EX-99.88 89 a05-22113_1ex99d88.htm EXHIBIT 99

Exhibit 99.88

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”.

SHORT FORM PROSPECTUS

New Issue

July 28, 2005

STARPOINT ENERGY TRUST

$223,800,000

12,000,000 Subscription Receipts,

each representing the right to receive one Trust Unit

Price: $18.65 per Subscription Receipt

This short form prospectus qualifies for distribution 12,000,000 subscription receipts (“Subscription Receipts”) of StarPoint Energy Trust (the “Trust”) at a price of $18.65 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 “Acquisition”) by the Trust of certain petroleum and natural gas properties and related assets currently owned indirectly by Nexen Inc. 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 Acquisition. Upon the Acquisition being completed on or before 5:00 p.m. (Calgary time) on August 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 Acquisition.

If the closing of the Acquisition does not take place by 5:00 p.m. (Calgary time) on August 31, 2005, if the 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 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 entitlement to interest on such amount. The Escrowed Funds will be applied towards payment of such amount.

If the closing of the Acquisition takes place by 5:00 p.m. (Calgary time) on August 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 July 22, 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 Acquisition occurs on or before August 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 $0.21 per Trust Unit that will be paid by the Trust on August 15, 2005 to holders of Trust Units (“Unitholders”) of record on July 22, 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 July 22, 2005 and prior to the closing of the 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 Acquisition. If the Acquisition closes on August 9, 2005, as currently contemplated, holders of Subscription Receipts will become Unitholders on August 9, 2005 and will be entitled, provided they remain Unitholders on August 22, 2005, to receive the monthly distribution expected to be paid on September 15, 2005 to Unitholders of record on August 22, 2005. See “Description of Subscription Receipts”.

The issued and outstanding Trust Units are listed on the TSX under the trading symbol “SPN.UN”. On July 15, 2005, the last trading day prior to the public announcement of the offering, the closing price of the Trust Units on the TSX was $19.23 per Trust Unit. The Trust has applied to list the Subscription Receipts and the Trust Units issuable pursuant to the Subscription Receipts on the TSX. The TSX has conditionally approved the listing of the Subscription Receipts and the Trust Units issuable pursuant to the Subscription Receipts. Listing is subject to the Trust fulfilling all of the listing requirements of the TSX on or before October 9, 2005.

The price of the Subscription Receipts 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)	$	18.65	$	0.9325	$	17.7175
Total(1)(2)(3)	$	223,800,000	$	11,190,000	$	212,610,000

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 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 1,000,000 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 $242,450,000, $12,122,500 and $230,327,500 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, 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.

BMO Nesbitt Burns Inc., Scotia Capital Inc., CIBC World Markets Inc., TD Securities Inc., National Bank Financial Inc. and RBC Dominion Securities Inc. are wholly owned subsidiaries of Canadian chartered banks which are lenders to the Trust. Consequently, the Trust may be considered to be a connected issuer of each of BMO Nesbitt Burns Inc., Scotia Capital Inc., CIBC World Markets Inc., TD Securities Inc., National Bank Financial Inc. and RBC Dominion Securities Inc. for the purposes of securities regulations in certain provinces. See “Relationship Between the Trust and Certain of the Underwriters” and “Use of Proceeds”.

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

Subscriptions for Subscription Receipts 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 August 9, 2005 or such other date not later than August 22, 2005 as the Trust and the Underwriters may agree. Except in certain limited circumstances: (i) 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, (ii) no certificates evidencing Subscription Receipts will be issued to subscribers for Subscription Receipts and (iii) subscribers for Subscription Receipts 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 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 or the Trust Units 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 and the Trust Units issuable pursuant to the Subscription Receipts 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 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.

iii

Cash distributions by the Trust to Unitholders are not guaranteed.

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 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.

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	14
The Acquisition	15
Information Concerning the Nexen Assets	16
Effect of the Acquisition on the Trust	24
Description of Subscription Receipts	26
Description of Trust Units	28
Consolidated Capitalization of the Trust	29
Material Debt	29
Price Range and Trading Volume of Units	30
Record of Cash Distributions	31
Hedging Arrangements	31
Use of Proceeds	32
Plan of Distribution	32
Relationship Between the Trust and Certain of the Underwriters	33
Interest of Experts	34
Certain Canadian Federal Income Tax Considerations	34
Eligibility for Investment	39
Risk Factors	39
Material Contracts	41
Legal Proceedings	41
Auditors, Transfer Agent and Registrar	42
Statutory and Contractual Rights of Withdrawal and Rescission	42
Auditors’ Consents	43
Schedule “A” - Schedule of Revenue and Expenses	A-1
Schedule “B” - Pro Forma Consolidated Financial Statements	B-1
Certificate of the Trust	C-1
Certificate of the Underwriters	D-1

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;

• 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.

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.

“114 Partnership” means 1148607 Alberta Partnership, a general partnership formed under the laws of the Province of Alberta;

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

“990 Alberta” means 990009 Alberta Inc., a corporation incorporated under the ABCA and a wholly-owned subsidiary of the Trust;

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

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

“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/EnCana BAR” means the Trust’s revised business acquisition report dated July 28, 2005 with respect to the APF Combination and the EnCana Acquisition;

“APF Combination” means the indirect acquisition by the Trust of all of the assets and liabilities of APF in exchange for Trust Units completed on June 27, 2005;

“APF Inc.” means APF Energy Inc., a corporation incorporated under the ABCA and wholly-owned subsidiary of the Trust;

“APF Notes” means the unsecured subordinated notes of APF Inc. in the aggregate amount of $107,237,985 acquired by the Trust pursuant to the APF Combination;

“APF Partnership” means APF Energy Limited Partnership, a limited partnership formed under the laws of the Province of Alberta;

“APF Royalties” means the entitlement of the Trust, pursuant to the terms and conditions of certain royalty agreements dated May 14, 2004, to 99% of the production revenues from the oil and gas properties of APF Inc. and APF Partnership, less deductions on account of production costs, debt service charges, management fees and general and administrative costs;

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

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

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

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

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

“CRA” means the Canada Revenue Agency;

“Credit Facility” means the credit facility available to the Administrator and Subtrust defined and described under the heading “Material Debt”;

“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 from EnCana of certain assets completed on June 30, 2005;

“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;

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

“Nexen” means Nexen Inc.;

“Nexen Agreement” means the partnership purchase agreement dated July 18, 2005 between the Administrator and Subtrust, as purchasers, and Nexen and Canadian Nexen Yemen Ltd., as vendors, respecting the purchase of the Nexen Assets;

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

“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 12,000,000 Subscription Receipts, and any Subscription Receipts issued pursuant to the exercise of the Option, pursuant to this short form prospectus;

“Option” means the option granted by the Trust to the Underwriters to purchase up to an additional 1,000,000 Subscription Receipts at a price of $18.65 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;

“Sproule Report” means the independent engineering report of Sproule dated June 30, 2005 evaluating, effective March 31, 2005, the oil, NGL and natural gas reserves attributable to the Nexen Assets;

“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;

“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 July 20, 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.

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
GJ/d		gigajoule per day


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 one BOE to six Mcf of natural gas. BOEs may be misleading, particularly if used in isolation. A BOE conversion ratio of one BOE for six 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
$000s or M$		thousands of dollars
WTI		West Texas Intermediate, the reference price paid in U.S. dollars at Cushing, Oklahoma for crude oil of standard grade

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 production or 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 production or reserves its working interest (operating or non-operating) share after deduction of royalty obligations, plus the its royalty interests in production or 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 gross wells; 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.

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;

(d) the Trust’s unaudited interim comparative consolidated financial statements as at and for the three months ended March 31, 2005, together with the notes thereto;

(e) the Trust’s management’s discussion and analysis for the three months ended March 31, 2005;

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

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

(h) the Trust’s material change report dated May 13, 2005 with respect to the EnCana Acquisition;

(i) the Trust’s material change report dated July 20, 2005 with respect to the Acquisition;

(j) the APF/EnCana BAR;

(k) Schedules “A”, “B” and “C” to the short form prospectus of the Trust dated May 19, 2005; and

(l) the Trust’s Information Circular and Proxy Statement dated April 15, 2005 relating to the annual meeting of Unitholders 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 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”.

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 and the holder of the Administrator Notes. 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.

Pursuant to the NPI Agreement, the Partnership has granted and set over to the Trust the NPI on petroleum and natural gas rights held by the Partnership from time to time (the “Property Interests”). Pursuant to the terms of the NPI Agreement, the Trust is entitled to a payment from the Partnership for each month equal to the amount by which 99% percent of the gross proceeds from the sale of production attributable to the Property Interests for such month exceed 99% percent of certain deductible production costs for such period.

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.

The Trust is the sole beneficiary of Subtrust. Subtrust owns all of the issued and outstanding shares of 116 Alberta and directly and indirectly owns all of the partnership interests in 114 Partnership. 114 Partnership holds the EnCana Assets. See “Significant Acquisitions by StarPoint and the Trust – The EnCana Acquisition”.

The Trust owns all of the issued and outstanding shares of APF Inc. and 990 Alberta, is the sole beneficiary of APF Trust and holds the APF Notes. 990 Alberta and APF Trust own all of the partnership interests in APF Partnership. APF Inc., 990 Alberta, APF Trust and APF Partnership hold the oil and gas assets indirectly acquired pursuant to the APF Combination. See “Significant Acquisitions by StarPoint and the Trust – The APF Combination”.

The Trust holds the APF Royalties, pursuant to which it is entitled to receive 99% of the income from the oil and gas properties held by APF Inc. and APF Partnership after the deduction of certain costs and expenses.

