Edgar Filing: PETROFUND ENERGY TRUST

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As filed with the Securities and Exchange Commission on November 30, 2005.

Registration No. 333-

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

FORM F-10

REGISTRATION STATEMENT UNDER
THE SECURITIES ACT OF 1933

Petrofund Energy Trust
(Exact name of Registrant as specified in its charter)

Ontario, Canada
(Province or other jurisdiction
of incorporation or organization)

1311
(Primary Standard Industrial Classification
Code Number (if applicable))

Not Applicable
(I.R.S. Employer Identification Number
(if applicable))

444-7^th Avenue S.W., Suite 600, Calgary, Alberta, Canada T2P 0X8
(403) 218-8625
(Address and telephone number of Registrant's principal executive offices)

CT CORPORATION SYSTEM
111 Eighth Avenue, 13^th Floor, New York, NY 10011
(212) 590-9331
(Name, address (including zip code) and telephone number (including area code) of agent for service in the United States)

Copies to:

Jason R. Lehner
Shearman & Sterling LLP
Commerce Court West
199 Bay Street, Suite 4405
Toronto, Ontario, Canada M5L 1E8
Telephone (416) 360-8484

Keith A. Greenfield
Burnet, Duckworth & Palmer LLP
1400, 350-7th Avenue S.W.
Calgary, Alberta, Canada
T2P 3N9
Telephone (403) 260-0100

Approximate date of commencement of proposed sale of the securities to the public: As soon as practicable after this Registration Statement is declared effective.

Province of Alberta, Canada
(Principal jurisdiction regulating this offering)

It is proposed that this filing shall become effective (check appropriate box):

A. ý	Upon filing with the Commission, pursuant to Rule 467(a) (if in connection with an offering being made contemporaneously in the United States and Canada).
B. o	At some future date (check the appropriate box below):
	1. o	pursuant to Rule 467(b) on ( ) at ( ) (designate a time not sooner than 7 calendar days after filing).
	2. o	pursuant to Rule 467(b) on ( ) at ( ) (designate a time 7 calendar days or sooner after filing) because the securities regulatory authority in the review jurisdiction has issued a receipt or notification of clearance on ( ).
	3. o	pursuant to Rule 467(b) as soon as practicable after notification of the Commission by the Registrant or the Canadian securities regulatory authority of the review jurisdiction that a receipt or notification of clearance has been issued with respect hereto.
	4. o	after the filing of the next amendment to this Form (if preliminary material is being filed).

If any of the securities being registered on this Form are to be offered on a delayed or continuous basis pursuant to the home jurisdiction's shelf prospectus offering procedures, check the following box. o

CALCULATION OF REGISTRATION FEE

Title of each class of securities to be registered		Amount to be registered		Proposed maximum offering price per subscription receipt (1)		Proposed maximum aggregate offering price		Amount of registration fee
Subscription Receipts		12,500,000		U.S.$17.23		U.S.$215,375,000		U.S.$23,045.13
Trust Units		(2)		(2)		(2)		None

(1): Estimated solely for the purpose of calculating the amount of the registration fee pursuant to Rule 457(c), based on the average of the high and low prices of the Registrant's Trust Units on the American Stock Exchange on November 23, 2005.
(2): Trust Units being registered on Form F-10 hereunder are to be sold without separate consideration.

PART I

INFORMATION REQUIRED TO BE DELIVERED TO OFFEREES OR PURCHASERS

I-1

This short form prospectus constitutes a public offering of these securities only in those jurisdictions where they may be 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.

The Underwriters have agreed not to offer, sell or deliver the Subscription Receipts offered hereunder, as part of the distribution of such Subscription Receipts at any time, within the United States or to, or for the benefit or account of, U.S. persons. Accordingly, this short form prospectus is not an offer to sell or the solicitation of an offer to buy any of these Subscription Receipts (or the Trust Units issuable pursuant to the Subscription Receipts) within the United States nor is it an offer to sell to, or the solicitation of an offer to buy from, any U.S. persons any of these Subscription Receipts (or the Trust Units issuable pursuant to the Subscription Receipts). See "Plan of Distribution".

SHORT FORM PROSPECTUS

New Issue

November 30, 2005

$250,000,000

12,500,000 Subscription Receipts,
each representing the right to receive one trust unit

Petrofund Energy Trust (the "Trust") is hereby qualifying for distribution 12,500,000 subscription receipts ("Subscription Receipts"), at a price of $20.00 each and each of which will entitle the holder thereof to receive, without payment of additional consideration, one trust unit ("Unit" or "Trust Unit") of the Trust upon closing of the acquisition (the "Acquisition") by the Trust of all of the outstanding shares of Kaiser Energy Ltd. from the Vendor (as defined herein) described in more detail under "Recent Developments — The Acquisition". The proceeds from the sale of the Subscription Receipts (the "Escrowed Funds") will be held by Computershare Trust Company of Canada, 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 January 31, 2006, the Escrowed Funds and the interest thereon will be released to the Trust and the Units will be issued to the holders of Subscription Receipts. The Trust will utilize the Escrowed Funds to pay for a portion of the purchase price of the Acquisition.

If the closing of the Acquisition does not take place by: (i) 5:00 p.m. (Calgary time) on January 31, 2006; (ii) the date upon which the Trust delivers to the Underwriters (as defined herein) a notice that the Acquisition has been terminated or that the Trust does not intend to proceed with the Acquisition; or (iii) the date that the Trust announces 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 on such amount. The Escrowed Funds will be applied towards payment of such amount.

If the closing of the Acquisition takes place prior to the Termination Time and holders of Subscription Receipts become entitled to receive Units, such holders will be entitled to receive an amount per Subscription Receipt equal to the amount per Unit of any cash distributions for which record dates have occurred during the period from the date of closing of the offering to the date immediately preceding the date the Units are issued pursuant to the Subscription Receipts. Accordingly, if the offering closes on December 6, 2005 and the Acquisition closes on December 15, 2005 as currently contemplated, holders of Subscription Receipts will be entitled to receive on December 30, 2005 an amount equal to the monthly distribution expected to be paid on December 30, 2005 to Unitholders of record on December 14, 2005. See "Details of the Offerings".

The issued and outstanding Units are listed on the Toronto Stock Exchange (the "TSX") and on the American Stock Exchange ("AMEX"). On November 15, 2005, the last trading day prior to the public announcement of the offering, the closing price of the Units was $20.57 on the TSX and U.S. $17.41 on AMEX. The TSX has conditionally approved the listing of the Subscription Receipts and the Units issuable pursuant to the Subscription Receipts on the TSX. Listing is subject to the Trust fulfilling all of the requirements of the TSX on or before February 16, 2006. The Trust has applied to list the Units issuable pursuant to the Subscription Receipts on AMEX. Listing will be subject to the Trust fulfilling all of the listing requirements of AMEX. 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 offering price of the Subscription Receipts was determined by negotiation between Petrofund Corp. ("PC") on behalf of the Trust, and CIBC World Markets Inc., on its own behalf and on behalf of National Bank Financial Inc., Scotia Capital Inc., RBC Dominion Securities Inc., TD Securities Inc., BMO Nesbitt Burns Inc., Canaccord Capital Corporation, FirstEnergy Capital Corp., GMP Securities Ltd., Raymond James Ltd., Blackmont Capital Inc., Sprott Securities Inc. and Tristone Capital Inc. (collectively, the "Underwriters").

We are permitted to prepare this prospectus in accordance with Canadian disclosure requirements, which are different from those of the United States. We prepare our financial statements in accordance with Canadian generally accepted accounting principles, and they are subject to Canadian auditing and auditor independence standards. As a result, they may not be comparable to financial statements of United States companies.

Owning the Subscription Receipts and the Trust Units may subject you to tax consequences both in the United States and Canada. This prospectus may not describe these tax consequences fully. You should read the tax discussion in "Canadian Federal Income Tax Considerations."

Your ability to enforce civil liabilities under the United States federal securities laws may be affected adversely because we are incorporated in Alberta, Canada, most of our officers and directors and all of the experts named in this prospectus are Canadian residents, and substantially all of our assets and the assets of those officers, directors and experts are located outside of the United States.

Neither the Securities and Exchange Commission nor any state securities regulator has approved or disapproved these securities, or determined if this prospectus is truthful or complete. Any representation to the contrary is a criminal offense.

Price: $20.00 per Subscription Receipt

		Price to the Public			Underwriters' Fee⁽¹⁾			Net Proceeds to the Trust⁽²⁾
Per Subscription Receipt		$	20.00		$	1.00		$	19.00
Total		$	250,000,000		$	12,500,000		$	237,500,000

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 $700,000, which will be paid from the general funds of the Trust.

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 Burnet, Duckworth & Palmer LLP and on behalf of the Underwriters by Blake, Cassels & Graydon LLP. See "Plan of Distribution".

CIBC World Markets Inc., National Bank Financial Inc., Scotia Capital Inc., RBC Dominion Securities Inc. and BMO Nesbitt Burns Inc., five of the Underwriters, are direct or indirect subsidiaries of Canadian chartered banks which are lenders to the Trust's subsidiary, PC, and to which PC is indebted. Consequently, the Trust may be considered to be a connected issuer of these Underwriters for the purposes of securities regulations in certain provinces. The net proceeds of this offering, together with borrowings under the credit facilities of PC, will be used to pay for the purchase price of the Acquisition. In addition, Scotia Capital Inc. (together with its affiliate, Scotia Waterous Inc.) was retained by the Trust in connection with the Acquisition and will receive a fee from the Trust on completion of the Acquisition. CIBC World Markets Inc. was retained by the Vendor in connection with the Acquisition and will receive a fee from the Vendor on completion of the Acquisition. See "Relationship Between PC's Lenders and the Underwriters".

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 December 6, 2005 or such other date not later than December 14, 2005 as the Trust and the Underwriters may agree. The Subscription Receipts will be represented by a global certificate issued in registered form to the Canadian Depository for Securities Limited ("CDS") or its nominee under the book-based system administered by CDS. No certificates evidencing the Subscription Receipts will be issued to subscribers for Subscription Receipts, except in certain limited circumstances, and registration will be made in the depositary service of CDS. 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 Units at levels other than those that might otherwise prevail on the open market. See "Plan of Distribution".

A return of an investor's investment in Trust Units is not comparable to the return on an investment in a fixed-income security. The recovery of an investor's initial investment is at risk and the anticipated return on an investor's investment is based on many performance assumptions. Cash distributions are not guaranteed. Although the Trust intends to make distributions of its available cash to holders of Trust Units ("Unitholders"), these cash distributions may be reduced or suspended. The actual amount distributed will depend on numerous factors, including profitability, debt covenants and obligations, fluctuations in working capital, the timing and amount of capital expenditures, applicable law and other factors beyond the control of the Trust. In addition, the market value of the Trust Units may decline if the Trust is unable to meet its cash distribution targets in the future and any such decline may be significant. See "Record of Cash Distributions" and "Risk Factors".

It is important for an investor to consider the particular risk factors that may affect the industry in which it is investing and, therefore, the stability of the distributions that Unitholders receive. See, for example the risk factors, under the heading "Risk Factors" in this prospectus and in the Trust's Renewal Annual Information Form for the year ended December 31, 2004.

The after-tax return from an investment in Trust Units to Unitholders subject to Canadian income tax can be made up of both a return on capital and a return of capital. The composition may change over time thus affecting an investor's after-tax return. Returns on capital are generally taxed as ordinary income or as dividends in the hands of a Unitholder. Returns of capital are generally tax-deferred (and reduce the Unitholder's cost base in the Trust Unit for tax purposes).

Dominion Bond Rating Service Limited ("DBRS") has assigned a stability rating of STA-5 (low) to the Trust Units. Income funds rated as STA-5 are considered by DBRS to have a weak level of stability and sustainability of distributions per unit. STA-1 is the highest DBRS rating available to units of income funds and STA-7 is the lowest DBRS rating available to units of income funds. See "Stability Rating".

The Subscription Receipts and the 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, 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

		Page
SPECIAL NOTE REGARDING FORWARD-LOOKING STATEMENTS AND OTHER DISCLOSURE		1
SELECTED ABBREVIATIONS AND DEFINITIONS		3
DOCUMENTS INCORPORATED BY REFERENCE		6
PETROFUND ENERGY TRUST		7
RECENT DEVELOPMENTS		10
INFORMATION CONCERNING THE NEW PROPERTIES		11
EFFECT OF THE ACQUISITION ON THE TRUST		23
DESCRIPTION OF THE TRUST UNITS		25
CONSOLIDATED CAPITALIZATION OF THE TRUST		26
STABILITY RATING		27
PRICE RANGE AND TRADING VOLUME OF THE UNITS		28
RECORD OF CASH DISTRIBUTIONS		28
USE OF PROCEEDS		29
DETAILS OF THE OFFERING		29
PLAN OF DISTRIBUTION		31
RELATIONSHIP BETWEEN PC'S LENDERS AND THE UNDERWRITERS		32
INTEREST OF EXPERTS		32
CANADIAN FEDERAL INCOME TAX CONSIDERATIONS		32
RISK FACTORS		37
MATERIAL CONTRACTS		38
LEGAL PROCEEDINGS		38
AUDITORS, TRANSFER AGENT AND REGISTRAR		39
CONSENT OF AUDITORS		40
CONSENT OF AUDITORS		41
OTHER SUPPLEMENTAL DISCLOSURES ABOUT OIL AND GAS ACTIVITIES (UNAUDITED)		42
DOCUMENTS FILED AS PART OF THE REGISTRATION STATEMENT		45
PRO FORMA CONSOLIDATED FINANCIAL STATEMENTS OF THE TRUST		F-1
FINANCIAL STATEMENTS OF KAISER ENERGY LTD.		F-12
FINANCIAL STATEMENTS OF THE LIMITED PARTNERSHIP		F-30
FINANCIAL STATEMENTS OF THE UNINCORPORATED ASSETS		F-41

SPECIAL NOTE REGARDING FORWARD-LOOKING STATEMENTS AND OTHER DISCLOSURE

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", "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 PC 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 and 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 size of the Trust's oil and natural gas reserves;
•: projections of market prices and costs;
•: supply and demand for oil and natural gas;
•: the Trust's expectations with respect to the Acquisition and the properties to be obtained thereunder;
•: expectations regarding the ability to raise capital and to continually add to reserves through acquisitions and development; and
•: treatment under governmental regulatory regimes.

