based on management assumptions and adjustments which are inherently subjective. The foregoing procedures are substantially less than either an audit or a review, the objective of which is the expression of assurance with respect to management’s assumptions, the pro forma adjustments and the application of the adjustments to the historical financial information. Accordingly, we express no such assurance. The foregoing procedures would not necessarily reveal matters of significance to the pro forma consolidated financial statements, and we therefore make no representation about the sufficiency of the procedures for the purposes of a reader of such statements.

(Signed) KPMG LLP

Chartered Accountants

Calgary, Canada

May 11, 2005

STARPOINT ENERGY TRUST

Pro Forma Consolidated Balance Sheet

As at December 31, 2004

(Unaudited)

(Thousands of dollars)

	StarPoint Energy Ltd.		E3 Energy Inc.		Selkirk Energy Partnership		Pro Forma Adjustments						Pro Forma Sub Total		APF Pro Forma Total		Pro Forma Adjustments						StarPoint Trust Pro Forma Total
							Mission Assets			Other							APF			Encana Assets
Assets
Current assets:
Cash and cash equivalents	$	—	$	31	$	3,857	$	—		$	(8,988		$	—	$	—	$	—		$	—		$	—
												)(3f)
										5,100		(3e)	—		567		(567		)(3f)
Accounts receivable and other
	39,605		1,724		2,973		—			(6,000		)(3e)
										(747		)(3a)	37,555		51,132		—			—			88,687
	39,605		1,755		6,830		—			(10,635		)	37,555		51,699		(567		)	—			88,687
Deferred financing costs	—		—		—		—			—			—		—		—			2,400		(3g)	2,400
Asset retirement fund	—		—		—		—			—			—		3,271		—			—			3,271
Property and equipment	242,650		34,817		29,291		(21,061		)(2)	35,916		(3e)	—		—		(643,346		)(3e)	—
										20,720		(3e)	342,333		643,346		731,412		(3e)	390,700		(3e)	1,464,445
Goodwill	87,627		—		—		—			23,509		(3e)					323,968		(3e)	17,782		(3e)
										12,472		(3e)	123,608		118,478		(118,478		)(3e)				465,359
	$	369,882	$	36,572	$	36,121	$	(21,061	)	$	81,982		$	503,496	$	816,794	$	292,989		$	410,882		$	2,024,162

	StarPoint Energy Ltd.		E3 Energy Inc.		Selkirk Energy Partnership		Pro Forma Adjustments						Pro Forma Sub Total		APF Pro Forma Total			Pro Forma Adjustments						StarPoint Trust Pro Forma Total
							Mission Assets			Other								APF			Encana Assets
Current Liabilities and Unitholders’ Equity
Current liabilities:
Accounts payable and accrued liabilities	$	46,447	$	3,166	$	4,550	$	—		$	925	(3f)	$	—	$	—		$	21,028	(3f)	$	—		$	143,049
										500		(3b)
										1,200		(3a)	56,788		65,233
Bank loan	74,167		7,900		—		—			(19,494		)(3g)			—			7,000		(3g)	392,000		(3e)
										63,100		(3g)						(567		)(3g)	2,400		(3g)
										6,128		(3g)						144,545		(3e)	(295,200		)(3g)
										(63,896		)(3g)									15,010		(3g)
																					(60,000		)(3g)
										(8,988		)(3g)	58,917											264,105
	120,614		11,066		4,550		—			(20,525		)	115,705		65,233			172,006			54,210			407,154
Convertible debentures	—		—		—		—			—			—		—			—			45,400		(3i)	45,400
Long-term debt	—		—		—		—			—			—		144,545			(144,545		)(3e)	—			—
Derivative liability	—		—		—		—			—			—		335			—			—			335
Asset retirement obligation	13,375		1,841		523		(751		)(2)	115		(3h)	15,103		30,198						16,482		(3e)	61,783
Future tax liability	40,170		1,323		3,543		2,097		(2)	14,098		(3e)
										(3,543		)(3e)
										(195		)(3b)
										(740		)(3j)	56,753		89,252									146,005
Unitholders’ Equity
Unitholders capital	186,220		15,685		20,926		(22,407		)(2)	17,148		(3e)			—			759,759		(3e)	295,200		(3g)
										19,494		(3i)						(636,662		)(3e)	(15,010		)(3g)
										(4,975		)(3a)
										5,100		(3e)						(7,000		)(3g)	—
										63,896		(3i)
										3,649		(3i)	306,841		636,662
										2,105		(3i)												1,339,791
Exchangeable shares	—		—		—					6,810		(3i)	6,810		—			—			—			6,810
Convertible debentures	—		—		—		—			—			—		—			—			14,600		(3i)	14,600
Contributed surplus	3,649		494		—		—			(4,143		)(3i)	—		—			—			—			—
Accumulated distributions	—		—		—		—						—		(276,293		)	276,293		(3e)	—			—
Accumulated earnings	5,854		6,163		6,579		—			(12,742		)(3e)	—		—			—			—			—
										(305		)(3b)
										(2,105		)(3i)
										(1,160		)(3j)	2,284		126,862			(126,862		)(3e)				2,284
	195,723		22,342		27,505		(22,407		)	96,187			315,935		487,231			265,528			294,790			1,363,485
	$	369,882	$	36,572	$	36,121	$	(21,061	)	$	81,982		$	503,496	$	816,794		$	292,989		$	410,882		$	2,024,162