In addition to the above, the Trust has various other non-material direct and indirect subsidiaries.

The following diagram shows the simplified structure of the Trust, excluding non-material subsidiaries, as at the date hereof:

Business of the Trust

The Trust’s wholly-owned subsidiaries are engaged in the business of producing and exploring for oil and natural gas. Through these subsidiaries, 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. The Trust’s primary mandate is to focus on low cost operations, maintain and grow reserves and production and distribute approximately 65% to 75% of its available cash flow (at current commodity prices) to Unitholders in monthly distributions.

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, interest received on the principal amount of the APF Notes, income under the NPI Agreement, income received from Subtrust and income received from the APF Royalties. 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 and APF 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 “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” to the short form prospectus of the Trust dated May 19, 2005, which is incorporated herein by reference, contains the audited comparative financial statements of E3 as at and for the years ended December 31, 2004 and 2003.

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” to the short form prospectus of the Trust dated May 19, 2005, which is incorporated herein by reference, 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 a 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” to the short form prospectus of the Trust dated May 19, 2005, which is incorporated herein by reference, 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.

The APF Combination

On June 27, 2005, the Trust completed the APF Combination. Pursuant to the APF Combination, the Trust acquired all of the assets of APF and assumed all of its liabilities. In exchange, the Trust issued 0.63 of a Trust Unit for every outstanding trust unit of APF. Approximately 39,659,628 Trust Units were issued pursuant to the APF Combination. In addition, the Trust assumed APF’s obligations with respect to its outstanding 9.40% convertible, unsecured, subordinated debentures, maturing July 31, 2008, in an aggregate principal amount of $46,986,000.

Prior to the completion of the APF Combination, APF transferred certain assets and the liabilities associated therewith to Rockyview Energy Inc. and each holder of trust units of APF was given the right to receive common shares of Rockyview Energy Inc. The assets consisted of approximately 1,000 BOE/d of production, primarily natural gas from properties located in Central Alberta. Those assets were not acquired by the Trust pursuant to the APF Combination and the Trust did not acquire any interest in Rockyview Energy Inc.

Following the completion of the APF Combination, Steve Cloutier and Martin Hislop, each of Calgary, Alberta, joined the Board of the Administrator. Mr. Hislop had been the Chief Executive Officer of the administrator of APF and Mr. Cloutier had been the President and Chief Operating Officer.

The APF Combination is 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. A complete description of the assets acquired by the Trust pursuant to the APF Combination is provided in the APF/EnCana BAR, the contents of which have been incorporated by reference into this short form prospectus.

Schedule “B” to the APF/EnCana BAR, which is incorporated herein by reference (“Schedule “B”), contains audited annual financial statements for APF for the years ended December 31, 2004 and 2003 and unaudited comparative interim financial statements for the three months ended March 31, 2005. On June 4, 2004, APF acquired all of the issued and outstanding shares of Great Northern Exploration Ltd. Schedule “B” 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 “B” contains unaudited pro forma combined financial statements for APF after giving effect to the acquisition of Great Northern Exploration Ltd. by APF and the transfer by APF of assets to Rockyview Energy Inc. prior to the completion of the APF Combination.

The EnCana Acquisition

On June 30, 2005, the Trust completed the EnCana Acquisition. Pursuant to the EnCana Acquisition, the Trust indirectly acquired certain assets from EnCana, effective May 1, 2005, for aggregate cash consideration of $392 million.

Upon the completion of the EnCana Acquisition, 17,800,000 subscription receipts that had been issued by the Trust on May 26, 2005 were exchanged for 17,800,000 Trust Units. In addition, the maturity date of the 6.50% convertible extendible unsecured subordinated debentures of the Trust in the aggregate principal amount of $60,000,000 issued on May 26, 2005 was extended from July 31, 2005 to July 31, 2010.

A complete description of the assets acquired by the Trust pursuant to the EnCana Acquisition is provided in the APF/EnCana BAR, the contents of which have been incorporated by reference into this short form prospectus.

Schedule “A” to the APF/EnCana BAR, which is incorporated herein by reference, contains an audited Statement of Net Operating Revenue concerning the assets acquired from EnCana for the years ended December 31, 2004, 2003 and 2002 and an unaudited Statement of Net Operating Revenue concerning the assets for the three month period ended March 31, 2005.

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 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.

Financings

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

May 26, 2005, the Trust completed an offering of 17,800,000 subscription receipts at a price of $18.00 each and 6.50% convertible extendible unsecured subordinated debentures in the aggregate principal amount of $60,000,000, for net proceeds of $361,980,000.

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 Acquisition. The Trust cannot predict whether any current or future opportunities will result in one or more acquisitions for the Trust.

THE ACQUISITION

On July 18, 2005, the Administrator and Subtrust entered into the Nexen Agreement with Nexen and Canadian Nexen Yemen Ltd., a wholly-owned subsidiary of Nexen. The Nexen Agreement provides for the acquisition by Subtrust of all the interests of Nexen Canada No. 5 Partnership, an Alberta general partnership which holds the Nexen Assets, for aggregate cash consideration of $330 million before adjustments. The Trust anticipates that the net purchase price after adjustments will be approximately $318.25 million.

Under the Nexen Agreement, conditions to closing of the 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), the completion of title and environmental due diligence and the absence of any substantial damage or physical alteration of the tangibles included in the Nexen Assets. Closing of the Acquisition is expected to occur on or about August 9, 2005, with an effective date of June 1, 2005.

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

INFORMATION CONCERNING THE NEXEN ASSETS

General

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

Oil and Natural Gas Reserves

In accordance with NI 51-101, Sproule prepared the Sproule Report. The Sproule Report evaluated, as at March 31, 2005, the oil, NGL and natural gas reserves attributable to the Nexen Assets. The tables below are a summary of the oil, NGL and natural gas reserves attributable to the Nexen Assets and the net present value of future net revenue attributable to such reserves as evaluated in the Sproule Report, based on constant and forecast price and cost assumptions. The tables summarize the data contained in the Sproule Report and, as a result, may contain slightly different numbers than such reports due to rounding. Also due to rounding, certain columns may not add exactly.

The net present value of future net revenue attributable to reserves is stated without provision for interest costs and general and administrative costs, but after providing for estimated royalties, production costs, development costs, other income, future capital expenditures, and well abandonment costs for only those wells assigned reserves by Sproule. It should not be assumed that the undiscounted or discounted net present value of future net revenue attributable to reserves estimated by Sproule represent the fair market value of those reserves. Other assumptions and qualifications relating to costs, prices for future production and other matters are summarized herein. The recovery and reserve estimates of oil, NGL and natural gas reserves provided herein are estimates only. 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	Natural Gas	Light and Medium Crude Oil	Natural Gas
	Mbbls	MMcf	Mbbls	MMcf
Proved
Developed Producing	9,294	4,819	8,278	4,475
Developed Non-Producing	41	—	37	—
Undeveloped	1,065	701	996	647
Total Proved	10,399	5,521	9,311	5,122
Probable	4,884	2,598	4,404	2,439
Total Proved plus Probable	15,284	8,119	13,715	7,561

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	404,109	268,115
Developed Non-Producing	692	583
Undeveloped	41,487	29,126
Total Proved	446,289	297,825
Probable	211,758	100,560
Total Proved plus Probable	658,047	398,385

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	726,463	95,823	136,016	20,826	27,508	446,289
Total Proved plus Probable	1,065,312	134,303	194,468	43,306	35,190	658,047

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)		297,825
Proved plus Probable
Light and Medium Crude Oil(1)		398,385

Notes:

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

Summary of Oil and Gas Reserves – Forecast Prices and Costs

	Gross Reserves		Net Reserves
	Light and Medium Crude Oil	Natural Gas	Light and Medium Crude Oil	Natural Gas
	Mbbls	MMcf	Mbbls	MMcf

Proved
Developed Producing	9,286	4,821	8,283	4,476
Developed Non-Producing	22	—	20	—
Undeveloped	1,065	701	997	648
Total Proved	10,373	5,522	9,299	5,124
Probable	4,866	2,600	4,397	2,440
Total Proved plus Probable	15,239	8,122	13,696	7,564

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	238,198	200,830	176,845	159,870	147,045
Developed Non-Producing	274	264	254	245	237
Undeveloped	24,124	20,287	17,332	14,979	13,059
Total Proved	262,596	221,381	194,431	175,094	160,340
Probable	118,814	75,261	56,409	44,856	36,982
Total Proved plus Probable	374,410	296,642	250,840	219,950	197,322

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	545,909	72,272	154,484	20,936	35,620	262,596
Total Proved plus Probable	792,418	99,249	228,393	43,786	46,580	374,410

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)		194,431
Proved plus Probable
Light and Medium Crude Oil(1)		250,840

Notes:

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

Pricing Assumptions – Constant Prices and Costs

The following pricing and exchange rate assumptions as of March 31, 2005 were used in the Sproule Report in estimating reserves data using constant prices and costs.

Light and Medium Crude Oil
Edmonton
Par Price		Natural Gas		Exchange
40° API ($Cdn/Bbl)		AECO - C Spot ($Cdn/MMBTU)		Rate ($US/$Cdn)
$	67.38	$	7.87	$	0.826

Pricing Assumptions – Forecast Prices and Costs

The following pricing, exchange rate and inflation rate assumptions as of March 31, 2005 were used in the Sproule Report in estimating reserves data using forecast prices and costs.