The actual results could differ materially from those anticipated in these forward-looking statements as a result of the risk factors set forth below and elsewhere in this short form prospectus:

•: volatility in market prices for oil and natural gas;
•: liabilities inherent in oil and gas operations;
•: uncertainties associated with estimating reserves;
•: competition for, among other things, capital, acquisitions of reserves, undeveloped lands and skilled personnel;
•: incorrect assessments of the value of acquisitions, including the Acquisition;
•: geological, technical, drilling and processing problems; and
•: the other factors described under "Risk Factors" in this prospectus and in the AIF.

These factors should not be construed as exhaustive. Except as required by applicable securities laws, neither the Trust nor PC undertakes any obligation to publicly update or revise any forward-looking statements.

Certain Financial Reporting Measures

The Trust uses cash flow (before changes in non-cash working capital) to analyze operating performance and leverage. Cash flow (before changes in non-cash working capital) and cash flow from operations before changes in working capital and before settlement of asset retirement obligations as presented does not have any standardized meaning prescribed by Canadian generally accepted accounting principles ("GAAP") and may not be comparable with the calculation of similar measures for other entities. Cash flow (before changes in non-cash working capital) and cash flow from operations before changes in working capital and before settlement of asset retirement obligations as presented is not intended to represent operating cash flows or operating profits for the period, nor should it be viewed as an alternative to cash provided by operating activities, net earnings or other

measures of financial performance calculated in accordance with Canadian GAAP. All references to cash flow (before changes in non-cash working capital) and cash flow from operations before changes in working capital and before settlement of asset retirement obligations are based on cash flow from operating activities before changes in non-cash working capital or before changes in working capital and before settlement of asset retirement obligations, as applicable.

The Trust also uses "net debt". Net debt as presented does not have any standardized meaning prescribed by Canadian GAAP and may not be comparable with the calculation of similar measures for other entities. Net debt as used by the Trust is calculated as bank debt and any working capital deficit excluding the current portion of derivative contracts.

The Trust uses certain key performance indicators and industry benchmarks such as operating netbacks ("netbacks"), finding, development and acquisition costs ("FD&A"), and total capitalization to analyze financial and operating performance. These performance indicators and benchmarks as presented do not have any standardized meaning prescribed by Canadian GAAP and, therefore, may not be comparable with the calculation of similar measures for other entities.

When the measures noted above are used, they have been footnoted and the footnote to the applicable measure notes that the measure is "non-GAAP" and contains a description of how to reconcile the measure to the applicable financial statements. These measures should be given careful consideration by the reader.

SELECTED ABBREVIATIONS AND DEFINITIONS

In this short form prospectus, the following terms shall have the meanings set forth below, unless otherwise indicated:

"Acquisition" means the acquisition of all of the outstanding shares of KEL from the Vendor pursuant to the Purchase Agreement.

"AIF" means the Renewal Annual Information Form of the Trust dated March 15, 2005.

"AMEX" means the American Stock Exchange.

"Board" or "Board of Directors" means the board of directors of PC.

"Business Day" means a day, other than a Saturday, Sunday or statutory holiday, when banks are generally open in the City of Calgary, in the Province of Alberta, for the transaction of banking business.

"CDS" means The Canadian Depositary for Securities Limited.

"Closing" means the closing of the sale of Subscription Receipts offered by this prospectus.

"Current Credit Facilities" has the meaning given to such term in Note (1) to the table under the heading "Consolidated Capitalization of the Trust".

"DBRS" means Dominion Bond Rating Service.

"DPSP" means deferred profit sharing plan as defined in the Tax Act.

"Distribution Record Date" means in respect of any distribution, the day on which Unitholders are identified for purposes of determining entitlement to such distribution.

"Escrow Agent" means Computershare Trust Company of Canada or its successor as escrow agent under the Subscription Receipt Agreement.

"Escrowed Funds" means the proceeds from the sale of the Subscription Receipts.

"Exempt Plans" means, collectively, RRSPs, RESPs, RRIFs and DPSPs.

"GLJ" means GLJ Petroleum Consultants Ltd.

"GLJ Report" means the report of GLJ dated August 12, 2005 evaluating the crude oil, NGL and natural gas reserves attributable to the New Properties as at July 1, 2005.

"Internalization Transaction" means the transaction approved at the annual and special meeting of Unitholders held on April 16, 2003 under which management of the Trust was internalized through the acquisition by PC of all of the issued and outstanding shares of Previous Manager and the consequent elimination of all management, acquisition and disposition fees payable to Previous Manager.

"KEL" means Kaiser Energy Ltd., a private company, all of the outstanding shares of which will be acquired by PC pursuant to the Purchase Agreement.

"Limited Partnership" means Canadian Acquisition Limited Partnership, a Delaware limited partnership, all of the interests in which will be acquired by a wholly-owned subsidiary of KEL prior to the closing of the Acquisition.

"New Credit Facilities" has the meaning given to such term in Note (1) to the table under the heading "Consolidated Capitalization of the Trust".

"New Properties" means the oil and natural gas properties and related assets to be acquired indirectly by PC pursuant to the Purchase Agreement, described in more detail under the heading "Information Concerning the New Properties".

"PC" means Petrofund Corp.

"PC Exchangeable Shares" means non-voting exchangeable shares in the capital of PC.

"PC Royalty Agreement" means the amended and restated royalty agreement dated as of November 16, 2004 between PC and the Trust.

"Previous Manager" means NCE Petrofund Management Corp., the previous manager of the Trust.

"Purchase Agreement" means the agreement of purchase and sale dated November 16, 2005 among the Vendor and PC providing for the acquisition of KEL by PC as described under the heading "Recent Developments — The Acquisition".

"PVT" means Petrofund Ventures Trust, formerly Ultima Ventures Trust.

"PVT Royalty Agreement" means the amended and restated royalty agreement dated June 23, 1999 between Ultima Ventures Corp. and Trust Company of the Bank of Montreal in its capacity as trustee of Ultima, as amended.

"Reclassification" means the proposed reclassification of trust unit capital of the Trust as defined and further described under "Petrofund Energy Trust — General Development of the Business", which reclassification has not been implemented.

"RESP" means registered education savings plan as defined in the Tax Act.

"RRIF" means registered retirement income fund as defined in the Tax Act.

"RRSP" means registered retirement savings plan as defined in the Tax Act.

"Special Resolution" means a resolution approved in writing by Unitholders holding not less than 66²/3% of the outstanding Trust Units or passed by a majority of not less than 66²/3% of the votes cast, either in person or by proxy, at a meeting of the Unitholders called for the purpose of approving such resolution.

"Subscription Receipt Agreement" means the agreement to be dated the date of closing of the offering between the Trust, CIBC World Markets Inc. on behalf of the Underwriters and the Escrow Agent governing the terms of the Subscription Receipts.

"Subscription Receipts" means the subscription receipts of the Trust offered hereby.

"Tax Act" means Income Tax Act (Canada), as amended.

"Termination Time" means the earliest of: (i) 5:00 p.m. (Calgary time) on January 31, 2006; (ii) the date upon which the Trust delivers to the Underwriters a notice that the Acquisition has been terminated or that the Trust does not intend to proceed with the Acquisition; or (iii) the date that the Trust announces to the public that it does not intend to proceed with the Acquisition.

"Trust" means Petrofund Energy Trust.

"Trustee" means Computershare Trust Company of Canada, the trustee of the Trust.

"Trust Indenture" means the trust indenture pursuant to which the Trust is organized, currently being the amended and restated trust indenture made as of November 16, 2004 between PC and the Trustee.

"Trust Unit" or "Unit" means a trust unit created pursuant to the Trust Indenture and representing a fractional undivided interest in the Trust.

"TSX" means the Toronto Stock Exchange.

"Ultima" means Ultima Energy Trust.

"Ultima Combination Agreement" means the combination agreement dated March 29, 2004, as amended, between Ultima, Ultima Ventures Corp., the Trust and PC providing for the Ultima Merger.

"Ultima Merger" means the business combination of the Trust and Ultima pursuant to which Ultima transferred all of its assets to the Trust in consideration for Trust Units of the Trust, the Trust assumed all of the liabilities of Ultima and Ultima distributed the Trust Units of the Trust received by it to Ultima Unitholders upon, and in consideration for, the redemption of all of the outstanding Ultima Units (other than one Ultima Unit which was held by the Trust).

"Ultima Unitholders" means holders of Ultima Units.

"Ultima Units" means trust units of Ultima.

"Unitholder" means a holder from time to time of Trust Units.

"Underwriters" means CIBC World Markets Inc., National Bank Financial Inc., Scotia Capital Inc., RBC Dominion Securities Inc., TD Securities Inc., BMO Nesbitt Burns Inc., Canaccord Capital Corporation, FirstEnergy Capital Corp., GMP Securities Ltd., Raymond James Ltd., Blackmont Capital Inc., Sprott Securities Inc. and Tristone Capital Inc.

"Underwriting Agreement" means the agreement dated as of November 18, 2005 among the Trust, PC and the Underwriters in respect of this offering.

"Unincorporated Interests" means oil and natural gas properties held by certain individuals and trusts and by the Vendor which are to be acquired by KEL prior to the closing of the Acquisition.

"United States" or "U.S." means the United States of America.

"Vendor" means Kaiser-Francis Oil Company of Canada.

"bbl" means one barrel

"bbls" means barrels

"bbls/d" means barrels per day

"bcf" means one billion cubic feet

"boe" means barrels of oil equivalent. A barrel of oil equivalent is determined by converting a volume of natural gas to barrels using the ratio of six mcf to one barrel. Boes may be misleading, particularly if used in isolation. The boe conversion ratio of 6 mcf:1 bbl is based on an energy equivalency method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead.

" boe/d" means barrels of oil equivalent per day

" mbbls" means one thousand barrels

" mboe" means one thousand barrels of oil equivalent

" mcf" means one thousand cubic feet

" mmcf" means one million cubic feet

" mmcf/d" means one million cubic feet per day

" NGL" or "NGLs" means natural gas liquids

" $m" or "m$" means thousands of dollars

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.

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 Corporate Secretary of PC at Suite 600, 444 - 7^th Avenue S.W., Calgary, Alberta, T2P 0X8 (telephone number (403) 218-8625). 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 Corporate Secretary of PC at the above mentioned address and telephone number. In addition, copies of the documents incorporated herein by reference may be obtained from the securities commissions or similar authorities in Canada through the SEDAR website at www.sedar.com. The Trust's SEDAR profile number is 2835.

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

(a): the Renewal Annual Information Form of the Trust dated March 15, 2005;
(b): the audited comparative consolidated financial statements and notes thereto of the Trust as at December 31, 2004 and 2003 and for each of the years in the three-year period ended December 31, 2004, together with the report of the auditors thereon dated March 1, 2005;
(c): management's discussion and analysis of the financial condition and operating results of the Trust for the year ended December 31, 2004;
(d): the unaudited interim comparative consolidated financial statements of the Trust for the nine months ended September 30, 2005 and 2004;
(e): management's discussion and analysis of the financial condition and operating results of the Trust for the nine months ended September 30, 2005;
(f): the Information Circular of the Trust dated February 28, 2005 relating to the annual meeting of Unitholders held on April 13, 2005 (excluding those portions thereof which appear under the headings "Report on Executive Compensation", "Performance Graph" and "Statement of Corporate Governance Practices");
(g): the audited comparative consolidated financial statements and notes thereto of Ultima Energy Trust for the fiscal years ended December 31, 2003 and 2002, together with the report of the auditors thereon dated February 24, 2004 (except as to Notes 14 and 15 which are as of April 30, 2004) which are contained in the Information Circular of Ultima Energy Trust dated April 30, 2004; and
(h): the unaudited interim comparative consolidated financial statements of Ultima Energy Trust for the three months ended March 31, 2004 and 2003.
(i): the material change report of the Trust dated November 25, 2005 in respect of, among other things, the Acquisition.

Any material change report and any document of the type referred to in the preceding paragraph (excluding confidential material change reports and excluding portions of information circulars 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 the provinces of 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 into 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 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.

PETROFUND ENERGY TRUST

General

The Trust is an open-ended investment trust created under the laws of the Province of Ontario on December 18, 1988 under the name "NCE Petrofund I". Active operations commenced March 3, 1989. On July 4, 1996, the name of the Trust was changed to "NCE Petrofund" and on November 1, 2003 the name was changed to its present name of "Petrofund Energy Trust". Effective September 7, 2001, the Trustee became the trustee of the Trust. The Trust is currently governed by the Trust Indenture. The executive office, head office and operations of the Trust are located at Suite 600, 444 - 7th Avenue S.W., Calgary, Alberta, T2P 0X8.