See accompanying notes to pro forma consolidated financial statements.

STARPOINT ENERGY TRUST

Pro Forma Consolidated Statements of Operations

Year ended December 31, 2004

(Unaudited)

(Thousands of dollars except per unit amounts)

	Starpoint Energy Ltd.			E3 Energy Inc															Pro Forma Sub Total			APF Pro Forma Total			Encana Assets			Pro Forma Adjustments			Starpoint Trust Pro Forma Total
										Pro Forma Adjustments
							Selkirk Energy Partnership			Upton Resources Ltd.			Mission Assets			Adjustment
Revenue
Oil and gas sales	$	102,019		$	17,344		$	16,851		$	5,439		$	(12,493	)	$	—		$	129,160		$	255,791		$	100,896		$	—		$	485,847
Royalties expense, net of ARTC	(24,262		)	(2,990		)	(3,990		)	(1,237		)	3,178			—			(29,301		)	(51,405		)	(4,999		)	—			(85,705		)
Other	—			—			45			—			—			—			45			—			—			—			45
	77,757			14,354			12,906			4,202			(9,315		)	—			99,904			204,386			95,897			—			400,187
Expenses:
Operating and transportation	18,895			4,513			2,016			810			(3,075		)	—			23,159			62,209			17,926			—			103,294
General and administrative	2,393			1,659			707			3,930									8,689			14,567			—			—			23,256
Stock based compensation	1,979			357			—									(357		)(4e)	1,979			(415		)	—			—			1,564
Depletion, depreciation and amortization	36,152			3,964			5,553			2,549			—			1,418		(4b)	49,636			93,490			—			42,213		(4b)	185,339
Accretion of ARO	685			104			23			—			—			(49		)(4b)	763						—			989		(4b)	1,752
Accretion of equity
Component of Debentures	—			—			—			—			—			—			—			—			—			733		(4b)	733
Interest and bank charges	2,252			286			—			155						(363		)(4a)										3,284		(4a)
																500		(3b)	2,830			6,359			—			3,900		(4a)	16,373
	62,356			10,883			8,299			7,444			(3,075		)	1,149			87,056			176,210			17,926			51,119			332,311
Income (loss) before income
taxes	15,401			3,471			4,607			(3,242		)	(6,240		)	(1,149		)	12,848			28,176			77,971			(51,119		)	67,876
Income taxes:
Capital	2,916			12			—			—						274		(4c)	3,202			3,529			—			(3,071		)(4c)	3,660
Future income taxes (recovery)	6,080			590			755			—			—			(3,158		)(4c)	4,267			(26,156		)	—			(2,638		)(4c)	(24,527		)
	8,996			602			755			(3,242		)	—			(2,884		)	7,469			(22,627		)	—			(5,709		)	(20,867		)
Net income (loss)	$	6,405		$	2,869		$	3,852		$	(3,242	)	$	(6,240	)	$	1,735		$	5,379		$	50,803		$	77,971		$	(45,410	)	$	88,743
Net income per unit:
Basic																															$	1.02
Diluted																															$	1.02

See accompanying notes to pro forma consolidated financial statements.