	Light and Medium Crude Oil
	Edmonton
	Par Price		Natural Gas		Exchange
	40° API		AECO - C Spot		Rate
Year	($CDN/Bbl)		($CDN/MMBTU)		($US/$Cdn)

2005	63.85		7.93		$	0.8225
2006	60.05		7.72		$	0.8225
2007	50.58		6.91		$	0.8225
2008	43.35		6.13		$	0.8225
2009	41.10		5.76		$	0.8225
2010	41.78		5.85		$	0.8225
2011	42.52		5.98		$	0.8225
2012	43.31		6.05		$	0.8225
2013	44.05		6.19		$	0.8225
2014	44.85		6.29		$	0.8225
2015	45.61		6.43		$	0.8225
2016	46.46		6.53		$	0.8225
2017 to 2024	+1.75	%	+1.75	%	$	0.8225
Thereafter	+0.75	%	+0.75	%	$	0.8225

Future Development Costs

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

	Constant Prices and	Forecast Prices and Costs
	Costs		Proved Plus
	Proved Reserves	Proved Reserves	Probable Reserves
	(M$)	(M$)	(M$)
2005	15,686	15,686	23,783
2006	5,140	5,250	17,235
2007	—	—	2,769
2008	—	—	—
2009	—	—	—
Remaining Years	—	—	—
Total Undiscounted	20,826	20,936	43,787
Total Discounted at 10% per year	19,950	20,050	40,949

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 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 properties comprising the Nexen Assets are located in southeast Saskatchewan, approximately 210 kilometres southeast of Regina. The Nexen Assets feature a land base situated along the Frobisher/Kisbey/Alida subcrop edge. Interests range from royalty interests to working interests up to 100%, with the average working interest being approximately 65%. The Nexen Assets are 85% operated with a land base of 44,859 (38,117 net) undeveloped acres.

Production from the Nexen Assets is weighted 92% to oil, with the balance being solution gas. Average production from the Nexen Assets during the first quarter of 2005 was 6,340 BOE/d. Oil production from the assets is generally light sweet crude with a 38° API. The acquired properties include Edenvale (Alida West), Ingoldsby, Nottingham, Cantal and Queensdale.

Facilities associated with the Nexen Assets include the Nottingham gas plant and gathering system, a 75% working interest in an Arlington pipeline and several operated and non-operated oil batteries. All natural gas production from the Nexen Assets is in the form of solution gas, which is conserved from existing production and processed at

the Nottingham gas plant or the BP Steelmen gas plant. Nexen holds a 17.5% working interest in the Nottingham gas plant.

The Nexen Assets include 520 (390.5 net) producing oil wells and 117 (77.5 net) non-producing oil wells. For the year ended December 31, 2004, Nexen participated in the drilling of 24 (19 net) development oils wells. For the three months ended March 31, 2005, Nexen participated in the drilling of 17 (9.7 net) development oil wells.

Planned exploration and development activity on the Nexen properties for 2005 includes the drilling of 12 (9.9 net) wells at an estimated total net cost of $8.0 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 Nexen Assets.

Producing Wells

Non-Producing Wells

Oil

Natural Gas

Oil

Natural Gas

Gross

Net

Gross

Net

Gross

Net

Gross

Net

Total

520

390.5

—

117

77.5

—

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 Nexen 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

Total	44,859	38,117	12,296

Drilling Activity

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

	Exploratory Wells		Development Wells
	Gross	Net	Gross	Net
Crude Oil	—	—	24	19.0

The following table sets forth the gross and net exploratory and development wells drilled on the properties comprising the Nexen Assets during the three months ended March 31, 2005.

	Exploratory Wells		Development Wells
	Gross	Net	Gross	Net
Crude Oil	—	—	17	9.7

Additional Information Concerning Abandonment and Reclamation Costs

Well abandonment costs have been estimated area by area. Such costs are included in the Sproule Report as deductions in arriving at future net revenue. The expected total abandonment costs, net of estimated salvage value, included in the Sproule Report for 569 net wells under the proved reserves category is $16.2 million undiscounted ($6.2 million discounted at 10%), of which a total of $0.3 million is estimated to be incurred in 2005, 2006 and 2007. This estimate does not include expected reclamation costs for surface leases of $5.7 million undiscounted ($2.2 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 Nexen Assets.

	Property Acquisition Costs
	Proved Properties	Unproved Properties	Exploration Costs	Development Costs
Total (M$)	2	—	241	17,967

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 Nexen Assets.

	Property Acquisition Costs
	Proved Properties	Unproved Properties	Exploration Costs	Development Costs
Total (M$)	—	—	353	7,440

Production Estimates

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

Crude Oil (Bbls/d)		Natural Gas (Mcf/d)		BOE (BOE/d)		%
5,667		3,150		6,192		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 Nexen 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)	3,293	2,744	3,090	3,280	3,208
Crude Oil (Bbls/d)	5,749	5,217	5,326	5,504	5,797
NGL (Bbls/d)	14	13	12	8	9
Total (BOE/d)	6,312	5,687	5,853	6,058	6,340

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	Mar. 31, 2005
Prices Received	43.95	48.59	54.46	51.51	57.47
Royalties Paid	9.74	10.90	12.15	11.06	11.67
Production Costs	6.41	6.87	8.81	7.72	4.88
Netback(1)	27.80	30.82	33.50	32.72	40.92

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	Mar. 31, 2005
Prices Received	8.00	8.12	8.93	9.95	9.74
Royalties Paid	0.61	0.57	0.62	0.73	0.72
Production Costs	1.07	1.14	1.47	1.29	0.81
Netback(1)	6.32	6.40	6.84	7.93	8.20

Note:

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

Financial Statements

Schedule “A” hereto contains an audited Schedule of Revenue and Expenses concerning the Nexen Assets for the years ended December 31, 2004, 2003 and 2002 and an unaudited Schedule of Revenue and Expenses concerning the Nexen Assets for the three month period ended March 31, 2005 and 2004.

EFFECT OF THE ACQUISITION ON THE TRUST

Selected Pro Forma Financial Information

The following tables set out certain pro forma combined financial information for the Nexen Assets and the Trust for the year ended December 31, 2004 and as at and for the three month period ended March 31, 2005 after giving effect to the Arrangement, the acquisition of Selkirk, the APF Combination, the EnCana Acquisition, the offering of 3,760,000 Trust Units completed on February 10, 2005, the offering of 17,800,000 subscription receipts and $60,000,000 of debentures completed on May 26, 2005 and the Offering hereunder.

The information provided below is qualified in its entirety by the unaudited pro forma combined financial statements attached as Schedule “B” 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 Trust’s unaudited interim comparative consolidated financial statements as at and for the three months ended March 31, 2005, incorporated herein by reference, (iv) the audited comparative financial statements of E3 as at and for the years ended December 31, 2004 and 2003, incorporated herein by reference, (v) the audited consolidated financial statements of Upton as at and for the year ended December 31, 2003, incorporated herein by reference, (vi) 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, incorporated herein by reference, (vii) the audited annual financial statements for APF for the years ended December 31, 2004 and 2003 and the unaudited comparative interim financial statements for APF for the three months ended March 31, 2005, incorporated herein by reference, (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, incorporated herein by reference, (ix) the unaudited pro forma combined financial statements for APF, incorporated herein by reference, (x) the audited statement of net operating revenue concerning the assets acquired pursuant to the EnCana Acquisition for the years ended December 31, 2004, 2003 and 2002 and the unaudited statement of net operating revenue concerning the such assets for three month period ended March 31, 2005, incorporated herein by reference, and (xi) the audited schedule of revenue and expenses concerning the Nexen Assets for the years ended December 31, 2004, 2003 and 2002 and the unaudited schedule of revenue and expenses concerning the Nexen assets for three month period ended March 31, 2005 and 2004, attached as Schedule “A” hereto.

For the year ended December 31, 2004	Trust(1)		Nexen Assets		Pro Forma(3)
	($000's)		($000's)		($000's)

Net petroleum and natural gas revenue(4)	400,187		89,271(2	)	489,458

Net earnings (loss)	89,188		—		109,058

Per unit (basic)	$	1.03	—		$	1.10

Per unit (diluted)	$	1.02	—		$	1.10

Note:

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

(2) Information is derived from the applicable audited financial information included herein.

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

(4) Revenue net of royalties.

For the three months ended March 31, 2005	Trust(1)		Nexen Assets		Pro Forma(3)
	($000's)		($000's)		($000's)

Net petroleum and natural gas revenue(4)	88,634		26,731	(2)	115,365
Net earnings (loss)	3,496		—		9,199
Per unit (basic)	$	0.04	—		$	0.09
Per unit (diluted)	$	0.04	—		$	0.09
Total Assets	2,080,605		335,443		2,416,048
Total Liabilities	731,982		123,083		855,065
Net Equity	1,348,623		212,360		1,560,983

Note:

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

(2) Information is derived from the applicable unaudited financial information included herein.

(3) Information is derived from the applicable unaudited pro forma financial statements included herein.

(4) Revenue net of royalties.

Selected Combined Operational Information

The following tables set forth certain combined operational information after giving effect to the Arrangement, the acquisition of Selkirk, the APF Combination, the EnCana Acquisition and the acquisition of the Nexen Assets.

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 acquired pursuant to the APF Combination and the EnCana Acquisition is contained in the APF/EnCana BAR, which is incorporated by reference herein. Important information in respect of the Nexen Assets is set forth herein under the headings “Information Concerning the Nexen Assets”. Readers are encouraged to carefully review the AIF, the APF/EnCana BAR and the information provided herein concerning the Nexen Assets as the tables below provide a summary only.