The Trust's primary source of income is from 99% net royalty interests granted by PC pursuant to the PC Royalty Agreement and by PVT pursuant to the PVT Royalty Agreement. The Trust may also purchase directly or indirectly securities of oil and gas companies, oil and gas properties and other related assets.

PC, formerly named NCE Petrofund Corp., was incorporated under the Business Corporations Act (Alberta) on March 17, 1988. PC acquires and manages producing oil and gas properties in western Canada. Pursuant to the PC Royalty Agreement, the Trust receives a 99% net royalty interest in the oil and gas properties of PC. All of the issued and outstanding voting shares of PC are held by the Trust. The capital structure of PC also includes PC Exchangeable Shares. As at September 30, 2005 there were 402,618 PC Exchangeable Shares issued and outstanding, which were issued in connection with the Internalization Transaction. As at September 30, 2005, the PC Exchangeable Shares were exchangeable into 539,147 Trust Units based on a ratio which is adjusted on each date that the Trust pays a distribution to its Unitholders. The PC Exchangeable Shares are not listed securities on any stock exchange. See "Capital Structure of PC" in the AIF for a description of the attributes of the PC Exchangeable Shares.

PVT is a trust created under the laws of the Province of Alberta on August 31, 1997. Following completion of the Ultima Merger, the sole beneficiary of PVT is the Trust. PVT was established for the purpose of, and its business is restricted to, purchasing, holding, operating and divesting petroleum, natural gas and related hydrocarbons and related facility interests including the development of petroleum and natural gas, the transportation, processing, marketing and sale thereafter and all business operations incidental or in anyway related to the foregoing. PC is presently the trustee of PVT. Pursuant to the PVT Royalty Agreement, the Trust receives a 99% net royalty interest in the oil and gas properties of PVT.

Each Trust Unit represents an equal undivided beneficial interest in the assets of the Trust. Historically, the Trust's activities have been focused on the acquisition of net royalties from PC and, more recently, from PVT. For each property for which a net royalty is granted by PC or PVT, the Trust receives 99% of the revenue generated by the property net of operating costs, debt service charges, general and administrative costs and certain other taxes and charges. The Trust distributes to its Unitholders a majority of its cash flow in the form of monthly distributions, part of which is on a tax-advantaged basis. Cash flow includes royalty income and may include cash flow generated by properties and interests not currently subject to the Trust's net royalty interests.

The following are the name, the percentage of voting securities and the jurisdiction governing the Trust's material subsidiaries and trusts, either direct or indirect, as at the date hereof:

		Percentage of voting securities (directly or indirectly)		Nature of Entity		Jurisdiction of Incorporation/ Formation
Petrofund Corp.		100%		Corporation		Alberta
Petrofund Ventures Trust		100%		Trust		Alberta

General Development of the Business

The Trust was initially formed as a closed-end royalty trust for the purposes of acquiring royalty interests from PC. Effective February 2, 1999, the Trust was converted to an open-ended investment trust. On that date, the Trust Indenture, PC Royalty Agreement and related agreements were amended to: (i) permit the Trust and PC to acquire, directly or indirectly, interests in resource issuers and/or resource properties and other related assets; (ii) remove certain financing restrictions applicable to the Trust and PC to permit the Trust and PC, subject to certain limitations, to raise or issue capital in connection with, or to finance, such acquisitions, either through the issuance of Trust Units or other equity or debt securities of the Trust or PC or through borrowing;

and (iii) provide that Unitholders have the right to cause the Trust to redeem their Trust Units in certain circumstances.

Effective November 1, 2000, the Trust acquired all of the issued and outstanding shares of PC from a subsidiary of the Previous Manager for nominal consideration, resulting in PC becoming a wholly-owned direct subsidiary of the Trust. This change simplified the structure of the Trust and related entities and allows the Trust to present consolidated financial statements which fully reflect the assets and liabilities of the Trust and PC.

In conjunction with PC becoming a wholly-owned subsidiary of the Trust, the corporate governance of the Trust was changed so that the stewardship of the Trust and PC was undertaken by the Board of Directors of PC.

On March 10, 2003, the Trust entered into an agreement to internalize its management structure such that the Previous Manager, the then manager of the Trust, became a wholly-owned subsidiary of PC. Unitholder and regulatory approval of the Internalization Transaction was received at the annual and special meeting of Unitholders held on April 16, 2003. As a result of the Internalization Transaction, all management, acquisition and disposition fees payable to the Previous Manager were eliminated effective January 1, 2003. The cost of the Internalization Transaction was $30.9 million, including $2.5 million of transaction costs. The purchase price for the shares of the Previous Manager was satisfied by the issuance of 1,939,147 PC Exchangeable Shares plus a cash amount per PC Exchangeable Share equal to the distributions paid or payable per Trust Unit by the Trust to Unitholders of record from and after January 1, 2003 up to and including the closing date. In addition, at closing, PC paid $3.4 million in cash to fund the repayment of a debt owing by the Previous Manager and, in addition, certain senior executives of the Previous Manager were paid $780,000 in cash and issued 100,244 Trust Units plus an amount per Trust Unit equal to the distributions per Trust Unit paid to Unitholders of record of Trust Units during the period commencing on January 1, 2003 and ending on the closing date.

Management of the Trust is presently carried out by directors, officers and other employees of PC.

On June 16, 2004, pursuant to the Ultima Combination Agreement, the Trust completed the acquisition of Ultima, a royalty trust listed on the TSX. Pursuant to the Ultima Merger, the Trust acquired all of the assets of Ultima (which included the PVT Royalty Agreement, a 99% royalty payable by Ultima Energy Inc. to Ultima, all of the outstanding units of Ultima Ventures Trust and all of the shares of Ultima's corporate subsidiaries) and assumed all of the liabilities of Ultima and former Ultima Unitholders became holders of Trust Units on the basis of 0.442 of a Trust Unit for each issued and outstanding Ultima Unit. The total price of the transaction was $563.1 million comprised of 26.4 million Trust Units with an assigned value of $452.8 million, the assumption of $104.4 million of debt and net working capital, and transaction costs of $1.9 million. The properties of Ultima included properties located in the Weyburn, Spirit River, Cherhill, Kerrobert and Westerose areas. Over 50% of the production was operated by Ultima and such production is now operated by PC. Approximately 50% of Ultima's production and reserves were common with or adjacent to PC's properties.

Immediately following the completion of the Ultima Merger on June 16, 2004, PC acquired from the Trust all of the shares of Ultima Energy Inc. Ultima Energy Inc. was then amalgamated with PC and the amalgamated company continued under the name "Petrofund Corp".

On June 30, 2004 PC acquired from the Trust all of the shares of Ultima Corp., Ultima Acquisitions Corp. and Ultima Management Inc. and all of such companies were wound up into PC and have since been dissolved. Also on June 30, 2004, PC became the trustee of Ultima Ventures Trust and Ultima Ventures Trust's name was changed to "Petrofund Ventures Trust".

At a special meeting of Unitholders held on November 16, 2004, Unitholders approved a reclassification of the trust unit capital of the Trust (the "Reclassification") into two new classes of Trust Units: Class R units and Class N units. The principal distinctions of the Class R units and the Class N units as compared to the existing Trust Units relate to who would be entitled to hold and to trade in the respective classes on the basis of residency in Canada for purposes of the Tax Act. The purpose of the Reclassification was to change the structure and procedures that regulate non-resident ownership of trust units of the Trust to ensure that the Trust continued to qualify as a mutual fund trust under the Tax Act. On December 6, 2004, the Minister of Finance for the Government of Canada announced that the previously announced proposed amendments to the Tax Act that were introduced in the March, 2004 Canadian federal budget relating to non-resident ownership of mutual fund trusts would be suspended and further public consultation undertaken prior to implementation of any amendment to the Tax Act in this regard. As a result of such announcement by the Minister of Finance, the Trust

determined not to implement the Reclassification. See "Canadian Federal Income Tax Considerations — The Trust — Status of the Trust".

In accordance with the approval of Unitholders which was obtained at the Special Meeting of Unitholders held on November 16, 2004, a number of amendments were made to the Trust Indenture as well as the PC Royalty Agreement, all effective November 16, 2004. Such amendments consisted of: (a) deleting the acquisition criteria which are contained in the PC Royalty Agreement which must be adhered to in respect of direct acquisitions of oil and gas properties; (b) amending the Trust Indenture to remove the present requirement that amendments to the PC Royalty Agreement (and any other royalty agreements) be approved by Unitholders and to add to the powers delegated to PC in the Trust Indenture the responsibility and authority for approving the entering into and the amendment of the provisions of royalty agreements; (c) expanding the definition of "Exchangeable Shares" which is contained in the Trust Indenture to include, in addition to shares in the capital of PC or an affiliate which are by their terms exchangeable into Trust Units, interests in a partnership in which PC or an affiliate of PC is the managing partner or interests in a limited partnership in which PC or an affiliate of PC is the general partner which are, by their terms, exchangeable into one or more classes of Trust Units; (d) amending certain of the provisions contained within Article 5 of the Trust Indenture, which article provides Unitholders with the right to require the Trustee to retract, at any time or from time to time, at the demand of the Unitholder all or any part of the Trust Units registered in the name of the Unitholder at the price determined, and payable, in accordance with the Trust Indenture; and (e) amending the Trust Indenture to provide that the Trustee will mail to each Unitholder within 90 days after the end of each calendar year, the audited financial statements of the Trust for such year, together with a report of the auditor thereon and for the Trustee to mail to each Unitholder within 45 days after the end of each quarter unaudited financial statements of the Trust for such quarter. In addition, effective November 16, 2004 each of the PC Royalty Agreement and the Ultima Royalty Agreement were amended by terminating such agreements and replacing them with one agreement, that being the PC Royalty Agreement.

The following chart shows the structure of the Trust and its material subsidiaries at the date hereof:

Notes:

(1): As at September 30, 2005, the Trust had a total of 402,618 PC Exchangeable Shares outstanding that were exchangeable for 539,147 Trust Units.
(2): Held by Petrofund Corp. as trustee for Petrofund Ventures Trust.

RECENT DEVELOPMENTS

Recent Acquisitions

To date in 2005, the Trust has completed four minor acquisitions, all adjacent to existing operations of the Trust, primarily in Alberta and northeastern British Columbia. The total purchase price for the acquisitions was $73.8 million, subject to adjustments. These acquisitions are expected to add approximately 1,650 boepd of production to the Trust. Based on the Trust's internal estimates, the properties acquired have been assigned proved plus probable reserves of 4.6 million boe.

Potential Acquisitions

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

The Acquisition

On November 16, 2005, PC entered into the Purchase Agreement with the Vendor providing for the acquisition of all of the outstanding shares of KEL for the purchase price of approximately $485 million in cash, subject to interim period adjustments. The Acquisition will have an effective date of December 1, 2005 and is expected to close on December 15, 2005. Pursuant to the Purchase Agreement, PC paid a deposit of $48.5 million to the Vendor, which amount will be credited to the purchase price in the event that the Acquisition is completed and will be retained by the Vendor if the Acquisition is not completed under certain circumstances, including breach by PC of its representations and warranties contained in the Purchase Agreement and failure by PC to perform its covenants contained in the Purchase Agreement. See "Risk Factors — Possible Failure to Complete the Acquisition".

KEL holds (or will hold prior to the completion of the Acquisition), either directly or indirectly, interests in the New Properties, which consist primarily of natural gas assets located in Alberta, and which had average gross production for the six months ended June 30, 2005 of approximately 5,800 boe/d. The New Properties also include undeveloped lands located in Alberta. See "Information Concerning the New Properties".

Conditions to closing of the Acquisition include standard conditions for transactions of this nature including the following: the continued accuracy of representations and warranties in the Purchase Agreement (provided PC's losses caused by any breaches of representations and warranties of the Vendor must exceed $5 million in aggregate for PC not to close for reason of such breaches); the performance of covenants contained in the Purchase Agreement; the delivery of closing documents; title due diligence satisfactory to PC; and receipt of regulatory approvals. If PC fails to complete the Acquisition as a result of the breach by the Vendor of its representations and warranties contained in the Purchase Agreement, PC is entitled to recover from the Vendor its costs and expenses resulting from such breach up to a maximum of $10 million.

In connection with the Acquisition, the Vendor has agreed to indemnify PC in respect of tax liabilities that relate to the period prior to the date that the Acquisition is completed (provided that such liabilities exceed $5 million) and liabilities relating to breaches of representations and warranties of Vendor contained in the Purchase Agreement (provided that individual breaches exceed $200,000 and provided that all of such breaches exceed $5 million). PC has also agreed to indemnify the Vendor in respect of all past, present and future environmental liabilities relating to the New Properties.

Pursuant to the Purchase Agreement a number of reorganization transactions will be completed prior to the completion of the Acquisitions, which transactions will result in, among other things: (1) KEL acquiring, through a wholly-owned subsidiary, all of the interests in the Limited Partnership; (2) KEL acquiring all of the Unincorporated Assets; and (3) KEL disposing of certain oil and natural gas assets which are presently held by it (the "Excluded Assets"). The financial statements for KEL which are included in this short form prospectus include the Excluded Assets and the results from the operation of such assets. Average gross production from

the Excluded Assets for the six months ended June 30, 2005, was approximately 450 boe/d. The New Properties do not include the Excluded Assets and were not evaluated by GLJ or included in the GLJ Report.

INFORMATION CONCERNING THE NEW PROPERTIES

Certain information in this short form prospectus in respect of the New Properties has been taken from information provided by the Vendor.