STARPOINT ENERGY TRUST

Notes to Pro Forma Consolidated Financial Statements

As at December 31, 2004 and for the year then ended

(Unaudited)

(Tabular amounts in thousands of dollars)

1.     Basis of presentation:

The accompanying unaudited pro forma consolidated balance sheet of StarPoint Energy Trust (the “Trust”) as at December 31, 2004 and the unaudited pro forma consolidated statement of operations for the year ended December 31, 2004 (the “pro forma statements”) have been prepared to reflect the following:

•The Plan of Arrangement (the “Arrangement”) dated December 7, 2004 to convert StarPoint Energy Ltd. (“StarPoint”) and E3 Energy Inc. (“E3”) from companies focused on oil and natural gas exploration and production into two new entities: (i) Mission Oil & Gas Inc. (“Mission”), a new public company concentrating on the exploration and development of oil and natural gas reserves; and (ii) the Trust, an entity designed to distribute to its unitholders a substantial portion of cash from operations generated by the producing assets. StarPoint Energy Ltd. (“Amalco”), a wholly-owned subsidiary of the Trust on the amalgamation of StarPoint, E3 and StarPoint Acquisition Ltd., holds the working interests in the properties.

The Trust was settled on December 6, 2004 and had $1,980 in cash and unitholders’ equity as at December 31, 2004. These amounts have been included in the pro forma statements. The pro forma statements include the accounts of the Trust and its subsidiaries. The Arrangement was finalized on January 7, 2005.

•The issue of 3,760,000 Trust units for gross proceeds of $67,680,000.

•The acquisition of all the issued and outstanding shares of four private corporations (the “Selkirk Acquisition”), who together own 100% of the interests in the Selkirk Energy Partnership (“Selkirk”) for cash consideration of $69 million.

•The acquisition of all the issued and outstanding units of APF Energy Trust (“APF Acquisition”), for unit consideration of $760 million upon issuance of 40,970,664 Trust units at an adjusted price of $18.54 per unit.

•The acquisition of all the issued and outstanding units of the Encana Assets (“Encana Assets”) for cash consideration of $392 million.

•The issue of $60,000,000 convertible debentures at a coupon rate of 6.5 % per annum and a conversion price of $19.75 per Trust unit.

•The issue of 16,400,000 Trust units for gross proceeds of $295,200,000.

The pro forma statements have been prepared from information derived from and should be read in conjunction with the following:

1)StarPoint’s audited consolidated financial statements as at December 31, 2004 and for the year then ended;

2)E3’s audited consolidated financial statements as at December 31, 2004 and for the year ended;

3)The unaudited statement of net operating revenues of the Mission Assets for the nine months ended September 30, 2004;

4)     the unaudited interim consolidated financial statements of Selkirk as at October 31, 2004 and for the nine months then ended;

5)APF’s audited consolidated financial statements as at December 31, 2004 and for the year then ended;

6)The audited Schedule of Revenues, Royalties and Operating Expenses for the Encana Assets for the year ended December 31, 2004.

7)The unaudited pro forma consolidated financial statements of APF Energy Trust as at December 31, 2004 and for the year then ended; and

8)The audited financial statement of the Trust as at December 31, 2004.

The pro forma statements have been prepared by management in accordance with Canadian generally accepted accounting principles. The unaudited pro forma consolidated balance sheet gives effect to the assumed transactions and assumptions described in notes 2, 3 and 4 as if they had occurred at December 31, 2004 and the unaudited pro forma consolidated statement of operations give effect to the transactions and assumptions in notes 2, 3 and 4 as if they had occurred at the beginning of the period being January 1, 2004. The pro forma statements may not be indicative of the results that actually would have occurred if the events reflected therein had been in effect on the dates indicated or of the results which may be obtained in the future. In preparing these pro forma financial statements no adjustments have been made to reflect the expected operating synergies and administrative cost savings that could result from the combining of the operations of StarPoint and the acquired entities.

Accounting policies used in the preparation of the pro forma statements are in accordance with those disclosed in StarPoint’s audited consolidated financial statements as at and for the year ended December 31, 2004.

In the opinion of management of the Trust, the pro forma statements include all of the necessary adjustments for the fair presentation of the Trust.