	Trust	Nexen Assets	Pro Forma
Average Daily Production
(For the year ended December 31, 2004)
Crude oil & NGLs (Bbls/d)	21,165	5,460	26,625
Natural gas (Mcf/d)	74,378	3,102	77,480
Oil equivalent (BOE/d)	33,561	5,977	39,538
Average Daily Production
(For the three months ended March 31, 2005)
Crude oil & NGLs (Bbls/d)	20,727	5,806	26,533
Natural gas (Mcf/d)	74,167	3,208	77,375
Oil equivalent (BOE/d)	33,088	6,340	39,428

	Trust	Nexen Assets	Pro Forma
Net Proved Reserves(1)
Light/medium crude oil & NGLs (Mbbls)	32,724	9,299	42,023
Heavy crude oil (Mbbls)	11,338	—	11,338
Natural gas (MMcf)	129,602	5,124	134,726
Oil equivalent (MBOE)	65,662	10,153	75,815
Net Proved plus Probable Reserves(1)
Light/medium crude oil & NGLs (Mbbls)	50,219	13,696	63,915
Heavy crude oil (Mbbls)	14,602	—	14,602
Natural gas (MMcf)	181,415	7,564	188,979
Oil equivalent (MBOE)	95,057	14,957	110,014
Net Undeveloped Land(2)	722,387	38,117	760,504

Notes:

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

(2) As at March 31, 2005.

Potential Dispositions of Non-Core Assets

Following completion of the Acquisition, the Trust will conduct a review of the Nexen Assets with a view to determining whether a disposition of certain of the acquired assets not considered core to the operations of the subsidiaries of the Trust, comprising approximately 500 BOE/d of production, would be beneficial. As of the date of this short form prospectus, the Trust has not reached any agreement for the disposition of non-core assets with any potential buyers.

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.

Except in certain limited circumstances: (i) 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, (ii) no certificates evidencing Subscription Receipts will be issued to subscribers for Subscription Receipts and (iii) subscribers for Subscription Receipts 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 is purchased.

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 Acquisition. Provided that the closing of the Acquisition occurs by 5:00 p.m. (Calgary time) on August 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 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 Acquisition does not take place by 5:00 p.m. (Calgary time) on August 31, 2005, the 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 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 earned on the Escrowed Funds. 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 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 July 22, 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 Acquisition occurs on or before August 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 $0.21 per Trust Unit that will be paid by the Trust on August 15, 2005 to Unitholders of record on July 22, 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 July 22, 2005 and prior to the closing of the 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 Acquisition. If the Acquisition closes on August 9, 2005, as currently contemplated, holders of Subscription Receipts will become Unitholders on August 9, 2005 and will be entitled, provided they remain Unitholders on August 22, 2005, to receive the monthly distribution expected to be paid on September 15, 2005 to Unitholders of record on August 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 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 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 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.

The Trust is not a legally recognized entity within the relevant definitions of the Bankruptcy and Insolvency Act (Canada), the Companies’ Creditors Arrangement Act (Canada), and in some cases the Winding Up and Restructuring Act (Canada). As a result, in the event a restructuring of the Trust were necessary, the Trust would not be able to access the remedies available thereunder. In the event of a restructuring, the position of Unitholders may be different than that of the shareholders of a corporation.

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 APF Combination, the EnCana Acquisition, the offering of 3,760,000 Trust Units completed on February 10, 2005, the offering of 17,800,000 subscription receipts and $60,000,000 of debentures completed on May 26, 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)			Outstanding as at March 31, 2005 after giving effect to the Transactions(2)(3)
Trust Units	Unlimited	$	2,000	$	1,551,779,000		$	1,559,302,000
		(1 trust unit)		(95,340,439		trust units)	(96,868,873		trust units)
Exchangeable Shares	Unlimited	$	nil	$	6,810,000		$	4,489,000
		(nil shares)		(3,494,595		shares)	(2,126,228		shares)
Bank Debt		$	nil	$	322,115,000	(4)	$	399,017,000	(4)

Debentures		$	nil	$	106,801,000	(5)	$	106,801,000	(5)

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 $12,122,500, 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 Nexen Assets.

(3) As at July 28, 2005 there were 86,617,031 Trust Units and 1,622,157 Exchangeable Shares outstanding. In addition there were 1,052,400 restricted units of the Trust outstanding as at July 28, 2005 pursuant to the Trust’s restricted unit plan, as described in the AIF.

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

(5) Such debentures are comprised of 9.40% convertible, unsecured, subordinated debentures in an aggregate principal amount of $46,986,000 and 6.50% convertible, extendible, unsecured subordinated debentures in an aggregate principal amount of $60,000,000. The values indicated in the table represent the debt component of the debentures.

MATERIAL DEBT

Pursuant to a credit agreement dated June 27, 2005 (the “Credit Agreement”), the Administrator and Subtrust have entered into a banking arrangement with a syndicate of eight banks led by Bank of Montreal and including Canadian Imperial Bank of Commerce, The Bank of Nova Scotia, The Toronto-Dominion Bank, Royal Bank of Canada, National Bank of Canada, Alberta Treasury Branches and BNP Paribas (Canada). The banking arrangement makes available to the Administrator and Subtrust a credit facility in the aggregate amount of $450,000,000 (the “Credit Facility”).

As at July 28, 2005, a total of approximately $351 million was outstanding under the Credit Facility. The Trust anticipates that an additional amount of approximately $86 million will need to be drawn on the Credit Facility to fund a portion of the purchase price of the Acquisition. The Trust anticipates that the credit limit under the Credit Facility will be increased by an amount sufficient to accommodate any additional borrowing request that may be necessary to complete the Acquisition.

Amounts outstanding under the Credit Facility are secured by a first charge in favour of the lenders over all assets and undertakings of the Administrator and Subtrust and each of their guarantors, which include the Trust and all of its material subsidiaries. If the Administrator and Subtrust become unable to pay their obligations to the lenders as they become due or they otherwise commit an event of default as defined under the Credit Agreement, the lenders may foreclose on and sell the assets of the Administrator and Subtrust and their guarantors free from, or together with, the NPI and the APF Royalties.

In connection with and as security for the Credit Agreement, the Trust, the Administrator, Subtrust and the Partnership have entered into a subordination agreement dated June 27, 2005 with Bank of Montreal on behalf of itself and the other lenders under the Credit Agreement (the “Subordination Agreement”). Under the Subordination Agreement, any and all present and future indebtedness of the Administrator, Subtrust, the Partnership or other subsidiary of the Trust to the Trust itself, including under the NPI, are postponed and made subordinate to the repayment of amounts owing under the Credit Facility.

Under the Credit Facility and the Subordination Agreement, the Administrator and Subtrust and each of their guarantors, which include the Trust and all of its material subsidiaries, are restricted from making any distributions (including to Unitholders) when (i) a default or event of default under the Credit Facility has occurred and is continuing, (ii) outstanding loans under the Credit Facility exceed the borrowing base set by the lenders thereunder until such time as such outstanding loans are reduced below the borrowing base, or (iii) a distribution would exceed the calculation of “net free cash flow” (defined as the consolidated net income of the Administrator and Subtrust before the deduction of interest, taxes, depreciation and amortization, minus cash taxes paid and scheduled principal and interest payments).

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 service the debt of the Administrator and Subtrust under the Credit Facility before the distribution or payment of any amounts to the Trust.

There can be no assurance that (i) the amounts available under the Credit Facility will be adequate for the financial obligations of the Trust, the Administrator and Subtrust, (ii) additional funds can be obtained under the Credit Facility to finance the Acquisition or otherwise, or (iii) upon expiration, the Credit Facility can be refinanced on terms acceptable to the Trust, the Administrator and Subtrust and to the applicable lenders.

The terms of the Credit Facility and the Subordination Agreement ensure that the lenders have priority over the Unitholders with respect to the assets and income of the Trust. Amounts due and owing to the lenders under the Credit Facility 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	$	18.75	4,206,861
April, 2005	$	20.50	$	17.75	4,435,841

	Price Range ($)
Period	High		Low		Trading Volume
May, 2005	$	18.65	$	17.65	5,349,588
June, 2005	$	19.90	$	18.11	10,685,696
July 1 to 27, 2005	$	19.64	$	18.65	15,017,497

On July 15, 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 $19.23. On July 27, 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 $19.50.

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 and the APF 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. Amounts due and owing under the Credit Facility must be paid before any distributions can be made to Unitholders. This could result in an interruption of distributions. 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
May 24, 2005	June 15, 2005	$	0.20
June 30, 2005	July 15, 2005	$	0.21
July 22, 2005	August 15, 2005	$	0.21

On July 18, 2005, the Trust announced that, subject to the completion of the Acquisition, the distribution anticipated to be paid on September 15, 2005 to Unitholders of record on August 22, 2005 will be increased to $0.22 per Unit.

HEDGING ARRANGEMENTS

From time to time, the Trust may enter into commodity price derivative contracts in order to promote stability of cash flows for operational expenditures and Unitholder distributions. As at July 28, 2005, the Trust had the following hedging arrangements outstanding:

Crude Oil Swaps

Year	Average Volumes Hedged (Bbls/d)	Price (WTI: C$/Bbl)
2005	6,245	$	55.36
2006	8,142	$	60.32
2007	5,562	$	62.00

Crude Oil Costless Collars

Year	Average Volumes Hedged (Bbls/d)	Price (WTI: US$/Bbl)
2005	1,638	$	44.69 - 52.65
2006	1,612	$	46.08 - 55.44

Natural Gas Swaps

Year	Average Volumes Hedged (GJ/d)	Price (AECO: C$/GJ)
2005	6,526	$	7.42
2006	21,562	$	7.69

Natural Gas Costless Collars

Year	Average Volumes Hedged (GJ/d)	Price (AECO: C$/GJ)
2005	16,530	$	6.48 - 8.11
2006	8,137	$	6.92 - 9.67

USE OF PROCEEDS

After deducting the Underwriters' fee of $11,190,000, 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 of $212,610,000. If the Option is exercised in full, the net proceeds to the Trust from the sale of the Subscription Receipts will be $230,327,500, after deducting the Underwriters’ fee of $12,122,500 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 fund a portion of the purchase price of the Nexen Assets pursuant to the Acquisition.