Drilling History

The following table sets forth the number of gross and net wells that were drilled on the New Properties during the periods indicated:

	Nine Months Ended September 30, 2005		Year Ended December 31, 2004
	Gross⁽¹⁾	Net⁽²⁾	Gross⁽¹⁾	Net⁽²⁾
Oil Wells	4	—	10	1.0
Gas Wells	25	7.7	38	18.2
Other	12	2.0	2	—
Dry and Abandoned⁽³⁾	1	0.3	—	—

Total	42	10.0	50	19.2

Notes:

(1): "Gross" wells are defined as the total number of wells in which the Trust will acquire an interest pursuant to the Acquisition.
(2): "Net" wells are defined as the aggregate of the numbers obtained by multiplying each gross well by the percentage working interest therein to be acquired by the Trust.
(3): "Dry" refers to a well that is not productive. A productive well is a well which is capable of producing hydrocarbons in quantities considered by the operator to be sufficient to justify the costs required to complete, equip and produce the well.

Oil and Gas Wells

The following table sets forth the number and status of wells in which the Trust will acquire a material royalty or working interest effective September 30, 2005, which were producing or which the Vendor considered to be capable of production which will be acquired pursuant to the Acquisition:

	Producing				Shut-in⁽¹⁾
	Crude Oil		Natural Gas		Crude Oil		Natural Gas
	Gross⁽²⁾	Net⁽³⁾	Gross⁽²⁾	Net⁽³⁾	Gross⁽²⁾	Net⁽³⁾	Gross⁽²⁾	Net⁽³⁾
Alberta	50	5.9	376	174.6	8	0.2	139	56.3

Notes:

(1): "Shut in" wells means wells which have encountered and are capable of producing crude oil or natural gas but which are not producing due to lack of available transportation facilities, available markets or other reasons.
(2): "Gross" wells are defined as the total number of wells in which the Trust will acquire an interest pursuant to the Acquisition.
(3): "Net" wells are defined as the aggregate of the numbers obtained by multiplying each gross well by the percentage working interest therein to be acquired by the Trust.

Principal Producing Properties

The following is a description of the principal properties comprising the New Properties on production or under development as at September 30, 2005. The term "gross", when used to describe the share of production of the New Properties, means the aggregate of the Vendor's working interest share to be acquired by the Trust before deduction of royalties owned by others. Reserve amounts are stated, before deduction of royalties, at July 1, 2005, based on forecast cost and price assumptions as evaluated in the GLJ Report. See "Information

Concerning the New Properties — Statement of Reserves Data and Other Oil and Gas Information for the New Properties". The following information in respect of gross and net acres of land is as at September 30, 2005 and information in respect of production is gross for the New Properties and is as at June 30, 2005 except where otherwise indicated. The reserves set forth in the principal property description and the table below are as presented in the GLJ Report. Such additional reserves are set forth on a consolidated basis in the oil and natural gas reserve tables set forth under the heading "Information Concerning the New Properties — Statement of Reserves Data and Other Oil and Gas Information for the New Properties". The estimates of reserves for individual properties may not reflect the same confidence level of estimates of reserves for all properties due to the effect of aggregation. All of the New Properties' proved producing reserves were on production on June 30, 2005.

Berland River

The Berland River area is located approximately 130 kilometres south east of Grande Prairie, Alberta. The Trust will acquire an average 70% working interest in approximately 23,000 gross acres (approximately 16,200 net acres) of land in this area of which approximately 5,000 net acres are undeveloped. This area has multi-zone potential from the Bluesky, Gething, Cadomin, Falher, Viking and Dunvegan formations. Twenty new drilling locations have been identified on these lands to target multiple pay potential. The average gross production from this property for the six months ended June 30, 2005 was 8.4 mmcf/d of natural gas, 68 bbls/d of crude oil and 83 bbls/d of NGLs which totals to over 25% of the New Properties' production for such period. The GLJ Report assigned proved reserves of 17.6 bcf of natural gas, 310 mbbls of NGLs and 31 mbbls of light and medium oil. In addition, probable reserves of 6.2 bcf of natural gas, 99 mbbls of NGLs and 22 mbbls of light and medium oil have been assigned.

Strachan

The Strachan area is located approximately 120 kilometres west of Red Deer, Alberta. The Trust will acquire an average 58% interest in approximately 22,700 gross acres (approximately 13,100 net acres) of land in this area including approximately 5,500 net undeveloped acres. The producing formations in this area range from the deep, sour Devonian Leduc and Nisku reefs through the sweet Cretaceous Ellerslie, Ostracod, Glauconitic, Viking and Cardium. One well is planned on this property before year end targeting the Glauconitic zone, and up to ten locations have been identified to drill for multiple pay potential in 2006 and future years. The average gross production from this property for the six months ended June 30, 2005 was 4.5 mmcf/d of natural gas, 111 bbls/d of NGLs and 2 bbls/d of crude oil. The GLJ Report assigned proved reserves of 10.3 bcf of natural gas and 252 mbbls of NGLs and additional probable reserves of 5.7 bcf of natural gas, 141 mbbls of NGLs and 48 mbbls of light and medium oil. The Strachan area is an existing core area for the Trust and, as such, the Trust expects there to be an opportunity to realize significant synergies associated with its and KEL's operations in this area.

Herronton

The Herronton area is located approximately 50 kilometres southeast of Calgary, Alberta. The Trust will acquire an average 82% working interest in approximately 60,700 gross acres (approximately 49,800 net acres) of land in the Herronton area of which approximately 9,100 net acres are undeveloped. Most of the production from this area comes from the Turner Valley carbonates or the Mannville and Belly River sands. The potential for coal bed methane production will be tested early next year in five recently recompleted wells. The average gross production from this property for the six months ended June 30, 2005 was 5.1 mmcf/d of natural gas and 8 bbls/d of NGLs. The GLJ Report assigned proved reserves of 11.5 bcf of natural gas, 42 mbbls of NGLs and 1 mbbl of light and medium oil. In addition, probable reserves of 3 bcf of natural gas, 4 mbbls of NGLs and 1 mbbl of light and medium oil have been assigned.

Drumheller

The Drumheller area is located approximately 100 kilometres northeast of Calgary, Alberta. The Trust will acquire an average 47% working interest in approximately 26,300 gross acres (approximately 12,300 net acres) of land in this area including approximately 3,500 net undeveloped acres. Activity in this area is high due to the current trend to downspace from one well per section to two wells per section for many gas bearing formations.

28 locations have been identified on these lands for this purpose. The main producing zones in the area are Medicine Hat, Belly River, Viking, Basal Colorado, Glauconitic and Ellerslie. The average gross production from this property for the six months ended June 30, 2005 was 2.1 mmcf/d of natural gas, 30 bbls/d of light and medium oil and 14 bbls/d of NGLs. The GLJ Report assigned proved reserves of 8.0 bcf of natural gas, 18 mbbls of light and medium oil and 71 mbbls of NGLs. In addition, probable reserves of 1.8 bcf of natural gas, 5 mbbls of light and medium oil and 12 mbbls of NGLs have been assigned.

Sugden

The Sugden area is located approximately 150 kilometres northeast of Edmonton, Alberta. The Trust will acquire an average 46% working interest in approximately 83,500 gross acres (approximately 38,800 net acres) of land in this area of which approximately 18,300 net acres is undeveloped. The main producing zones are Colony, Clearwater, McLaren and Viking. Seven drilling locations targeting Mannville and Viking gas have been selected and an additional 16 potential locations for Viking gas have been identified. The average gross production from this property for the six months ended June 30, 2005 was 3.4 mmcf/d of natural gas. The GLJ Report assigned proved reserves of 6.6 bcf of natural gas and additional probable reserves of 3.3 bcf of natural gas.

Ribstone

The Ribstone area is located approximately 200 kilometres southeast of Edmonton, Alberta. The Trust will acquire an average 59% working interest in approximately 14,900 gross acres (approximately 8,700 net acres) of land in the area including approximately 1,500 net undeveloped acres. The main producing zones are Colony, Sparky and Viking. There is potential for infill drilling in the Colony pools in the area. The average gross production from this property for the six months ended June 30, 2005 was 1.8 mmcf/d of natural gas and 17 bbls/d of heavy crude oil. The GLJ Report assigned proved reserves of 6.2 bcf of natural gas and 14 mbbls of heavy oil. In addition, probable reserves of 1.6 bcf of natural gas and 62 mbbls of heavy oil have been assigned.

Certain information in respect of the principal properties comprising the New Properties is set forth in the following table:

Property Name	Operator	Average Working Interest	Major Product	Average Gross Production⁽¹⁾	Gross Proved plus Probable Reserves⁽²⁾
				(mboe)	(mboe)
Berland River	KEL	70%	gas and oil	1,555	4,425
Strachan	KEL and PC	58%	gas	863	3,112
Herronton	KEL	82%	gas	864	2,450
Drumheller	KEL and Others	47%	gas and oil	400	1,748
Sugden	KEL	46%	gas	559	1,649
Ribstone	KEL	59%	gas	315	1,382
Others	Various	30%	gas and oil	1,244	6,069

Total				5,800	20,835

Notes:

(1): Average for the six months ended June 30, 2005.
(2): As at July 1, 2005, based on the GLJ Report and based on forecast cost and price assumptions.

Undeveloped Lands

The following table summarizes the undeveloped land holdings, in acres, as at September 30, 2005 associated with the New Properties.

		Gross⁽¹⁾		Net⁽²⁾		Average Working Interest
Alberta		102,165		55,109		54%

Notes:

(1): "Gross" refers to the total acres in which the Trust will acquire an interest pursuant to the Acquisition. See "Statement of Reserves Data and Other Oil and Gas Information for the New Properties — Definitions and Other Notes" below.

(2): "Net" refers to the total acres in which the Trust will acquire an interest, multiplied by the percentage working interest therein to be acquired. See "Statement of Reserves Data and Other Oil and Gas Information for the New Properties — Definitions and Other Notes" below.

Statement of Reserves Data and Other Oil and Gas Information for the New Properties

The statement of reserves data and other oil and gas information set forth below (the "Statement") is dated August 12, 2005 in respect of the reserves data for the New Properties. The effective date of the Statement is July 1, 2005 and the preparation date of the Statement is July 15, 2005.

Disclosure of Reserves Data

The reserves data set forth below (the "Reserves Data") for the New Properties are based upon an evaluation by GLJ with an effective date of July 1, 2005 as contained in the GLJ Report. The Reserves Data summarizes the crude oil, NGL and natural gas reserves of the New Properties and the net present values of future net revenue for these reserves using constant prices and costs and forecast prices and costs. The Reserves Data conforms with the requirements of National Instrument 51-101 Standards of Disclosure for Oil and Gas Activities ("NI 51-101"). Additional information not required by NI 51-101 has been presented to provide continuity and additional information which we believe is important to the readers of this information. GLJ was engaged to provide an evaluation of proved and proved plus probable reserves and also proved plus probable plus possible reserves.

All of the New Properties' reserves are in located Canada and, specifically, in the province of Alberta.

Disclosure provided herein in respect of boes may be misleading, particularly if used in isolation. A boe conversion ratio of 6 mcf:1 bbl is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead.

It should not be assumed that the estimates of future net revenues presented in the tables below represent the fair market value of the reserves. There is no assurance that the constant prices and costs assumptions and forecast prices and costs assumptions will be attained and variances could be material.

Reserves Data (Constant Prices and Costs)

SUMMARY OF OIL AND GAS RESERVES
AND NET PRESENT VALUES OF FUTURE NET REVENUE
as of July 1, 2005
CONSTANT PRICES AND COSTS

Reserves Category		Natural Gas		Light and Medium Oil		Heavy Oil		Natural Gas Liquids
		Gross	Net	Gross	Net	Gross	Net	Gross	Net
		(mmcf)	(mmcf)	(mbbl)	(mbbl)	(mbbl)	(mbbl)	(mbbl)	(mbbl)
Proved Producing		62,112	50,160	108	108	14	24	755	525
Proved Non-Producing		8,532	6,884	—	—	—	—	156	103

	Total Proved Developed	70,644	57,044	108	108	14	24	911	628
Proved Undeveloped		12,794	10,324	—	—	—	—	84	58

	Total Proved	83,437	67,368	108	108	14	24	994	686
Probable		31,534	25,046	92	90	62	55	468	306

Total Proved + Probable		114,971	92,414	200	198	76	78	1,462	992

NET PRESENT VALUES OF FUTURE NET REVENUE
BEFORE INCOME TAXES DISCOUNTED AT
(%/year)

Reserves Category		0	5	10	15	20
		(M$)	(M$)	(M$)	(M$)	(M$)
Proved Producing		303.0	236.2	195.9	168.8	149.2
Proved Non-Producing		40.5	28.4	22.3	18.7	16.2

	Total Proved Developed	343.5	264.6	218.2	187.5	165.4
Proved Undeveloped		48.2	36.0	28.1	22.6	18.5

	Total Proved	391.8	300.6	246.3	210.0	183.9
Probable		143.0	88.2	61.6	46.3	36.5

Total Proved + Probable		534.7	388.8	307.9	256.3	220.4

TOTAL FUTURE NET REVENUE
(UNDISCOUNTED)
as of July 1, 2005
CONSTANT PRICES AND COSTS

Reserves Category	Revenue	Royalties	Operating Costs	Development Costs	Well Abandonment Costs	Future Net Revenue Before Income Taxes
	(M$)	(M$)	(M$)	(M$)	(M$)	(M$)
Proved Reserves	664,987	135,911	113,411	17,877	5,819	391,751
Proved + Probable Reserves	922,264	190,125	160,068	30,790	6,537	534,744