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2.     Pro forma assumptions and adjustments:

The pro forma statements give effect to the following assumptions and adjustments:

On November 26, 2004, StarPoint, E3, the Trust, Mission, StarPoint Acquisition Ltd. and StarPoint Exchange co Ltd. entered into the Arrangement which became effective on January 7, 2005. Under the Arrangement:

(a)StarPoint shareholders exchanged each StarPoint share they owned for: (i) 0.25 of a Trust unit or, at the election of the holder, 0.25 of an exchangeable share and; (ii) 0.1111 of a Mission share;

(b)E3 shareholders exchanged each E3 share they owned for: (i) 0.11 of a Trust unit or, at the election of the holder, 0.11 of an exchangeable share and; (ii) 0.0488 of a Mission share;

(c)each unexercised, in-the-money StarPoint option and E3 option was exchanged for a Trust converted option;

(d)virtually all of StarPoint’s and E3’s existing producing oil and gas assets were transferred to the benefit of the Trust; and

(e)certain exploration assets, undeveloped lands and limited producing oil and natural gas assets (the “Mission Assets”) held by StarPoint were transferred to Mission.

StarPoint was deemed the acquirer of E3, APF and the Encana Assets, consequently the Trust will account for these as acquisitions using the purchase method of accounting. As the former StarPoint and E3 shareholder group own Mission and the Trust (including its subsidiaries), the oil and gas properties and the associated asset retirement obligation transferred to Mission was recorded at StarPoint’s carrying value.

The carrying value of the Mission Assets was determined based on the portion of the oil and natural gas revenue of the proved properties transferred relative to the total future net revenue of the proved properties StarPoint had before the transfer. The revenue, royalties and operating expenses related to the Mission Assets have been deducted from the unaudited pro forma consolidated statement of operations of the Trust for the year ended December 31, 2004 and related adjustments have been made to depletion, depreciation and accretion and income taxes.

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3.     Balance Sheet Adjustments:

(a)Completion of the business combination whereby all of the issued and outstanding shares of E3 are exchanged for StarPoint common shares. For purposes of the purchase price determination, StarPoint used an adjusted share price of $4.32 per StarPoint common share. StarPoint issued 14,258,946 common shares on the acquisition of E3.

The pro forma consolidated balance sheet includes $1,200,000 in costs incurred by E3 for required severance and professional costs, net of proceeds received on exercise of outstanding E3 stock options. In addition, StarPoint incurred $4,975,000 in share issue costs relating to the issuance of 14,258,946 common shares to E3 shareholders of which $747,000 has been reclassified from accounts receivable.

(b)On November 8, 2004 StarPoint entered into agreements to acquire all the issued and outstanding shares of four private corporations representing the Selkirk Acquisition.

With respect to the Selkirk acquisition, StarPoint was to participate as to 50% with a third party with which they had an irrevocable option to acquire the third parties interest. StarPoint exercised this option and paid the required $500,000 fixed fee ($305,000 net of future income taxes totaling $195,000).

(c)On April 13, 2005 StarPoint entered into an agreement to acquire all the issued and outstanding units of APF For purposes of the purchase price determination, StarPoint has used an adjusted unit price of $18.54 per StarPoint unit and has assumed that 40,970,664 Trust units will be issued.

The pro forma consolidated balance sheet includes $21,028,000 in costs to be incurred by APF for required severance and professional costs. In addition, StarPoint incurred $7,000,000 in unit issue costs relating to the issuance of 40,970,664 units to APF unitholders.

(d)On May 9, 2005 StarPoint entered into an agreement to acquire all the issued and outstanding units of the Encana Assets.

4

(e)   The purchase price allocations are as follows:

	E3			Selkirk
Cost of acquisition:
Cash	$	—		$	69,100
Common shares issued	61,573			—
Fair value of options assumed	4,096			—
Transaction costs	800			125
	$	66,469		$	69,225
Allocated:
Property and equipment	$	70,733		$	50,011
Goodwill	23,509			12,472
Working capital (including transactions costs of $1,200,000)	(2,611		)	7,380
Bank loan	(7,900		)	—
Asset retirement obligation	(1,841		)	(638		)
Future income taxes	(15,421		)	—
	$	66,469		$	69,225

Included within Selkirk’s working capital is $5,100,000 in relation to redeemable, retractable preferred shares issued for cash to a partner of Selkirk prior to its acquisition by the Trust.

Included in StarPoint’s accounts receivable at December 31, 2004 was a deposit on the acquisition of Selkirk of $6,000,000.

The acquisitions of E3 and Selkirk closed on January 7, 2005 and January 28, 2005 respectively. The allocation of the purchase price to the assets and liabilities will be finalized once the fair values of the assets and liabilities are determined. Accordingly the above allocations may change.