PLAN OF DISTRIBUTION

Pursuant to the Underwriting Agreement, the Trust has agreed to issue and sell an aggregate of 12,000,000 Subscription Receipts to the Underwriters and the Underwriters have severally agreed to purchase such Subscription Receipts on August 9, 2005, or such other date not later than August 22, 2005 as may be agreed among the parties to the Underwriting Agreement. Delivery of the Subscription Receipts is conditional upon payment on closing of $18.65 per Subscription Receipt by the Underwriters to the Escrow Agent. The Underwriting Agreement provides that the Trust will pay the Underwriters’ fee of $0.9325 per Subscription Receipt for Subscription Receipts issued and sold by the Trust, for an aggregate fee payable by the Trust of $212,610,000, 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 Acquisition. If the Acquisition is not completed by 5:00 p.m. (Calgary time) on August 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 1,000,000 Subscription Receipts at a price of $18.65 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 will terminate if the Acquisition is terminated or the Trust has advised the Underwriters or announced to the public that it does not intend to proceed with the Acquisition. If an Underwriter fails to purchase the Subscription Receipts

that it has agreed to purchase, the other Underwriters may, but are not obligated to, purchase such Subscription Receipts. 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 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”.

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 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.

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 and the Trust Units issuable pursuant to the Subscription Receipts on the TSX. The TSX has conditionally approved the listing of the Subscription Receipts and the Trust Units issuable pursuant to the Subscription Receipts. Listing is subject to the Trust fulfilling all of the listing requirements of the TSX on or before October 9, 2005. There is currently no market through which the Subscription Receipts may be sold and purchasers may not be able to resell Subscription Receipts purchased under this short form prospectus.

The Subscription Receipts and the Trust Units issuable pursuant to the Subscription Receipts (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 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 (“Rule 144A”). Moreover, the Underwriting Agreement provides that the Underwriters will offer and sell the Subscription Receipts 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 Rule 144A.

RELATIONSHIP BETWEEN THE TRUST AND CERTAIN OF THE UNDERWRITERS

As described under the heading “Material Debt”, certain of the Underwriters are wholly-owned subsidiaries of certain Canadian chartered banks (the “Banks”) that are lenders to the Administrator and Subtrust. More specifically, BMO Nesbitt Burns Inc. is a wholly-owned subsidiary of Bank of Montreal, Scotia Capital Inc. is a wholly-owned subsidiary of The Bank of Nova Scotia, CIBC World Markets Inc. is a wholly-owned subsidiary of Canadian Imperial Bank of Commerce, TD Securities Inc. is a wholly-owned subsidiary of The Toronto-Dominion Bank, National Bank Financial Inc. is a wholly-owned subsidiary of National Bank of Canada and RBC Dominion Securities Inc. is a wholly-owned subsidiary of Royal Bank of Canada. Accordingly, the Trust may be considered a “connected issuer” of each of BMO Nesbitt Burns Inc., Scotia Capital Inc., CIBC World Markets Inc., TD

Securities Inc., National Bank Financial Inc. and RBC Dominion Securities Inc. under applicable Canadian securities legislation.

Under the Credit Facility, the Administrator and Subtrust were indebted to the Banks and certain other lenders for an aggregate amount of approximately $351 million as at July 28, 2005. The Administrator and Subtrust are in compliance with all material terms of the agreements governing the Credit Facility and the Banks have not waived any material breach by the Administrator or Subtrust of such agreements since their execution. Neither the financial position of the Administrator and Subtrust nor the value of the security under the Credit Facility has changed substantially since the indebtedness under the Credit Facility was incurred. The proceeds of the Offering will not be applied to repay any of the indebtedness owed to the Banks under the Credit Facility. See “Material Debt” for further information concerning the Credit Facility.

The decision to distribute the Subscription Receipts 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 Banks did not have any involvement in such decision or determination, but have been advised of the issuance and terms thereof. As a consequence of the offering, BMO Nesbitt Burns Inc., Scotia Capital Inc., CIBC World Markets Inc., TD Securities Inc., National Bank Financial Inc. and RBC Dominion Securities Inc. will receive their share of the underwriting fee payable by the Trust to the Underwriters.

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 Sproule. As of the date hereof, the principals, directors, officers and associates of each of Sproule, as a group, 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 pursuant to the Offering and who, for purposes of the Tax Act and at all relevant times, holds the Subscription Receipts and the Trust Units issuable pursuant to the Subscription Receipts (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.

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 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 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 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 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.

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.

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 of the 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 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 Unitholder”).

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 Unitholder’s jurisdiction of residence. Under recent amendments to the Tax Act, distributions made to a Non-Resident Unitholder that are attributable to capital gains realized by the Trust after March 22, 2004 on the disposition by the Trust of taxable Canadian property in circumstances where the Trust has designated such capital gains to Unitholders will also be subject to Canadian withholding tax at a rate of 25% of the amount so distributed. 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 such distributions.

Pursuant to recent amendments to the Tax Act, the Trust will also be obligated to withhold at the rate of 15% on all distributions by the Trust to a Non-Resident Unitholder that are not otherwise included in the income of the Non-Resident Unitholder for the purposes of the Tax Act or otherwise subject to withholding taxes under the Tax Act. In the event that the Non-Resident Unitholder subsequently realizes a loss on the disposition of the Trust Units, the Non-Resident Unitholder 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 Unitholder, 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 Unitholder for the purposes of the Tax Act. Trust Units will not be considered taxable Canadian property to a Non-Resident Unitholder unless: (i) the Non-Resident Unitholder 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 Unitholder or persons with whom the Non-Resident Unitholder 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 Unitholder 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 Unitholder’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) 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 will cease to qualify as a mutual fund trust if it can 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 Administrator that the Trust has filed a valid election with CRA to have the Trust deemed to have been 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 and the APF Royalties on an accrual basis; and (ii) all interest on the Administrator Notes and APF 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; and (iii) income from Subtrust that becomes payable to the Trust in the 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. The Proposed Amendments would preclude the Trust from deducting a loss from a business or property unless the Trust has a reasonable expectation of realizing a cumulative profit (excluding capital gains) from such business or property. 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 and the Trust Units issuable pursuant to the Subscription Receipts 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”) and registered education savings plans (“RESP”) (collectively, “Exempt Plans”) under the Tax Act as in effect on the date hereof. 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 or a subscriber under the governing plan of the particular Exempt Plan. See “Risk Factors - Investment Eligibility and Mutual Fund Trust Status” in the AIF.

RISK FACTORS

An investment in the Subscription Receipts 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 Acquisition

The Acquisition is subject to normal commercial risks that the transactions may not be completed on the terms negotiated or at all. If closing of the Acquisition does not take place as contemplated, the Trust could suffer adverse consequences, including the forfeiture of deposits or the loss of investor confidence. In addition, if the 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.

Possible Failure to Realize Anticipated Benefits of Acquisitions

The Trust has completed the EnCana Acquisition and the APF Combination and is proposing to complete the Acquisition 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 Nexen 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 Nexen Assets that the Trust intends to acquire pursuant to the Acquisition. In particular, the reserve and recovery information contained in the Sproule Report in respect of the Nexen 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 may be sold and purchasers may not be able to resell Subscription Receipts purchased under this short form prospectus. There can be no assurance that an active trading market will develop for the Subscription Receipts after the Offering, or if developed, such a market will be sustained at the price level of the Offering.

Refinancing of Short Term Debt

The Trust has, and will continue to have following the completion of the Offering and the Acquisition, significant amounts of outstanding short term debt. There is no guarantee that the Trust will be able to refinance such short term debt on terms favourable to the Trust. Any increase in the cost of borrowing to the Trust arising out of the need to refinance short term debt may decrease the cash available for payment to Unitholders and could unfavourably affect future cash distributions.

Acquisitions

Acquisitions of oil and gas properties or companies are based in large part on engineering, environmental and economic assessments made by the acquiror, independent engineers and consultants. These assessments include a series of assumptions regarding such factors as recoverability and marketability of oil and gas, environmental restrictions and prohibitions regarding releases and emissions of various substances, future prices of oil and gas and operating costs, future capital expenditures and royalties and other government levies which will be imposed over the producing life of the reserves. Many of these factors are subject to change and are beyond the control of the Trust. All such assessments involve a measure of geologic, engineering, environmental and regulatory uncertainty that could result in lower production and reserves or higher operating or capital expenditures than anticipated.

Although title and environmental reviews are conducted prior to any purchase of resource assets, such reviews cannot guarantee that an unforeseen defects in the chain of title will not arise to defeat the Trust’s title to certain assets or that environmental defects or deficiencies do not exist. Such deficiencies or defects could reduce the amounts distributable to Unitholders, and could result in a reduction of capital.

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;

(d) the Subordination Agreement (as defined under the heading “Material Debt”);

(e) the Administration Agreement;

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

(g) 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;

(h) the Trust’s restricted unit plan;

(i) the DRIP Plan;

(j) the Nexen Agreement;

(k) the Subscription Receipt Agreement; and

(l) the Underwriting Agreement.