FUTURE NET REVENUE
BY PRODUCTION GROUP
as of July 1, 2005
CONSTANT PRICES AND COSTS

Reserves Category	Production Group	Future Net Revenue Before Income Taxes (discounted at 10%/year)
		(M$)
Proved Reserves	Natural Gas (including by-products but excluding solution gas from oil wells) Light and Medium Crude Oil (including solution gas and other by-products) Heavy Crude Oil (including solution gas and other by-products)	246,310
Proved Plus Probable Reserves	Natural Gas (including by-products but excluding solution gas from oil wells) Light and Medium Crude Oil (including solution gas and other by-products) Heavy Crude Oil (including solution gas and other by-products)	307,888

Reserves Data (Forecast Prices and Costs)

SUMMARY OF OIL AND GAS RESERVES
AND NET PRESENT VALUES OF FUTURE NET REVENUE
as of July 1, 2005
FORECAST PRICES AND COSTS

				Light and Medium Oil				Natural Gas Liquids
		Natural Gas				Heavy Oil
Reserves Category		Natural Gas				Heavy Oil
Reserves Category		Gross	Net	Gross	Net	Gross	Net	Gross	Net
		(mmcf)	(mmcf)	(mbbl)	(mbbl)	(mbbl)	(mbbl)	(mbbl)	(mbbl)
Proved Producing		62,017	50,058	103	103	14	24	754	526
Proved Non-Producing		8,488	6,847	—	—	—	—	155	103

	Total Proved Developed	70,505	56,905	103	103	14	24	909	629
Proved Undeveloped		12,794	10,313	—	—	—	—	84	59

	Total Proved	83,299	67,218	103	103	14	24	993	688
Probable		31,380	24,906	86	84	62	55	465	306

Total Proved + Probable		114,679	92,124	189	186	76	78	1,458	994

NET PRESENT VALUES OF FUTURE NET REVENUE
BEFORE INCOME TAXES DISCOUNTED AT
(%/year)

Reserves Category		0	5	10	15	20
		(M$)	(M$)	(M$)	(M$)	(M$)
Proved Producing		305.7	239.8	200.7	174.6	155.7
Proved Non-Producing		42.5	29.5	23.3	19.6	17.2

	Total Proved Developed	348.2	269.3	223.9	194.2	172.9
Proved Undeveloped		47.8	36.3	28.7	23.4	19.5

	Total Proved	396.0	305.5	252.7	217.6	192.4
Probable		146.4	87.7	60.8	45.8	36.3

Total Proved + Probable		542.4	393.2	313.4	263.4	228.7

TOTAL FUTURE NET REVENUE
(UNDISCOUNTED)
as of July 1, 2005
FORECAST PRICES AND COSTS

Reserves Category	Revenue	Royalties	Operating Costs	Development Costs	Well Abandonment Costs	Future Net Revenue Before Income Taxes
	(M$)	(M$)	(M$)	(M$)	(M$)	(M$)
Proved Reserves	695,317	139,723	133,708	18,277	7,584	396,025
Proved + Probable Reserves	973,504	196,865	193,708	31,408	9,104	542,420

FUTURE NET REVENUE
BY PRODUCTION GROUP
as of July 1, 2005
FORECAST PRICES AND COSTS

Reserves Category	Production Group	Future Net Revenue Before Income Taxes (discounted at 10%/year)
		(M$)
Proved Reserves	Natural Gas (including by-products but excluding solution gas from oil wells) Light and Medium Crude Oil (including solution gas and other by-products) Heavy Crude Oil (including solution gas and other by-products)	252,683
Proved Plus Probable Reserves	Natural Gas (including by-products but excluding solution gas from oil wells) Light and Medium Crude Oil (including solution gas and other by-products) Heavy Crude Oil (including solution gas and other by-products)	313,449

Definitions and Other Notes

In the tables set forth above and elsewhere in this short form prospectus except where indicated otherwise the following definitions and other notes are applicable:

(1)

"Gross" means:

(a): in relation to the interest in production and reserves of the New Properties, its "gross reserves", which is the interest to be acquired by the Trust (operating and non-operating) before deduction of royalties and without including any royalty interest of the New Properties;
(b): in relation to wells, the total number of wells in which the Trust will acquire an interest; and
(c): in relation to properties, the total area of properties in which the Trust will acquire an interest.

(2)

"Net" means:

(a): in relation to the interest in production and reserves of the New Properties, its "net reserves", which is the interest to be acquired by the Trust (operating and non-operating) after deduction of royalties obligations, plus the royalty interest in production or reserves.
(b): in relation to wells, the number of wells obtained by aggregating the working interest in each of its gross wells; and
(c): in relation to interest in the New Properties, the total area in which the Trust will acquire an interest multiplied by the working interest to be acquired.

(3)

"Exploration well" means a well that is not a development well, a service well or a stratigraphic test well.

(4)

"Development costs" means costs incurred to obtain access to reserves and to provide facilities for extracting, treating, gathering and storing the oil and gas from reserves. More specifically, development costs, including applicable operating costs of support equipment and facilities and other costs of development activities, are costs incurred to:

(a): gain access to and prepare well locations for drilling, including surveying well locations for the purpose of determining specific development drilling sites, clearing ground draining, road building, and relocating public roads, gas lines and power lines, pumping equipment and wellhead assembly;
(b): drill and equip development wells, development type stratigraphic test wells and service wells, including the costs of platforms and of well equipment such as casing, tubing, pumping equipment and wellhead assembly;

(c): acquire, construct and install production facilities such as flow lines, separators, treaters, heaters, manifolds, measuring devices and production storage tanks, natural gas cycling and processing plants, and central utility and waste disposal systems; and
(d): provide improved recovery systems.

(5)

"Development well" means a well drilled inside the established limits of an oil and gas reservoir, or in close proximity to the edge of the reservoir, to the depth of a stratigraphic horizon known to be productive.

(6)

"Exploration costs" means costs incurred in identifying areas that may warrant examination and in examining specific areas that are considered to have prospects that may contain oil and gas reserves, including costs of drilling exploratory wells and exploratory type stratigraphic test wells. Exploration costs may be incurred both before acquiring the related property and after acquiring the property. Exploration costs, which include applicable operating costs of support equipment and facilities and other costs of exploration activities, are:

(a): costs of topographical, geochemical, geological and geophysical studies, rights of access to properties to conduct those studies, and salaries and other expenses of geologists, geophysical crews and others conducting those studies;
(b): costs of carrying and retaining unproved properties, such as delay rentals, taxes (other than income and capital taxes) on properties, legal costs for title defence, and the maintenance of land and lease records;
(c): dry hole contributions and bottom hole contributions;
(d): costs of drilling and equipping exploratory wells; and
(e): costs of drilling exploratory type stratigraphic test wells.

(7)

"Service well" means a well drilled or completed for the purpose of supporting production in an existing field. Wells in this class are drilled for the following specific purposes: gas injection (natural gas, propane, butane or flue gas), water injection, steam injection, air injection, salt water disposal, water supply for injection, observation or injection for combustion.

(8)

Definitions used for reserve categories are as follows:

The following definitions apply to both estimates of individual reserves entities and the aggregate of reserves for multiple entities.

Reserve Categories

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 (see the discussion of "Economic Assumptions" below).

Reserves are classified according to the degree of certainty associated with the estimates.

(a): 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.
(b): 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.

"Economic Assumptions" will be the prices and costs used in the estimate, namely:

(a): constant prices and costs as at the preparation date of the evaluation (September 30, 2005); and
(b): forecast prices and costs.

Development and Production Status

Each of the reserve categories (proved and probable) may be divided into developed and undeveloped categories:

(a): Developed reserves are those reserves that are expected to be recovered from existing wells and installed facilities or, if facilities have not been installed, that would involve a low expenditure (for example, when compared to the cost of drilling a well) to put the reserves on production. The developed category may be subdivided into producing and non-producing.
(b): 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.
(c): 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.
(d): Undeveloped reserves are those reserves expected to be recovered from known accumulations where a significant expenditure (for example, 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) 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 subdivide 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.

Levels of Certainty for Reported Reserves

The qualitative certainty levels referred to in the definitions above are applicable to individual reserve entities (which refers to the lowest level at which reserves calculations are performed) and to reported reserves (which refers to the highest level sum of individual entity estimates for which reserves are presented). Reported reserves should target the following levels of certainty under a specific set of economic conditions:

(a): at least a 90 percent probability the estimated proved reserves will be recovered; and
(b): at least a 50 percent probability that the sum of the estimated proved plus probable reserves will be recovered.

A qualitative measure of the certainty levels pertaining to estimates prepared for the various reserves categories is desirable to provide a clearer understanding of the associated risks and uncertainties. However, the majority of reserves estimates will be prepared using deterministic methods that do not provide a mathematically derived quantitative measure of probability. In principle, there should be no difference between estimates prepared using probabilistic or deterministic methods.

(9): Forecast prices and costs

Future prices and costs that are:

(a): generally acceptable as being a reasonable outlook of the future; and

(b): if and only to the extent that, there are fixed or presently determinable future prices or costs to which the working interest owner is legally bound by a contractual or other obligation to supply a physical product, including those for an extension period of a contract that is likely to be extended, those prices or costs rather than the prices and costs referred to in paragraph (a).

The forecast summary table under "Pricing Assumptions" identifies benchmark reference pricing that apply to the New Properties.

(10): Constant prices and costs

Prices and costs used in an estimate that are:

(a): the Corporation's prices and costs as at the effective date of the estimation, held constant throughout the estimated lives of the properties to which the estimate applies; and
(b): if, and only to the extent that, there are fixed or presently determinable future prices or costs to which the working interest owner is legally bound by a contractual or other obligation to supply a physical product, including those for an extension period of a contract that is likely to be extended, those prices or costs rather than the prices and costs referred to in paragraph (a).
(c): For the purposes of paragraph (a), the Corporation's prices are the posted prices for oil and the spot price for gas, after historical adjustments for transportation, gravity and other factors.

(11): Estimated reclamation costs related to a property have not been taken into account by GLJ in determining reserves that should be attributed to a property and in determining the aggregate future net revenue therefrom. A reasonable estimate of future well abandonment costs was taken into account and was deducted.
(12): Numbers may not add due to rounding.
(13): Both the constant and forecast price and cost assumptions assumed the continuance of current laws and regulations.
(14): The extent and character of all factual data supplied to GLJ were accepted by GLJ as represented. No field inspection was conducted.
(15): The estimates of future net revenue presented in the tables above do not represent fair market value.

Pricing Assumptions

The following sets out the benchmark reference prices, as at July 1, 2005, reflected in the Reserves Data. These forecast price assumptions were provided by the Vendor. The constant prices as of June 30, 2005 were supplied by GLJ.

SUMMARY OF PRICING ASSUMPTIONS
as of June 30, 2005
CONSTANT PRICES AND COSTS

Oil				Natural Gas	Edmonton NGLs Prices
WTI Cushing Oklahoma	Edmonton Par Price 40° API	Hardisty Heavy 25° API	Cromer Medium 29.3° API	AECO Gas Price	Propane	Butane	Pentanes Plus	Exchange Rate
($US/bbl)	($Cdn/bbl)	($Cdn/bbl)	($Cdn/bbl)	($Cdn/Mmbtu)	($Cdn/bbl)	($Cdn/bbl)	($Cdn/bbl)	($US/$Cdn)
56.50	68.45	47.73	49.17	6.89	43.81	50.65	65.83	0.8159

Note:

(1): The exchange rate used to generate the benchmark reference prices in this table.

SUMMARY OF PRICING AND INFLATION RATE ASSUMPTIONS
as of July 1, 2005
FORECAST PRICES AND COSTS

	Oil				Natural Gas	Edmonton Liquids Prices
Year	WTI Cushing Oklahoma	Edmonton Par Price 40° API	Hardisty Heavy 25° API	Cromer Medium 29.3° API	AECO Gas Price	Propane	Butane	Pentanes Plus	Inflation Rates⁽¹⁾ %/Year	Exchange Rate⁽²⁾
	($US/bbl)	($Cdn/bbl)	($Cdn/bbl)	($Cdn/bbl)	($Cdn/mmbtu)	($Cdn/bbl)	($Cdn/bbl)	($Cdn/bbl)		($US/$Cdn)
Forecast
2005	55.00	66.00	35.50	57.50	7.65	42.25	48.75	66.75	2.0	0.82
2006	55.00	66.00	35.50	57.50	7.75	42.25	48.75	66.75	2.0	0.82
2007	52.00	62.75	34.75	54.50	7.35	40.25	46.50	63.50	2.0	0.82
2008	48.00	57.75	34.25	50.25	7.10	37.00	42.75	58.25	2.0	0.82
2009	45.00	54.25	34.00	47.25	6.80	34.75	40.25	54.75	2.0	0.82
2010	42.00	50.50	32.75	44.00	6.50	32.25	37.25	51.00	2.0	0.82
2011	40.00	48.00	31.25	41.75	6.50	30.75	35.50	48.50	2.0	0.82
2012	40.00	48.00	31.25	41.75	6.50	30.75	35.50	48.50	2.0	0.82
2013	40.75	49.00	32.00	42.75	6.65	31.25	36.25	49.50	2.0	0.82
2014	41.50	50.00	32.50	43.50	6.85	32.00	37.00	50.50	2.0	0.82
2015	42.50	51.00	33.25	44.25	7.00	32.75	37.75	51.50	2.0	0.82
Thereafter	+2.0%/year	+2.0%/year	+2.0%/year	+2.0%/year	+2.0%/year	+2.0%/year	+2.0%/year	+2.0%/year	2.0	0.82

Notes:

(1): Inflation rates for forecasting prices and costs.
(2): Exchange rates used to generate the benchmark reference prices in this table.