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	APF			Encana Assets
Cost of acquisition:
Cash	$	—		$	392,000
Units issued	759,759			—
	$	759,759		$	392,000
Allocated:
Property and equipment	$	731,412		$	390,700
Goodwill	323,968			17,782
Working capital (including transactions costs of $21,028,000)	(34,897		)	—
Long-term debt	(144,545		)	—
Asset retirement fund	3,271			—
Asset retirement obligation	(30,198		)	(16,482		)
Future income taxes	(89,252		)	—
	$	759,759		$	392,000

The allocation of the purchase price to the assets and liabilities will be finalized once the fair values of the assets and liabilities are determined. Accordingly the above allocations may change.

(f)The working capital of StarPoint and E3 has been allocated entirely to the Trust. Included in the working capital adjustments are a reclassification of the cash balance to bank indebtedness of $8,988,000 and $567,000 for a total of $9,555,000 as well as increases to accounts payable of $925,000 and $21,028,000 totaling $21,953,000 for transaction costs on the acquisitions of E3, Selkirk and APF.

(g)Bank indebtedness has been adjusted to reflect the proceeds in relation to StarPoint and E3 options exercised of $17,623,000 and $1,871,000 totaling $19,494,000, transaction and unit issue costs of $6,128,000 ($6,875,000 net of prepaid costs of $747,000) on the issue of shares relating to the E3 transaction, the consideration on the Selkirk acquisition of $63,100,000 ($69,100,000 net of the deposit of $6,000,000), proceeds of $63,896,000 ($67,680,000 net of issue costs of $3,784,000) on the issue of 3,760,000 Trust units, proceeds of $280,190,000 ($295,200,000 net of issue costs of $15,010,000), $7,000,000 of unit issue costs on the APF acquisition, proceeds of $57,600,000 ($60,000,000 net of deferred financing costs of $2,400,000) on the issue of convertible debentures, repayment of APF long term debt of $144,545,000 and the reclassification of the cash balance of $9,555,000.

6

(h)The asset retirement obligation for the Trust has been measured based on the assumptions and terms consistent with those used by StarPoint. The liability was estimated based on the net ownership of all wells and facilities, the estimated costs to abandon and reclaim the wells and facilities and the estimated timing of the costs to be incurred in future periods.

(i)Unitholders’ capital has been adjusted to reflect the acquisition of E3, Selkirk, APF and the Encana Assets. Of the consideration rendered on the acquisition of E3, $6,810,000 has been allocated to exchangeable shares issued on the acquisition. Other adjustments include proceeds in relation to StarPoint and E3 options exercised of $17,623,000 and $1,871,000 respectively totaling $19,494,000 and a reclassification of contributed surplus to share capital on the exercise of the options. Accumulated earnings (deficit) has been adjusted by $2,105,000 to reflect the StarPoint options becoming fully vested immediately prior to being exercised.

Unitholders’ capital has been adjusted to reflect the issue of 3,760,000 Trust units for proceeds of $63,896,000 net of commissions and transactions costs of $3,784,000 pursuant to an underwriting agreement dated January 27, 2005.

Unitholders’ capital has also been adjusted to reflect the issue of 16,400,000 Trust units for proceeds of $295,200,000 net of commissions and transactions costs of $15,010,000 pursuant to an underwriting agreement dated May 9, 2005.

Unitholders’ capital has also been adjusted by $14,600,000 to reflect the fair value of the conversion feature relating to the issue of $60,000,000 of convertible debentures at a unit price of $19.75 and a coupon rate of 6.5%.

(j)Direct and incremental costs related to the Arrangement, estimated to be $1,900,000 ($1,160,000 net of future income taxes of $740,000), have been charged to accumulated earnings (deficit) on the pro forma balance sheet. These costs have not been included in the pro forma statement of operations as they relate to StarPoint and E3 prior to becoming a Trust and will be expensed in StarPoint’s and E3’s financial statements as incurred.

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4.     Statement of Operations Adjustments:

(a)Interest expense has been adjusted to give effect to the cash portion of the consideration paid on the acquisitions of Selkirk and the Encana Assets as well as the interest charged on the convertible debentures less the proceeds received from the exercise of options, the equity issues and convertible debenture issue as if they occurred on January 1, 2004.

(b)Depreciation, depletion and accretion have been adjusted to reflect the application of the appropriate unit-of-production rate for the full cost pool allocated to the Trust based on the estimated proved petroleum and natural gas reserves as determined by independent reserve engineers after adjustments for the transactions referred to in 3(e).