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) 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, are available on www.sedar.com. A copy of the Subscription Receipt Agreement 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”.

AUDITORS’ CONSENTS

Consent of KPMG LLP

We have read the short form prospectus (the “Prospectus”) of StarPoint Energy Trust (the “Trust”) dated July 28, 2005 relating to the qualification for distribution of 12,000,000 subscription receipts 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 above-mentioned Prospectus of our report to the unitholder 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 above-mentioned 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 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 September 5, 2003 to December 31, 2003. Our report is dated March 16, 2005.

We consent to the incorporation by reference in the above-mentioned 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 incorporation by reference in the above-mentioned 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 incorporation by reference in the above-mentioned 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

July 28, 2005

Consent of Collins Barrow Calgary LLP

The Board of Directors of StarPoint Energy Ltd.

We consent to the incorporation by reference 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

July 28, 2005

Consents of PricewaterhouseCoopers LLP

We consent to the incorporation by reference 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

July 28, 2005

We consent to the incorporation by reference 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

July 28, 2005

Consent of Deloitte & Touche LLP

We consent to the use in the Prospectus of our report to the Managing Partner of Nexen Canada No. 5 on the schedule of revenue and expenses of the properties of Nexen Canada No. 5 for each of the years in the three year period ended December 31, 2004. Our report is dated February 28, 2005.

(signed) “Deloitte & Touche LLP”

Chartered Accountants Calgary, Canada

July 28, 2005

SCHEDULE “A” - SCHEDULE OF REVENUE AND EXPENSES

A - 1

AUDITORS’ REPORT

To the Managing Partner of Nexen Canada No. 5

We have audited the schedule of revenue and expenses of the properties of Nexen Canada No. 5 for each of the years in the three year period ended December 31, 2004. This financial information is the responsibility of the management of Nexen Canada No. 5. 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 presentation of the financial information.

In our opinion, this schedule presents fairly, in all material respects, the revenue and expenses of the properties of Nexen Canada No. 5 as described in Note 1 for each of the years in the three year period ended December 31, 2004 in accordance with Canadian generally accepted accounting principles.

Calgary, Alberta	(signed) Deloitte & Touche LLP
February 28, 2005	Chartered Accountants

Nexen Canada No. 5

Schedule of Revenue and Expenses

For the years ended December 31, 2004, 2003 and 2002

And the three months ended March 31, 2005 and 2004

($000’s)

	March 31						December 31
	2005			2004			2004			2003			2002
	(unaudited)
REVENUE	$	33,030		$	25,897		$	112,001		$	104,798		$	106,782
ROYALTIES	(6,299		)	(5,839		)	(22,730		)	(21,397		)	(23,374		)
OPERATING EXPENSES	(3,382		)	(3,397		)	(15,700		)	(14,019		)	(12,036		)

NET OPERATING INCOME	$	23,349		$	16,661		$	73,571		$	69,382		$	71,372

Nexen Canada No. 5

Schedule of Revenue and Expenses

For the years ended December 31, 2004, 2003 and 2002

And for the three months ended March 31, 2005 and 2004

(amounts for the three months ended March 31, 2005 and 2004 are unaudited)

1. BASIS OF PRESENTATION

This schedule has been prepared by management of Nexen Inc. (the managing partner) and relates only to the working interests in the properties transferred from Nexen Petroleum Canada (partnership) as at December 31, 2004.

This schedule includes only those revenues, royalties, and operating expenses that are directly related to the properties transferred and does not include any expenses related to general and administrative expenses, insurance, interest, income and capital taxes or any provisions related to depletion, depreciation or asset retirement obligations.

SIGNIFICANT ACCOUNTING POLICIES

(a) Revenue

Sales are recorded when title to the commodities passes to the purchaser, at the pipeline delivery point for gas and at the wellhead for crude oil.

(b) Royalties

Royalties are recorded at the time the product is produced and are calculated in accordance with the applicable regulations.

Operating expenses include all costs related to the lifting, gathering, processing, and delivery to a sales point of the commodities.

SCHEDULE “B” - PRO FORMA CONSOLIDATED FINANCIAL STATEMENTS

B-1

	KPMG LLP
	Chartered Accountants	Telephone (403) 691-8000
	1200 205 – 5^th Avenue SW	Fax (403) 691-8008
	Calgary AB T2P 4B9	Internet www.kpmg.ca

COMPILATION REPORT ON PRO FORMA FINANCIAL STATEMENTS

We have read the accompanying unaudited pro forma consolidated balance sheet of StarPoint Energy Trust as at March 31, 2005 and the unaudited pro forma consolidated statement of operations for the three months ended March 31, 2005 and the year ended December 31, 2004 and have performed the following procedures:

1. Compared the figures in the columns captioned “StarPoint Energy Trust” to the unaudited interim consolidated financial statements of StarPoint Energy Trust as at March 31, 2005 and for the three months then ended and found them to be in agreement.

2. Compared the figures in the column captioned “StarPoint Energy Ltd” to the audited consolidated financial statements of StarPoint Energy Ltd. for the year ended December 31, 2004 and found them to be in agreement.

3. Compared the figures in the columns captioned “APF Pro Forma Total” to the unaudited pro forma consolidated financial statements of APF Energy Trust as at March 31, 2005 and for the three months then ended and for the year ended December 31, 2004 and found them to be in agreement.

4. Compared the figures in the column captioned “E3 Energy Inc.” to the audited consolidated financial statements of E3 Energy Inc. for the year ended December 31, 2004 and found them to be in agreement.

5. Compared the figures in the columns captioned “Encana Assets” to the unaudited schedule of revenues, royalties and operating expenses for the Encana Assets for the three months ended March 31, 2005 and 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. Compared the figures in the columns captioned “Nexen Assets” to the unaudited schedule of revenues, royalties and operating expenses for the Nexen Assets for the three months ended March 31, 2005 and to the audited schedule of revenues, royalties and operating expenses for the Nexen Assets for the year ended December 31, 2004 and found them to be in agreement.

7. Made enquires of certain officials of StarPoint Energy 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.

KPMG LLP, a Canadian limited liability partnership is the Canadian
member firm of KPMG International, a Swiss cooperative

The officials:

(a) described to us the basis for determination of the pro forma adjustments; and

(b) stated that 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.

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 Trust”, “StarPoint Energy Ltd.”, “E3 Energy Inc.”, “Encana Assets”, “Nexen Assets” and “APF Pro Forma Total”, as at March 31, 2005 and for the three months then ended and for the year ended December 31, 2004 and found the amounts in the columns 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
July 28, 2005

STARPOINT ENERGY TRUST

Pro Forma Consolidated Balance Sheet

As at March 31, 2005

(Unaudited)

(Thousands of dollars)

	StarPoint				APF																StarPointTrust
	Energy				Pro Forma				Pro Forma Adjustments												Pro Forma
	Trust				Total				APF			Encana Assets				Nexen Assets					Total

Assets

Current assets:
Cash and cash equivalents	$		—		$		1,299		$	(1,299	)(2f)	$		—		$		—			$		—
Accounts receivable and other	44,411				53,443				—			—				—					97,854
	44,411				54,742				(1,299		)	—				—					97,854
Deferred financing costs	—				—				—			2,400			(2e)	—					2,400
Asset retirement fund	—				3,475				—			—				—					3,475
Property and equipment	353,572				643,931				(643,931		)(2d)	390,700			(2d)	299,142				(2d)
									731,412		(2d)										1,774,826
Goodwill	121,760				118,478				(118,478		)(2d)	17,782			(2d)	36,301				(2d)
									361,650		(2d)										537,493
	$		519,743		$		820,626		$	329,354		$		410,882		$		335,443			$		2,416,048

Current Liabilities and Unitholders’ Equity

Current liabilities:
Accounts payable and accrued liabilities	$	35,908			$		76,691		$	14,228	(2a)	$	—			$			—		$		126,827
Bank loan	98,611				—				7,000		(2e)	392,000			(2d)	318,250				(2d)
									(1,299		)(2f)	(57,600			)(2e)	(223,800				)(2e)
									158,545		(2f)	(304,130			)(2e)	11,440				(2e)	399,017
	134,519				76,691				178,474			30,270				105,890					525,844
Convertible debentures	—				45,882				(45,882		)(2h)	58,800			(2e,g)
									48,001		(2h)										106,801
Long-term debt	—				158,545				(158,545		)(2f)	—				—					—
Derivative liability	—				1,304				—			—				—					1,304
Asset retirement obligation	16,804				30,727							16,482			(2d,i)	17,193				(2d,i)	81,206
Future tax liability	54,574				80,847				—			—				—					135,421

Non Controlling interest	4,489				—				—			—				—					4,489

Unitholders’ Equity:
Unitholders' capital	314,364				605,922				(605,922		)(2d)	320,400			(2e)	223,800				(2e)
	—				—				735,448		)(2d)	(16,270			)(2e)	(11,440				)(2e)
	—				—				(7,000		)(2d)	—				—					1,559,302
Convertible debentures	—				1,104				5,488		(2h)	1,200			(2g)	—					—
	—				—				(1,104		)(2h)	—				—					6,688
Contributed surplus	1,333				— 1,333
Accumulated distributions	(15,118			)	(304,887			)	304,887		(2d)	—				—					(15,118			)
Accumulated earnings	8,778				124,491				(124,491		)(2d)	—				—					8,778
	309,357				426,630				307,306			305,330				212,360					1,560,983
	$		519,743		$	820,626			$	329,354		$	410,882			$	335,443				$	2,416,048

See accompanying notes to pro forma consolidated financial statements.