Weighted average historical prices realized in respect of the New Properties for the year ended December 31, 2004 were $40.70/bbl for oil, $6.60/mcf for natural gas and $45.00/bbl for NGLs.

Additional Information Relating to Reserves Data

The recovery of the Proved Undeveloped and Probable reserves of the New Properties will occur primarily through development drilling and drilling injection wells. The recovery of these reserves will be dependent on these future wells exhibiting similar performance characteristics to the existing wells drilled into the pool.

Future Development Costs

The following table sets forth development costs deducted in the estimation of the future net revenue in respect of the New Properties attributable to the reserve categories noted below. All amounts are stated in thousands of dollars.

	Forecast Prices and Costs		Constant Prices and Costs
Year	Proved Reserves	Proved Plus Probable Reserves	Proved Reserves	Proved Plus Probable Reserves
2005	8,243	16,073	8,243	16,073
2006	6,932	10,563	6,796	10,356
2007	650	921	625	885
2008	—	663	—	625
2009	2,192	677	2,025	625
Thereafter	260	2,511	188	2,226

Total	18,227	31,408	17,877	30,790

Discounted at 10%	16,447	28,475	16,175	28,047

These future development costs will be financed with cash flow and with the New Credit Facilities.

Capital Expenditures

The following tables summarizes capital expenditures made on acquisitions, development and exploration drilling and production facilities and other equipment in respect of the New Properties for the periods indicated.

	Nine Months Ended September 30	Year Ended December 31⁽¹⁾
	2005⁽¹⁾	2004	2003
	($000's)	($000's)	($000's)
Property acquisitions⁽²⁾	282	558	1,721
Development expenditures⁽³⁾	14,134	12,928	11,631
Production equipment⁽⁴⁾	4,541	8,152	5,401
Exploration expenditures⁽⁵⁾	855	967	855

TOTAL	19,812	22,605	19,608

Notes:

(1): Based on information provided to the Trust by the Vendor.
(2): Property acquisitions include production lease/royalty purchases and property exchanges of lease and royalty interests.
(3): Development expenditures include development drilling and miscellaneous intangible expenditures.
(4): Production equipment includes production and facility equipment and miscellaneous tangible assets.
(5): Exploration expenditures include exploration drilling, geological and geophysical costs and miscellaneous intangible expenditures.

Production Estimates

Gross volumes of production from the New Properties for the six months ended December 31, 2005 estimated in the GLJ Report using constant prices and costs are as follows:

	Light and Medium Oil	Heavy Oil	Natural Gas	NGLs	Combined
	(bbls/d)	(bbls/d)	(mcf/d)	(bbls/d)	(boe/d)
Proved Producing	68	24	30,647	354	5,554
Total Proved	68	24	33,589	366	6,056
Proved plus Probable	69	62	34,558	371	6,262

Production History and Prices Received

The following table sets forth certain information in respect of production, product prices received, royalties, production expenses and netbacks received in respect of the New Properties for the periods indicated.

		Quarter Ended
		2005			2004
		September 30	June 30	March 31	December 31	September 30	June 30	March 31
Average Daily Production⁽¹⁾
	Light and medium Crude Oil (bbls/d)	128	143	155	153	138	127	73
	Gas (mcf/d)	30.9	32.1	32.4	34.5	34.7	33.8	31.1
	NGLs (bbls/d)	286	265	304	328	315	297	322
	Combined (boe/d)	5,566	5,762	5,860	6,230	6,237	6,062	5,572
Average Price Received
	Light and Medium Crude Oil ($/bbl)	71.76	57.36	53.85	50.44	53.11	46.44	38.80
	Gas ($/mcf)	9.34	7.66	7.10	6.88	6.50	7.22	6.57
	NGLs ($/bbl)	60.50	53.36	50.62	47.16	44.10	41.64	37.60
	Combined ($/boe)	56.65	46.59	43.31	41.81	39.58	43.33	39.30

Royalties
	Light and Medium Crude Oil ($/bbl)	12.92	10.32	9.69	9.08	9.56	8.36	6.98
	Gas ($/mcf)	1.84	1.49	1.50	1.30	1.54	1.36	1.51
	NGLs ($/bbl)	16.33	14.41	13.74	12.73	11.91	11.24	10.22
	Combined ($/boe)	11.34	9.23	9.24	8.08	9.35	8.32	9.11
Operating expenses
	Light and Medium Crude Oil ($/bbl)	5.42	6.83	6.52	4.91	6.95	5.35	4.83
	Gas ($/mcf)	0.90	1.14	1.09	0.82	1.16	0.89	0.80
	NGLs ($/bbl)	5.42	6.83	6.52	4.91	6.95	5.35	4.83
	Combined ($/boe)	5.42	6.83	6.52	4.91	6.95	5.35	4.83
Transportation Costs
	Gas ($/mcf)	0.27	0.27	0.28	0.27	0.30	0.30	0.24
	Light and Medium Crude Oil ($/bbl)	—	—	—	—	—	—	—
	NGLs ($/bbl)	—	—	—	—	—	—	—
	Combined ($/boe)	1.50	1.49	1.57	1.49	1.67	1.66	1.33
Netback Received⁽³⁾
	Light and Medium Crude Oil ($/bbl)	53.42	40.21	37.64	36.45	36.60	32.73	26.99
	Gas ($/mcf)	6.33	4.76	4.23	4.49	3.50	4.67	4.02
	NGLs ($/bbl)	38.75	32.12	30.36	29.52	25.24	25.05	22.55
	Combined ($/boe)	38.39	29.04	25.98	27.33	21.61	28.00	24.03

Notes:

(1): Before deduction of royalties.
(2): Netbacks are calculated by subtracting royalties, operating costs and transportation costs from revenues.

EFFECT OF THE ACQUISITION ON THE TRUST

The following table sets out certain operational information for the Trust and the New Properties and certain pro forma combined operational information after giving effect to the Acquisition.

Selected Pro Forma Combined Operational Information

		Trust	Ultima	New Properties	Pro Forma Combined
Average Daily Production
(before royalties, for the nine months ended September 30, 2005)
	Crude oil and NGL (bbls/d)	20,521	N/A	427	20,948
	Natural gas (mcf/d)	94,384	N/A	31,808	126,192
	Oil equivalent (boe/d)	36,252	N/A	5,728	41,980
Average Daily Production⁽¹⁾
(before royalties, for the year ended December 31, 2004)
	Crude oil and NGL (bbls/d)	17,346	3,538	437	21,321
	Natural gas (mcf/d)	84,500	6,111	33,436	124,047
	Oil equivalent (boe/d)	31,429	4,557	6,010	41,996

Note:

(1): Average daily production for the Trust for the year ended December 31, 2004 includes production from Ultima from the date of closing of the Ultima acquisition, June 16, 2004. Average daily production for Ultima for the year ended December 31, 2004 is from January 1, 2004 to the date of closing of the Ultima acquisition, June 16, 2004.

Selected Pro Forma Consolidated Financial Information

Certain selected pro forma consolidated financial information is set forth in the following tables. Such information should be read in conjunction with the unaudited pro forma consolidated financial statements of the Trust after giving effect to the Acquisition as at and for the nine months ended September 30, 2005 and the year ended December 31, 2004 included in this short form prospectus.

The pro forma adjustments are based upon the assumptions described in the notes to the unaudited pro forma consolidated financial statements. The pro forma consolidated financial statements are presented for illustrative purposes only and are not necessarily indicative of the operating or financial results that would have occurred had the Acquisition actually occurred at the times contemplated by the notes to the unaudited pro forma consolidated financial statements or of the results expected in future periods.

The information presented below and in the unaudited pro forma consolidated financial statements of the Trust assumes completion of the Acquisition and the issuance of 12,500,000 Subscription Receipts pursuant to the offering.

	As at and for the Nine Months Ended September 30, 2005
	Trust⁽⁴⁾	New Properties⁽⁶⁾	Pro Forma Consolidated⁽⁷⁾
	(stated in thousands of dollars, except unit amounts)
Revenue — net⁽¹⁾	434,955	61,086	496,041
Net income (loss)	110,645	7,018	117,663
Cash flow from operations before changes in working capital and before settlement of asset retirement obligations⁽²⁾	273,664	36,867	310,531
Total Assets	1,569,436	655,721	2,225,157
Net debt (including working capital)⁽³⁾	232,422	248,815	481,237
Equity	1,084,746	236,800	1,321,546
Units outstanding (000s)⁽⁸⁾	104,507	12,500	117,007

	For the Year Ended December 31, 2004
	Trust⁽⁴⁾	Ultima⁽⁵⁾		New Properties⁽⁶⁾		Pro Forma Consolidated⁽⁷⁾
	(stated in thousands of dollars)
Revenue — net⁽¹⁾	416,851	58,262		72,369		547,482
Net income (loss)	74,359	(7,485	)	(974	)	65,900
Cash flow from operations before changes in working capital and before settlement of asset retirement obligations⁽²⁾	240,798	20,002		40,389		301,189

Notes:

(1): Revenue — net consists of gross revenue net of applicable royalties.
(2): Cash flow from operations before changes in working capital and before settlement of asset retirement obligations is before changes in non-cash working capital. As such, it is not a measure recognized by Canadian generally accepted accounting principles ("GAAP") and does not have a standardized meaning prescribed by GAAP. Therefore, cash flow from operations before changes in working capital and before settlement of asset retirement obligations of the Trust may not be comparable to similar measures presented by other issuers, and subscribers are cautioned that it 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. See "Special Note Regarding Forward Looking Statements and Other Disclosure — Certain Financial Reporting Measures". For the Trust's nine months ended September 30, 2005 and year

ended December 31, 2004, funds flow from operations before changes in working capital and before settlement of asset retirement obligations is reconciled to its closest GAAP measure of cash provided by operating activities as follows:

	Nine Months Ended September 30, 2005		Year Ended December 31, 2004
Cash flow from operations before changes in working capital and before settlement of asset retirement obligations	310,531		301,189
Changes in non-cash working capital	(39,516	)	33,525
Settlement of asset retirement obligations	(1,772	)	(4,553	)

Cash provided by operating activities	269,243		330,161

(3): Net debt is bank debt and any working capital deficit excluding the current portion of derivative contracts. Net debt is a "non-GAAP" measure. See "Special Note Regarding Forward-Looking Statements and Other Disclosure — Certain Financial Reporting Measures".
(4): The Trust financial information for the year ended December 31, 2004 was obtained from the Trust's consolidated financial statements as at and for the year ended December 31, 2004 and for the nine months ended September 30, 2005 was obtained from the Trust's unaudited consolidated financial statements as at and for the nine months ended September 30, 2005.
(5): The Ultima financial information for the year ended December 31, 2004 was derived from the unaudited consolidation financial statements of Ultima as at March 31, 2004 and for the three month period then ended and from Ultima's accounting records for the period April 1, 2004 to June 16, 2004.
(6): The New Properties financial information for the year ended December 31, 2004 and for the nine months ended September 30, 2005 was obtained from the financial statements of each of KEL and the Limited Partnership and the schedule of revenue and expenses of the Unincorporated Interests set forth herein and reflects the pro forma adjustments as noted in the Pro Forma Consolidated Financial Statements set forth herein. These amounts do not reflect adjustments related to this offering as reflected in the pro forma financial statements. These amounts are reflected in the pro forma consolidated column in each of the tables above.
(7): See the notes to the unaudited pro forma consolidated financial statements set forth herein for assumptions and adjustments. The unaudited pro forma consolidated financial statements may not be indicative of results that actually would have occurred if the events reflected herein had been in effect on the dates indicated or of the results expected in future periods.
(8): Pro Forma Trust Units outstanding includes Trust Units issued upon conversion of Subscription Receipts, and does not include rights granted pursuant to the Trust's unit rights incentive plan exercisable for 44,532 Trust Units as at September 30, 2005, restricted units granted pursuant to the Trust's restricted unit plan entitling the holders to acquire 123,173 Trust Units as at September 30, 2005, restricted units granted pursuant to the Trust's long-term incentive plan entitling the holders to acquire 40,830 Trust Units as at September 30, 2005, and PC Exchangeable Shares exchangeable into 539,147 Trust Units as at September 30, 2005.

DESCRIPTION OF THE TRUST UNITS

Trust Units

An unlimited number of Trust Units may be created and issued pursuant to the Trust Indenture. Each Trust Unit represents an equal undivided beneficial interest in the assets of Trust. Each outstanding Trust Unit is entitled to an equal share of distributions by the Trust and, in the event of termination of the Trust, the net assets of the Trust. All Trust Units rank equally. Each Trust Unit entitles the holder thereof to one vote at all meetings of Unitholders. No Unitholder will be liable to pay any further calls or assessments in respect of the Trust Units. No conversion or preemptive rights attach to the Trust Units.

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 statutory right given shareholders to bring an action against an issuer and its directors. 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.

Special Voting Units

An unlimited number of Special Voting Units are also issuable pursuant to the Trust Indenture. Special Voting Units may only be issued by the Trust in conjunction with the issuance by the Corporation or an affiliate of securities which are, by their terms, exchangeable into Trust Units. Each holder of a Special Voting Unit of record is entitled to vote at all meetings of Unitholders. The maximum number of votes attached to each Special

Voting Unit shall be that number of Trust Units into which the exchangeable shares issued in conjunction with the Special Voting Unit and at that time outstanding are then exchangeable. The holders of Trust Units and the holder of Special Voting Units vote together as a single class on all matters. Special Voting Units have the foregoing rights in respect of voting at all meetings of unitholders but have no other rights and, for greater certainty, Special Voting Units do not represent a beneficial interest in the Trust. In the event that exchangeable shares issued in conjunction with a Special Voting Unit cease to be outstanding, such Special Voting Unit shall be deemed to be cancelled.