(c)Capital taxes have been adjusted to reflect the increased size of the Trust after the completion of the transactions referred to in note 3(e). The provision for current income taxes would be eliminated under the new structure and consequently the future income tax provision has been increased to reflect this. The future income tax provision reflects the lower taxable income for amounts being allocated to Mission and for the tax impact of the pro forma adjustments in the pro forma consolidated statement of operations.

(d)The net income per Trust unit and exchangeable shares has been based on the following historical weighted average number of shares of StarPoint adjusted for the Arrangement. The calculation reflects the exercise of all options prior to the Arrangement.

	Year ended December 31, 2004
StarPoint pro forma weighted average shares outstanding	79,642,000
Issued on acquisition of E3	14,258,946
	93,900,946
Trust units and exchangeable shares outstanding after giving effect to the Arrangement	24,099,444
Options exercised	1,515,962
Equity issue	3,760,000
Issued on acquisition of APF	40,970,664
Equity issue	16,400,000
Weighted average Trust Units and Exchangeable Shares	86,746,070
Allocated as follows:
Trust units	83,251,475
Exchangeable shares	3,494,595

8

(e)No new options are assumed to be issued in the period.

(f)StarPoint acquired Upton Resources Ltd. on January 24, 2004. The pro forma statement of operations for the year ended December 31, 2004 has been adjusted to incorporate the pre-acquisition period from January 1, 2004 to January 24, 2004. These adjustments have been made based on the unaudited results for the period.

The pro forma consolidated financial statements as at December 31, 2004 and for the year then ended have been adjusted to incorporate the periods from January 1, 2004 to January 31, 2004 and November 1, 2004 to December 31, 2004 in relation to the acquisition of Selkirk as well as for the period from October 1, 2004 to December 31, 2004 in relation to the Mission Assets. These adjustments have been made based on the unaudited results for the periods.

(g)The properties comprising the Mission Assets were acquired by StarPoint or its subsidiary companies at various points in time. The pro forma consolidated statement of operations has been adjusted only for the revenues and related expenditures incurred after the properties were acquired by StarPoint.

9

CERTIFICATE OF THE TRUST

Dated: May 11, 2005

This short form prospectus, together with the documents incorporated herein by reference, constitutes full, true and plain disclosure of all material facts relating to the securities offered by this prospectus as required by the securities legislation of each of the provinces of Canada. For the purpose of the Province of Québec, this simplified prospectus, as supplemented by the permanent information record, contains no misrepresentation that is likely to affect the value or the market price of the securities to be distributed.

STARPOINT ENERGY TRUST,
by its administrator, STARPOINT ENERGY LTD.

(signed)	“Paul Colborne”	(signed)	“Brett Herman”
	President and		Vice-President, Finance and
	Chief Executive Officer		Chief Financial Officer
On behalf of the Board of Directors
(signed)	“Robert G. Peters”	(signed)	“Jim Bertram”
	Director		Director

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CERTIFICATE OF THE UNDERWRITERS

Dated: May 11, 2005

To the best of our knowledge, information and belief, this short form prospectus, together with the documents incorporated herein by reference, constitutes full, true and plain disclosure of all material facts relating to the securities offered by this prospectus as required by the securities legislation of each of the provinces of Canada. For the purpose of the Province of Québec, this simplified prospectus, as supplemented by the permanent information record, contains no misrepresentation that is likely to affect the value or the market price of the securities to be distributed.

BMO NESBITT BURNS INC.

(signed) “Jason J. Zabinsky”

SCOTIA CAPITAL INC.

(signed) “Mark Herman”

FIRSTENERGY CAPITAL CORP.

(signed) “Hugh R. Sanderson”

CIBC WORLD MARKETS INC.

(signed) “T. Timothy Kitchen”

TD SECURITIES INC.

(signed) “Drew E. MacIntyre”

ORION SECURITIES INC.

(signed) “Lee A. Pettigrew”

NATIONAL BANK FINANCIAL INC.

(signed) “Robert B. Wonnacott”

GMP SECURITIES LTD.		RBC DOMINION SECURITIES INC.
	(signed) “Sandy L. Edmonstone”		(signed) “Robi Contrada”

TRISTONE CAPITAL INC.

(signed) “Vincent L. Chahley”

CANACCORD CAPITAL CORPORATION

(signed) “Karl B. Staddon”

FIRST ASSOCIATES INVESTMENTS INC.		HAYWOOD SECURITIES INC.
	(signed) “John M. Peltier”		(signed) “David G. McGorman”

H - 1