STARPOINT ENERGY TRUST

Pro Forma Consolidated Statement of Operations

Three months ended March 31, 2005

(Unaudited)

(Thousands of dollars except per unit amounts)

				Pro Forma Adjustments
	Starpoint Energy Trust			Selkirk Energy Partnership			APF Pro Forma Total			Encana Assets			Nexen Assets			Pro Forma Adjustments			StarPoint Trust Pro Forma Total
				(note 3e)
Revenue:
Oil and gas sales	$	35,873		$	1,390		$	47,933		$	25,596		$	33,030		$	—		$	143,822
Royalties expense, net of ARTC	(7,799		)	(353		)	(12,843		)	(1,163		)	(6,299		)	—			(28,457		)
	28,074			1,037			35,090			24,433			26,731			—			115,365
Expenses:
Operating and transportation	5,332			199			15,765			4,543			3,382			—			29,221
General and administrative	828			1,002			3,528			—			—						5,358
Plan of arrangement costs	3,357			—			—			—			—			—			3,357
Depletion, depreciation and accretion	15,077			534			24,922			—						31,189		(3b)	71,722
Unit based compensation	1,333			—			277			—			—			—			1,610
Accretion of equity component of debentures	—			—			—			—			—			88		(3a)	88
Interest and bank charges	1,094			(7		)	2,768			—			—			975		(3a)	—
	—			—			—			—			—			1,951		(3a)	6,781
	27,021			1,728			47,260			4,543			3,382			34,203			118,137

Income (loss) before income taxes	1,053			(691		)	(12,170		)	19,890			23,349			(34,203		)	(2,772		)

Income taxes:
Capital	874			—			702			—			—			392		(3c)	1,968
Future income taxes (recovery)	(3,092		)	—			(10,096		)	—			—			(1,098		)(3c)	(14,286		)
	(2,218		)	—			(9,394		)	—			—			(706		)	(12,318		)
Non Controlling interest	347			—			—			—			—			—			347

Net income (loss)	$	2,924		$	(691	)	$	(2,776	)	$	19,890		$	23,349		$	(33,497	)	$	9,199

Net income per unit and exchangeable share (note 3f):
Basic																			$	0.09
Diluted																			$	0.09

See accompanying notes to pro forma consolidated financial statements.

STARPOINT ENERGY TRUST

Pro Forma Consolidated Statement of Operations

Year ended December 31, 2004

(Unaudited)

(Thousands of dollars except per unit amounts)

							Pro Forma Adjustments
	Starpoint						Selkirk			Upton												APF												Starpoint Trust
	Energy			E3 Energy			Energy			Resources			Mission						Pro Forma			Pro Forma			Encana			Nexen			Pro Forma			Pro Forma
	Ltd.			Inc.			Partnership			Ltd.			Assets			Other			Sub Total			Total			Assets			Assets			Adjustments			Total
							(note 4g)			(note 4f)			(note 4a)
Revenue
Oil and gas sales	$	102,019		$	17,344		$	16,851		$	5,439		$	(12,493	)	$	—		$	129,160		$	255,791		$	100,896		$	112,001		$	—		$	597,848

Royalties expense, net of ARTC	(24,262		)	(2,990		)	(3,990		)	(1,237		)	3,178			—			(29,301		)	(51,405		)	(4,999		)	(22,730		)	—			(108,435		)
Other	—			—			45			—			—			—			45			—			—			—			—			45
	77,757			14,354			12,906			4,202			(9,315		)	—			99,904			204,386			95,897			89,271			—			489,458

Expenses:
Operating and transportation	18,895			4,513			2,016			810			(3,075		)	—			23,159			62,209			17,926			15,700			—			118,994
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		)(4a),(4c)	49,636			93,490			—			—			88,216		(4c)	231,342
Accretion of ARO	685			104			23			—			—			(49)		(4a),(4c)	763			—			—			—			2,020		(4c)	2,783
Accretion of equity component of debentures –	—			—			—			—			—			—			—			—			—			—			353		(4b)	353
Interest and bank charges	2,252			286			—			155						(363		)(4b)													3,900		(4b)
																500		(4b)	2,830			11,417			—			—			7,804		(4b)	25,951
	62,356			10,883			8,299			7,444			(3,075		)	1,149			87,056			181,268			17,926			15,700			102,293			404,243


Income (loss) before income taxes	15,401			3,471			4,607			(3,242		)	(6,240		)	(1,149		)	12,848			23,118			77,971			73,571			(102,293		)	85,215

Income taxes:
Capital	2,916			12			—			—			—			274		(4d)	3,202			3,529			—			—			(2,523		)(4d)	4,208
Future income taxes (recovery)	6,080			590			755			—			—			(3,158		)(4d)	4,267			(27,926		)	—			—			(4,392		)(4d)	(28,051		)
	8,996			602			755			—			—			(2,884		)	7,469			(24,397		)	—			—			(6,915		)	(23,843		)

Net income (loss)	$	6,405		$	2,869		$	3,852		$	(3,242	)	$	(6,240	)	$	1,735		$	5,379		$	47,515		$	77,971		$	73,571		$	(95,378	)	$	109,058


Net income per unit and exchangeable share (note 4h):
Basic																																		$	1.10
Diluted																																		$	1.10

See accompanying notes to pro forma consolidated financial statements.

STARPOINT ENERGY TRUST

Notes to Pro Forma Consolidated Financial Statements

As at March 31, 2005 and for the three months then ended and the year ended December 31, 2004

(Unaudited)

(Tabular amounts in thousands of dollars)

1. Basis of presentation:

The accompanying unaudited pro forma consolidated balance sheet of StarPoint Energy Trust (“StarPoint”) as at March 31, 2005 and the unaudited pro forma consolidated statements of operations for the three months ended March 31, 2005 and the year ended December 31, 2004 (the “pro forma financial statements”) have been prepared to reflect the following:

• The acquisition of all the issued and outstanding units of APF Energy Trust (“APF”) for consideration totaling approximately $735.4 million through the issuance of 39,659,628 StarPoint units at an adjusted price of $18.54 per unit;

• The acquisition of the Encana Assets (“Encana Assets”) for cash consideration of approximately $392.0 million;

• The issuance of $60,000,000 convertible debentures at a coupon rate of 6.5 % per annum with a conversion price of $19.75 per StarPoint unit;

• The issuance of 17,800,000 StarPoint units at $18 per unit for gross proceeds totaling approximately $320.4 million.

• The acquisition of the Nexen Assets (“Nexen Assets”) for cash consideration of approximately $318.3 million; and

• The issuance of 12,000,000 StarPoint units at $18.65 per unit for gross proceeds totaling approximately $223.8 million.

The pro forma financial statements have been prepared from information derived from and should be read in conjunction with the following:

1) StarPoint’s unaudited interim consolidated financial statements as at March 31, 2005 and for the three months then ended;

2) StarPoint Energy Ltd.’s audited consolidated financial statements as at December 31, 2004 and for the year then ended;

3) E3 Energy Inc.’s (“E3”) audited consolidated financial statements as at December 31, 2004 and for the year then ended;

4) The unaudited statement of net operating revenues of the Mission Assets for the nine months ended September 30, 2004. These amounts have been adjusted to incorporate the unaudited results of these assets for the period from October 1, 2004 to December 31, 2004;

As at March 31, 2005 and for the three months then ended and the year ended December 31, 2004 (Unaudited)

(Tabular amounts in thousands of dollars)

5) The unaudited interim consolidated financial statements of the Selkirk Energy Group (“Selkirk”) as at October 31, 2004 and for the nine months then ended. These amounts have been adjusted to include the unaudited operations of Selkirk for the period from January 1, 2004 to January 31, 2004 and November 1, 2004 to December 31, 2004. Further, as StarPoint acquired Selkirk on January 28, 2005, the pro forma consolidated statement of operations for the three months ended March 31, 2005 has been adjusted to include the unaudited operations of Selkirk for the period from January 1, 2005 to January 27, 2005;

6) APF’s unaudited interim consolidated financial statements as at March 31, 2005 and for the three months then ended and audited consolidated financial statements as at December 31, 2004 and for the year then ended;

7) The unaudited schedule of revenues, royalties and operating expenses for the Encana Assets for the three months ended March 31, 2005 and the audited schedule of revenues, royalties and operating expenses for the Encana Assets for the year ended December 31, 2004;

8) The unaudited schedule of revenues, royalties and operating expenses for the Nexen Assets for the three months ended March 31, 2005 and the audited schedule of revenues, royalties and operating expenses for the Nexen Assets for the year ended December 31, 2004;

9) The audited consolidated financial statements of Upton Resources Ltd. as at December 31, 2003 and for the year then ended. As StarPoint acquired Upton on January 24, 2004 the pro forma consolidated statement of operations for the year ended December 31, 2004 has been adjusted to include the operations of Upton Resources Inc. for the period from January 1, 2004 to January 23, 2004;

10) The unaudited pro forma consolidated financial statements of APF as at March 31, 2005 and for the three months then ended and the year ended December 31, 2004; and

11) The audited financial statement of StarPoint Energy Trust as at December 31, 2004.

The pro forma financial 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 note 2 as if they had occurred on March 31, 2005. The unaudited pro forma consolidated statements of operations give effect to the transactions and assumptions in notes 2, 3 and 4 as if they had occurred on January 1, 2004. The pro forma financial 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 financial statements are in accordance with those disclosed in StarPoint’s unaudited consolidated financial statements as at March 31, 2005 and for the three months then ended and StarPoint Energy Ltd.’s audited consolidated financial statements as at December 31, 2004 and for the year then ended.