Trust Indenture

The Trust Indenture, among other things, provides for the calling of meetings of Unitholders, the conduct of business thereof, notice provisions, the appointment and removal of the Trustee and the form of Trust Unit certificates. The Trust Indenture may be amended from time to time. Substantive amendments to the Trust Indenture, including early termination of the Trust and the sale or transfer of the property of the Trust as an entirety or substantially as an entirety, require approval by Special Resolution of the Unitholders. See "Information Relating to the Trust — Trust Indenture" in the AIF.

The foregoing is a summary of certain provisions of the Trust Indenture. For a complete description of such Trust Indenture, reference should be made to the complete text of the Trust Indenture, copies of which may be viewed at the offices of, or obtained from, the Trustee.

CONSOLIDATED CAPITALIZATION OF THE TRUST

The following table sets forth the consolidated capitalization of the Trust as at December 31, 2004 and as at September 30, 2005 both before and after giving effect to the offering and the Acquisition.

Designation (Authorized)	As at December 31, 2004		As at September 30, 2005 before giving effect to the offering and the Acquisition		As at September 30, 2005 after giving effect to the offering and the Acquisition
	($ thousands, except unit and vote amounts)
Long Term Debt⁽¹⁾	$	214,414	$	244,499	$	493,314
Capital Leases		608		—		—
Unitholders' Equity^(2)(3)(4)(5)		1,026,526		1,084,746		1,321,546
		(99,511,576 Units)		(104,507,120 Units)		(117,007,120 Units)
		(939,147 Units issuable in exchange for PC Exchangeable Shares)		(539,147 Units issuable in exchange for PC Exchangeable Shares)		(539,147 Units issuable in exchange for PC Exchangeable Shares)

Notes:

(1): PC has a revolving working capital operating facility in the amount of $25 million and a syndicated facility in the amount of $390 million that are available in Canadian or U.S. dollars (collectively, the "Current Credit Facilities"). Interest rates fluctuate under the working capital operating facility with Canadian prime and U.S. base rates, as well as with Canadian banker's acceptance and LIBOR rates plus 80 basis points. Interest rates fluctuate under the syndicated facility with Canadian prime and U.S. base rates plus between 0 and 25 basis points, as well as with Canadian banker's acceptance and LIBOR rates plus between 80 basis points and 125 basis points, depending, in each case upon the Trust's debt to cash flow ratio. Indebtedness under the Current Credit Facilities is secured by a $600 million debenture containing a first ranking security interest on all of PC's assets. In addition, each of the Trust and PVT have provided a guarantee of PC's indebtedness under the Current Credit Facilities that is secured by a $600 million debenture containing a first ranking security interest in their respective assets. The limit of the syndicated facility is subject to adjustment from time to time to reflect changes in PC's asset base. The next review date for the Current Credit Facilities is April 2006. PC is negotiating replacement credit facilities (the "New Credit Facilities") in the aggregate principal amount of $590 million to be available for the closing of the Acquisition. It is expected that the New Credit Facilities will consist of a combined revolving working capital operating facility in the amount of $50 million and a syndicated facility in the amount of $540 million. Interest rates are expected to fluctuate under the working capital operating facility of the New Credit Facilities with Canadian prime and U.S. base rates, as well as with Canadian banker's acceptance and LIBOR rates. Interest rates are expected to fluctuate under the syndicated facility of the New Credit Facilities with Canadian prime and U.S. base rates plus between 0 and 25 basis points, as well as with Canadian banker's acceptance and LIBOR rates plus between 75 basis points and 125 basis points, depending, in each case upon the Trust's debt to cash flow ratio. The New Credit Facilities are expected to be secured by a $900 million debenture containing a first ranking security interest on all PC's assets. In addition, it is expected that the New Credit Facilities will require each of the Trust, PVT, KEL and its subsidiaries to provide a

guarantee of PC's indebtedness under the New Credit Facilities that will be secured by a $900 million debenture containing a first ranking security interest in their respective assets.

(2): In addition, as at September 30, 2005, rights were outstanding to purchase an aggregate of 44,532 Trust Units, having a weighted average exercise price of $11.03 which were granted pursuant to the Trust's unit rights incentive plan.
(3): In addition, as at September 30, 2005, 123,173 restricted units were outstanding which were granted pursuant to the Trust's restricted unit plan, which restricted units entitled the holders to acquire 123,173 Trust Units, subject to adjustment for cash distributions paid to Unitholders.
(4): In addition, as at September 30, 2005, 40,830 restricted units were outstanding which were granted pursuant to the Trust's long-term incentive plan, which restricted units entitled the holders to acquire 40,830 Trust Units, subject to adjustment in accordance with cash distributions paid to Unitholders and subject to meeting certain performance measures.
(5): As at September 30, 2005, 402,618 PC Exchangeable Shares were outstanding entitling the holders to exchange shares at an exchange ratio of 1.3391. If all PC Exchangeable Shares were exchanged on September 30, 2005, there would be 539,147 additional Trust Units issued.

STABILITY RATING

Dominion Bond Rating Service Limited ("DBRS") has assigned a stability rating of STA-5 (low) to the Trust Units. The stability rating is based on a rating scale developed by DBRS that provides an indicator of both the stability and sustainability of an income fund's distributions per unit. Ratings categories range from STA-1 to STA-7, with STA-1 being the highest. In addition, DBRS further separates the ratings into "high", "middle" and "low" subcategories to indicate where they fall within the rating category. Ratings take into consideration the seven main factors of: (1) operating and industry characteristics; (2) asset quality; (3) financial flexibility; (4) diversification; (5) size and market position; (6) sponsorship/governance; and (7) growth. In addition, consideration is given to specific structural or contractual elements that may eliminate or mitigate risks or other potentially negative factors.

Specifically, income funds rated as STA-5 are considered by DBRS to have weak distribution per unit stability and sustainability. An income fund rated as STA-5 is subject to many of the same cyclical, seasonal and economic factors as the higher STA-4 rating category, but the lack of diversification is generally more pronounced and such income funds will tend to be below average in several areas.

A rating is not a recommendation to buy, sell or hold any security and may be subject to revision or withdrawal at any time by DBRS.

PRICE RANGE AND TRADING VOLUME OF THE UNITS

The Trust Units are listed and posted for trading on the TSX and on AMEX. The following table sets forth the high and low closing prices and the aggregate volume of trading of the Trust Units on the TSX and on AMEX for the periods indicated:

		Toronto Stock Exchange			American Stock Exchange
Period		High $	Low $	Average Daily Volume	High US$	Low US$	Average Daily Volume
2002
	First Quarter	13.90	11.85	133,115	8.80	7.36	58,125
	Second Quarter	13.43	11.86	99,730	8.50	7.80	61,700
	Third Quarter	12.65	10.65	73,293	8.33	6.75	62,870
	Fourth Quarter	11.89	10.10	104,237	7.48	6.48	80,130
2003
	First Quarter	12.43	10.80	103,752	8.52	7.02	139,287
	Second Quarter	13.41	10.79	248,402	9.98	7.48	310,449
	Third Quarter	16.54	13.06	257,373	12.08	9.80	442,928
	Fourth Quarter	18.80	15.95	233,814	14.55	11.90	435,908
2004
	First Quarter	19.17	15.01	204,321	14.96	11.24	653,824
	Second Quarter	18.00	14.80	188,990	13.48	11.03	318,521
	Third Quarter	16.16	14.67	286,784	12.71	11.22	423,800
	Fourth Quarter	17.15	14.52	185,181	13.65	12.16	518,348
2005
	January	17.05	15.50	215,865	13.75	12.66	514,090
	February	18.85	16.95	324,430	15.34	13.68	603,879
	March	19.33	16.25	253,323	16.05	13.40	794,377
	April	18.57	17.00	160,852	15.22	13.62	513,657
	May	18.79	17.47	163,181	15.04	13.90	385,424
	June	19.97	18.25	202,077	16.25	14.63	505,686
	July	21.12	19.57	132,440	17.25	15.94	467,575
	August	22.96	19.30	125,068	19.26	15.72	697,309
	September	23.31	20.90	184,861	19.85	17.55	555,700
	October	23.17	19.05	163,535	19.88	16.10	762,190
	November (to November 29)	21.80	20.02	233,371	18.47	16.84	483,450

On November 15, 2005 the last completed trading day on which the Trust Units traded prior to announcement of this offering, the closing price of the Trust Units was $20.57 on the TSX and US$17.41 on AMEX. On November 29, 2005 the closing price of the Trust Units was $20.52 on the TSX and US$17.53 on AMEX.

RECORD OF CASH DISTRIBUTIONS

The following per Trust Unit distributions have been payable to Unitholders on record dates during the following periods.

	Distribution Per Trust Unit
2002:
First Quarter	$	0.43
Second Quarter	$	0.41
Third Quarter	$	0.42
Fourth Quarter	$	0.45

2003:
First Quarter	$	0.48
Second Quarter	$	0.53
Third Quarter	$	0.54
Fourth Quarter	$	0.54
2004:
First Quarter	$	0.48
Second Quarter	$	0.48
Third Quarter	$	0.48
Fourth Quarter	$	0.48
2005:
First Quarter	$	0.48
Second Quarter	$	0.48
Third Quarter	$	0.48
October	$	0.17
November	$	0.17

Cash distributions by the Trust are payable on the last business day of each month to Unitholders of record on the tenth business day preceding the end of such month.

If the offering closes on December 6, 2005 and the Acquisition closes on December 15, 2005 as currently contemplated, holders of Subscription Receipts will be entitled to receive on December 30, 2005 an amount equal to the monthly distribution expected to be paid on December 30, 2005 to Unitholders of record on December 14, 2005.

Distributions may vary significantly from period to period based on, among other things, commodity prices and production levels. The Trust's acquisition and development activity will also impact the level of distributions. The Trust has historically been engaged in an active program of acquiring producing oil and gas properties with a view to replacing exploited reserves and increasing production in order to enhance distributions; however, there can be no assurance that such acquisitions will continue in the foreseeable future. Distributions for any given period will also vary to the extent cash flows are utilized for debt repayment, reserved for purposes of funding future operating costs, capital expenditures, reclamation obligations, general and administrative costs or debt service charges or to the extent such reserve is utilized in a particular period. Distributions per Trust Unit will also vary based on the number of outstanding Trust Units. There is no minimum distribution payable in any period.

USE OF PROCEEDS

The net proceeds to the Trust from the sale of the Subscription Receipts hereunder are estimated to be $236,800,000 after deducting the fees of $12,500,000 payable to the Underwriters and the estimated expenses of the issue of $700,000. The net proceeds of the offering will be used to pay for a portion of the purchase price of the Acquisition.

DETAILS OF THE OFFERING

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

At closing, a certificate representing the Subscription Receipts will be issued in registered form to CDS or its nominee, CDS & Co., and will be deposited with CDS on the closing date of this offering pursuant to the book-entry only system. Unless the book-entry only system is terminated, and except in certain limited circumstances, owners of beneficial interests in Subscription Receipts shall not receive a certificate for Subscription Receipts or, unless requested, for the Trust Units issuable on the exchange of the Subscription

Receipts. Beneficial interests in Subscription Receipts will generally be represented solely through the book-entry only system and such interests will be evidenced by customer confirmations of purchase from the Underwriters.

The Escrowed Funds will be delivered to and held by the Escrow Agent and invested in short-term obligations of, or guaranteed by, the Government of Canada (and other approved investments) pending the closing of the Acquisition. Provided that the closing of the Acquisition occurs by 5:00 p.m. (Calgary time) on January 31, 2006, the Escrowed Funds and the interest earned thereon will be released to the Trust and the Units will be issued to holders of Subscription Receipts who will receive, without payment of additional consideration or further action, one 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 Units to the Escrow Agent. Contemporaneously with the delivery of such notice, the Trust will issue a press release specifying that the Units have been issued.

If the closing of the Acquisition does not take place by 5:00 p.m. (Calgary time) on January 31, 2006, 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 on such amount. The Escrowed Funds will be applied toward payment of such amount. The issuance of a cheque in payment of the subscription price for the Subscription Receipts will require the surrender of the certificate(s) representing the same at the principal office of the Escrow Agent in Calgary, Alberta. If any certificates representing Subscription Receipts have not been surrendered one year after the Termination Time, the Escrow Agent will mail the cheques that the holders thereof are entitled to receive to their last addresses of record.

If the closing of the Acquisition takes place prior to the Termination Time and holders of Subscription Receipts become entitled to receive Units pursuant to the Subscription Receipt Agreement, such holders will be entitled to receive an amount per Subscription Receipt equal to the amount per Unit of any cash distributions for which record dates have occurred during the period from the date of closing of the offering to the date immediately preceding the date the Units are issued pursuant to the Subscription Receipts. All or a portion of this amount 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 Units will be paid by the Trust. If holders of Subscription Receipts become entitled to receive Units, the Escrow Agent and the Trust will pay such amounts to holders on the later of the date the 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 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 Units on such date and will be entitled as Unitholders to receive such monthly distribution.

In addition, if the offering closes on December 6, 2005 and the Acquisition closes on December 15, 2005 as currently contemplated, holders of Subscription Receipts will be entitled to receive on December 30, 2005 an amount equal to the monthly distribution expected to be paid on December 30, 2005 to Unitholders of record on December 14, 2005.