In the opinion of management of StarPoint, the pro forma financial statements include all of the necessary adjustments for the fair presentation of StarPoint.

2. Balance Sheet Adjustments (March 31, 2005):

The unaudited consolidated balance sheet as at March 31, 2005 gives effect to the following assumptions and adjustments as if they occurred on March 31, 2005:

(a) On June 27, 2005, StarPoint concluded a transaction to acquire all the issued and outstanding units of APF. For purposes of the purchase price determination, StarPoint has used the actual adjusted unit price of $18.54 per StarPoint unit and that the actual 39,659,628 StarPoint units issued. StarPoint was deemed to be the acquirer of APF and will account for the acquisition using the purchase method of accounting.

The pro forma consolidated balance sheet includes $14,228,000 in costs incurred by APF for required severance and other assumed liabilities. In addition, StarPoint has assumed $7,000,000 in unit issue costs relating to the issuance of the 39,659,628 StarPoint units to APF unitholders.

(b) On May 9, 2005, StarPoint entered into an agreement to issue 17,800,000 StarPoint units at $18 per unit for gross proceeds totaling $320.4 million, to acquire the Encana Assets.

(c) On July 18, 2005, StarPoint entered into an agreement to issue 12,000,000 StarPoint units at $18.65 per unit for gross proceeds totaling $223.8 million, to acquire the Nexen Assets.

(d) The purchase price allocations at fair value relating to the APF, Encana Assets and Nexen Assets acquisitions are as follows:

	APF			Encana Assets			Nexen Assets

Cost of acquisition:
Cash	$	—		$	392,000		$	318,250
Units issued	735,448			—			—

	$	735,448		$	392,000		$	318,250

Allocated:
Property and equipment	$	731,412		$	390,700		$	299,142
Goodwill	361,650			17,782			36,301
Working capital (including severance and other assumed liabilities totaling approximately $14,228)	(36,177		)	—			—
Convertible debentures	(53,489		)	—			—
Derivative liability	(1,304		)	—			—
Long-term debt	(158,545		)	—			—
Asset retirement fund	3,475			—			—
Asset retirement obligation	(30,727		)	(16,482		)	(17,193		)
Future income taxes	(80,847		)	—			—
	$	735,448		$	392,000		$	318,250

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 will change.

(e) The bank loan and unitholders’ capital has been adjusted to reflect the following:

(i) net proceeds totaling $304,130,000 ($320,400,000 less issue costs of $16,270,000) on the issue of 17,800,000 StarPoint units pursuant to an underwriting agreement dated May 9, 2005;

(ii) $7,000,000 of unit issue costs on the acquisition of APF;

(iii) proceeds of $57,600,000 ($60,000,000 less deferred financing costs of $2,400,000) on the issue of the convertible debentures pursuant to the agreement dated May 09, 2005 (the “StarPoint debentures”);

(iv) net proceeds totaling $212,360,000 ($223,800,000 less issue costs of $11,440,000) on the issue of 12,000,000 StarPoint units pursuant to an underwriting agreement dated July 18, 2005;

(f) The bank loan has been adjusted to reflect the repayment of APF long-term debt of $158,545,000 and the reclassification of the APF cash balance of $1,299,000.

(g) Unitholders’ capital and the convertible debenture balance have been adjusted by $1,200,000 to reflect the fair value of the conversion feature relating to the issue of $60,000,000 of the StarPoint debentures. The fair value of the conversion feature was calculated using a convertible debenture pricing model.

(h) As at June 27, 2005, APF debentures with a face value of $46,986,000 and a fair value of $53,489,000 had not been converted. Pursuant to a debenture agreement dated June 27, 2005, the APF debenture obligation was undertaken by StarPoint and has been recorded as a pro forma adjustment. Unitholders’ capital and the convertible debenture balance have been adjusted by $5,488,000 and $48,001,000, respectively. The amount recorded in unitholders’ equity reflects the fair value of the conversion feature relating to these debentures. The fair value of the conversion feature was calculated using a convertible debenture pricing model.

(i) The asset retirement obligation for StarPoint 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.

3. Statement of Operations Adjustments (Three months ended March 31, 2005):

The unaudited consolidated pro forma statement of operations for the three months ended March 31, 2005 gives effect to the following assumptions and adjustments as if they occurred on January 1, 2004:

(a) Interest expense has been adjusted to give effect to the cash portion of the consideration paid on the acquisitions of Selkirk, the Encana Assets, the Nexen Assets and the interest on the issuance of the APF and StarPoint convertible debentures less the proceeds received from the exercise of options, equity issues and the convertible debenture issue. Accretion of the equity component of the convertible debenture issue has been adjusted to give effect to the issuance of the convertible debentures.

(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 StarPoint based on the estimated proved petroleum and natural gas reserves after adjustments for the acquisitions of APF, the Encana Assets and the Nexen Assets.

(c) Capital taxes have been adjusted to reflect the increased size of StarPoint after the completion of the acquisitions of APF, the Encana Assets and the Nexen Assets.

The pro forma consolidated statement of operations has been adjusted to reflect the elimination of current income taxes which will be eliminated under the Trust structure. The future income tax provision reflects the tax impact of the pro forma adjustments in the pro forma consolidated statement of operations.

(d) No new options are assumed to be issued in the period.

(e) StarPoint acquired Selkirk on January 28, 2005. The pro forma consolidated statement of operations for the three months ended March 31, 2005 has been adjusted to incorporate the unaudited operating results for the period from January 1, 2005 to January 27, 2005.

(f) The net income per StarPoint unit and exchangeable share has been based on the following historical weighted average number of shares of StarPoint adjusted as follows:

		Three months ended March 31, 2005

Weighted average StarPoint units and exchangeable shares		29,535,473
Issued on acquisition of APF		39,659,628
Equity issues		29,800,000
Weighted average StarPoint units and exchangeable shares		98,995,101

Allocated as follows:
StarPoint units		96,868,873
Exchangeable shares		2,126,228

4. Statement of Operations Adjustments (Year ended December 31, 2004):

The unaudited consolidated pro forma consolidated statement of operations for the year ended December 31, 2004 gives effect to the following assumptions and adjustments as if they occurred on January 1, 2004:

(a) On November 26, 2004, StarPoint, E3, StarPoint Energy Trust, Mission Oil & Gas Inc. (“Mission”), StarPoint Acquisition Ltd. and StarPoint Exchangeco Ltd. entered into the Arrangement which became effective on January 7, 2005. Under the Arrangement:

(i) StarPoint Energy Ltd. issued 14,258,946 common shares at an adjusted purchase price of $4.32 per share to the shareholders of E3;

(ii) virtually all of StarPoint’s and E3’s existing producing oil and gas assets were transferred to the benefit of StarPoint Energy Trust; and

(iii) 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 and consequently accounted for the acquisition using the purchase method of accounting. The revenue, royalties and operating expenses related to the Mission Assets have been deducted from the unaudited pro forma consolidated statement of operations of StarPoint for the year ended December 31, 2004 and related adjustments have been made to depletion, depreciation and accretion and income taxes. 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.

(b) Interest expense has been adjusted to give effect to the cash portion of the consideration paid on the acquisitions of Selkirk, the Encana Assets, the Nexen Assets and the interest on the convertible debentures less the proceeds received from the exercise of options, the equity issues and convertible debenture issue. Accretion of the equity component of the convertible debenture issue has been adjusted to give effect to the issuance of the convertible debentures.

(c) 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 StarPoint based on the estimated proved petroleum and natural gas reserves after adjustments for all acquisitions.

(d) Capital taxes have been adjusted to reflect the increased size of StarPoint after the completion of the acquisitions.

(e) No new options are assumed to be issued in the period.

(f) StarPoint acquired Upton Resources Inc. on January 24, 2004. The pro forma consolidated statement of operations for the year ended December 31, 2004 has been adjusted to incorporate the unaudited operating results of Upton Resources inc. for the pre-acquisition period from January 1, 2004 to January 23, 2004.

(g) StarPoint acquired Selkirk on January 28, 2005. The pro forma consolidated statement of operations for the year ended December 31, 2004 has been adjusted to incorporate the unaudited operating results of Selkirk for the year ended December 31, 2004.

(h) The net income per StarPoint unit and exchangeable share has been based on the following historical weighted average number of shares of StarPoint adjusted for the following:

		Year ended
		December 31, 2004

StarPoint Energy Ltd. pro forma weighted average shares outstanding		79,642,000
Issued on acquisition of E3		14,258,946

		93,900,946

StarPoint 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		39,659,628
Equity issues		29,800,000
Weighted average StarPoint units and exchangeable shares		98,835,034

Allocated as follows:
StarPoint units		95,340,439
Exchangeable shares		3,494,595

CERTIFICATE OF THE TRUST

Dated: July 28, 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)	“Fred C. Coles”		(signed)	“Jim Bertram”
	Director			Director

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CERTIFICATE OF THE UNDERWRITERS

Dated: July 28, 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, to our knowledge, 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) “Shane C. Fildes”

		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) “Gregory B. Saksida”

		ORION SECURITIES INC.

		(signed) “Daniel J. Cristall”

		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) “Tom MacInnis”

	CANACCORD CAPITAL CORPORATION

		(signed) “Karl B. Staddon”

FIRST ASSOCIATES INVESTMENTS INC.		HAYWOOD SECURITIES INC.

(signed) “Terris N. Chorney”		(signed) “David G. McGorman”

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