Under the Subscription Receipt Agreement, original purchasers of Subscription Receipts under the offering will have a contractual right of rescission following the issuance of 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 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.

PLAN OF DISTRIBUTION

Pursuant to the Underwriting Agreement, the Trust has agreed to issue and sell an aggregate of 11,250,000 Subscription Receipts to the Underwriters, and the Underwriters have severally agreed to purchase such Subscription Receipts on December 6, 2005, or such other date not later than December 14, 2005 as may be agreed among the parties to the Underwriting Agreement. Delivery of the Subscription Receipts is conditional upon payment on closing of $20.00 per Subscription Receipt by the Underwriters to the Escrow Agent. The Underwriting Agreement provides that the Trust will pay the Underwriters' fee of $1.00 per Subscription Receipt for Subscription Receipts issued and sold by the Trust, for an aggregate fee payable by the Trust of $11,250,000, in consideration for their services in connection with the offering. The Underwriters' fee 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 January 31, 2006, 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 PC, on behalf of the Trust, and CIBC World Markets Inc., on its own behalf and on behalf of the other Underwriters.

Pursuant to the Underwriting Agreement, the Trust had granted to the Underwriters an Underwriters' option to purchase up to an additional 1,250,000 Subscription Receipts on the same terms and conditions as the offering, exercisable in whole or in part, at any time up to 48 hours prior to the closing of the offering. The Underwriters exercised the option in full on November 24, 2005 increasing the offering from 11,250,000 Subscription Receipts to 12,500,000 Subscription Receipts and resulting in, the total offering, Underwriters' fee and net proceeds to the Trust (before expenses of the offering) being $250,000,000, $12,500,000 $237,500,000, respectively.

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 automatically 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 one or more of the Underwriters fails to purchase its allotment of Subscription Receipts, the remaining Underwriter or Underwriters are obligated to purchase the Subscription Receipts not purchased by the Underwriter or Underwriters which fail to purchase. Notwithstanding the foregoing, however, in the event one or more of the Underwriters who have an obligation to purchase in the aggregate more than 7% of the Subscription Receipts offered hereunder fail to purchase their allotment of Subscription Receipts, the remaining Underwriter or Underwriters have the right but not the obligation to purchase the Subscription Receipts not purchased by the Underwriter or Underwriters which fail to purchase or the remaining Underwriter or Underwriters have the right to terminate their obligations under the Underwriting Agreement. The Underwriters are obligated to take up and pay for all of the Subscription Receipts if any purchased under the Underwriting Agreement. The Underwriting Agreement also provides that the Trust and the Corporation 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 "Details of the Offering".

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 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, Units or any securities convertible or exchangeable into Units for a period of 90 days subsequent to the closing date of the offering without the consent of CIBC World Markets Inc. on behalf of the Underwriters, which consent may not be unreasonably withheld.

The TSX has conditionally approved the listing of the Subscription Receipts offered hereunder and the Units issuable pursuant to the Subscription Receipts on the TSX. Listing is subject to the Trust fulfilling all of the requirements of the TSX on or before February 16, 2006. The Trust has applied to list the Units issuable

pursuant to the Subscription Receipts on AMEX. Listing will be subject to the Trust fulfilling all of the listing requirements of AMEX.

RELATIONSHIP BETWEEN PC'S LENDERS AND THE UNDERWRITERS

CIBC World Markets Inc., National Bank Financial Inc., Scotia Capital Inc., RBC Dominion Securities Inc. and BMO Nesbitt Burns Inc., five of the Underwriters, are direct or indirect wholly-owned subsidiaries of Canadian chartered banks which are lenders to PC and to which PC is indebted. See note (1) to the table under "Consolidated Capitalization of the Trust" for a description of the existing credit facility of PC and PVT and the New Credit Facilities. Consequently, the Trust may be considered to be a connected issuer of these Underwriters for the purposes of securities regulations in certain provinces. PC and PVT are currently in compliance with the terms of the credit facility. The decision to distribute the Subscription Receipts hereby and the determination of the terms of distribution were made through negotiations between PC, on behalf of the Trust, and CIBC World Markets Inc., on behalf of the Underwriters. The banks did not have any involvement in such decision or determination; however, the banks have been advised of the issuance and the terms thereof. As a consequence of this issuance, CIBC World Markets Inc., National Bank Financial Inc., Scotia Capital Inc., RBC Dominion Securities Inc. and BMO Nesbitt Burns Inc. will receive their respective share of the Underwriters' fee. In addition, Scotia Capital Inc. (together with its affiliate, Scotia Waterous Inc.) was retained by the Trust in connection with the Acquisition and will receive a fee from the Trust on completion of the Acquisition.

CIBC World Markets Inc. was retained by the Vendor in connection with the Acquisition and will receive a fee from the Vendor on completion of the Acquisition.

CIBC World Markets Inc. and Scotia Capital Inc. have performed financial advisory work for the Trust since the commencement of the Trust's last completed fiscal year.

INTEREST OF EXPERTS

Certain legal matters relating to the offering will be passed upon by Burnet, Duckworth & Palmer LLP on behalf of the Trust, and by Blake, Cassels & Graydon LLP on behalf of the Underwriters. As at the date hereof, the partners and associates of Burnet, Duckworth & Palmer LLP, as a group, owned less than 1% of outstanding Trust Units and the partners and associates of Blake, Cassels & Graydon LLP, as a group, own, directly or indirectly, less than 1% of the Trust Units. Oil and natural gas reserve estimates contained in or incorporated by reference into this short form prospectus have been prepared by GLJ. As of the date hereof, the directors, officers and associates of GLJ, as a group, own, directly or indirectly, less than 1% of the Trust Units.

CANADIAN FEDERAL INCOME TAX CONSIDERATIONS

In the opinion of Burnet, Duckworth & Palmer LLP and Blake, Cassels & Graydon LLP (collectively, "Counsel"), the following summary fairly describes the principal Canadian federal income tax considerations pursuant to the Tax Act and the regulations thereunder (the "Regulations") generally applicable to a subscriber who acquires Subscription Receipts pursuant to the offering and who at all relevant times, for purposes of the Tax Act, is resident or deemed to be resident in Canada, holds the Subscription Receipts and the Units issued pursuant to the Subscription Receipts (collectively, the "Securities") as capital property and deals at arm's length with the Trust and the Underwriters and is not affiliated with the Trust. 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 Units as capital property may, in certain circumstances, be entitled to have them treated

as capital property by making the election permitted by subsection 39(4) of the Tax Act. This summary is not applicable to: (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 and Counsel's understanding of the current published administrative practices of the Canada Revenue Agency ("CRA"). Except for specifically proposed amendments (the "Proposed Amendments") to the Tax Act and the Regulations that have been publicly announced by the federal Minister of Finance prior to the date hereof, this summary does not take into account or anticipate changes thereto, whether by legislative, regulatory or judicial action, nor any changes in the administrative practices of the CRA. This summary is not exhaustive of all Canadian federal income tax considerations nor does it take into account any provincial, territorial or foreign tax considerations arising from the acquisition, ownership or disposition of the Securities. Except as otherwise indicated, this summary is based on the assumption that all transactions described herein occur at fair market value.

Prospective Unitholders that are registered pension plans or who are not resident (or deemed not to be resident) in Canada should consult their own tax advisors regarding the income tax considerations applicable to them in their particular circumstances.

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.

Holders of Securities Resident in Canada

Subscription Receipts

No gain or loss will be realized by a holder on the issuance of a Unit pursuant to a Subscription Receipt. If the Acquisition is completed prior to the Termination Time, the holder of a Subscription Receipt will be required to include in income the amount equal to the distributions that the holder would have received on such Unit had the Unit been issued to the holder on the date of closing of this offering, and such amount will not reduce the cost of the acquired Units. The cost of any Units acquired must be averaged with the cost of any other Units held by the Unitholder to determine the adjusted cost base of each Unit held.

In the event the Acquisition does not close before the Termination Time or if the Acquisition is terminated at an earlier time, holders of Subscription Receipts will be required to include their proportionate share of interest on the Escrowed Funds in computing their income for purposes of the Tax Act.

A disposition or deemed disposition by a holder of a Subscription Receipt, other than on the exchange thereof for a Unit, 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. Prior to delivery of a Unit pursuant to a Subscription Receipt, the cost of a Subscription Receipt need not be averaged with the cost of any Units held. Any such capital gains or capital losses will be treated, for tax purposes in the same manner as capital gains and capital losses arising from a disposition of Units, which treatment is described below under "Holders of Securities Resident in Canada — Units".

Units

Income of a Unitholder from the Units will be considered to be income from property and not resource income (or "resource profits") for the purposes of the Tax Act. Any loss of the Trust for the purposes of the Tax Act cannot be allocated to and treated as a loss of a Unitholder.

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 determined for purposes of the Tax Act, that is paid or payable to the Unitholder in that particular taxation year.

Provided that appropriate designations are made by the Trust, such portions of its net taxable capital gains and taxable dividends as are paid or payable to a Unitholder will effectively retain their character as taxable capital gains and taxable dividends, respectively, and shall be treated as such in the hands of the Unitholder for purposes of the Tax Act. Such dividends will be subject, among other things, to the gross-up and dividend tax credit provisions in respect of individuals, the refundable tax under Part IV of the Tax Act in respect of certain corporations, and the deduction in computing taxable income in respect of dividends received by taxable Canadian corporations.

Based on the distribution policy of the Trust, the amount distributed to Unitholders in a year may exceed the income of the Trust for tax purposes for that year. Distributions in excess of the Trust's taxable income in a year will not generally be included in computing the income of the Unitholders from the Trust for tax purposes. However, a Unitholder is required to reduce the adjusted cost base of the Unitholder's Trust Units by the portion of any amount paid or payable to the Unitholder by the Trust (other than the non-taxable portion of certain capital gains) that was not included in computing Unitholder's income, and will realize a capital gain in a year to the extent the adjusted cost base of the Unitholder's units becomes a negative amount.

Upon the disposition or deemed disposition by a holder of a 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 Unit and any reasonable costs of disposition. The cost of any Units acquired must be averaged with the cost of any other Units held by the Unitholder to determine the adjusted cost base of each Unit held. Where Units are redeemed and notes of PC are distributed or Repurchase Notes are issued to the Unitholder in satisfaction of the aggregate redemption price, the proceeds of disposition to the holder of the Units will generally be equal to the adjusted cost base to the Trust of the notes of PC so distributed or the fair market value of the Repurchase Notes so issued, as the case may be. A capital loss realized on the disposition of a Unit will generally be reduced by the amount of any non-taxable dividends payable to the Unitholder and, where the Unitholder is a corporation, the amount of any taxable dividends that are deductible by the corporation in computing taxable income. Similar rules apply where the Unitholder is a partnership or a Trust. Where a Unitholder that is a corporation or a Trust (other than a mutual fund trust) disposes of a Unit, the Unitholder's capital loss from the disposition will generally be reduced by the amount of dividends from taxable Canadian corporations previously designated by the Trust to the Unitholder except to the extent that a loss on a previous disposition of a Unit has been reduced by such dividends. Analogous rules apply where a corporation or Trust (other than a mutual fund trust) is a member of a partnership that disposes of Units.

One-half of any capital gain realized by a Unitholder on a disposition or deemed disposition of Units, and the amount of any net taxable capital gains designated by the Trust in respect of the Unitholder, will be included in the Unitholder's income under the Tax Act in the year of disposition or designation, as the case may be, as a taxable capital gain. To the extent and under the circumstances described in the Tax Act, one-half of any capital loss (an "allowable capital loss") realized by a Unitholder upon a disposition of Units must be deducted against any taxable capital gains realized by the Unitholder in the applicable taxation year and any excess thereof may be deducted against, (i) net taxable capital gains in any of the three preceding taxation years, and (ii) net taxable capital gains in any subsequent taxation year.

The cost of any note of PC distributed or Repurchase Note issued to a Unitholder by the Trust upon a redemption of Units will be equal to the fair market value of the note of PC or Repurchase Note, as the case may be, at the time of the distribution or issuance, as applicable, less any accrued interest thereon. Such a Unitholder will be required to include in income interest paid or accrued on the note of PC or Repurchase Note in accordance with the provisions of the Tax Act. To the extent that a Unitholder is required to include in income any interest that had accrued to the date of the acquisition of the note of PC or Repurchase Note, an offsetting deduction may be available. For purposes of computing the adjusted cost base to a holder of notes of PC or Repurchase Notes the respective costs must be averaged with the adjusted cost base to the holder of all other notes of PC or Repurchase Notes, as the case may be, held at that time by the holder as capital property.

Unitholders who receive a note of PC or a Repurchase Note should consult their own tax advisors with respect to the income tax consequences of holding such note or Repurchase Note.

Taxable capital gains realized by a Unitholder who is an individual may give rise to 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 6²/3% on certain investment income, including income that was received or became receivable from the Trust in the relevant taxation year and taxable capital gains arising from a disposition of Units.

Provided that the Trust qualifies as a mutual fund trust under the Tax Act, the Units will be qualified investments for Trusts governed by Exempt Plans. Exempt Plans will generally not be liable for tax in respect of any distributions received from the Trust or any capital gain realized on the disposition of any Units. If the Trust ceases to qualify as a mutual fund trust, the Units will cease to be qualified investments for Exempt Plans. Where, at the end of any month, an Exempt Plan holds Units that are not qualified investments, the Exempt Plan must, in respect of that month, pay a tax under Part XI.1 of the Tax Act equal to 1% of the fair market value of the Units at the time such Units were acquired by the Exempt Plan. In addition, where a Trust governed by a registered retirement savings plan or a registered retirement income fund holds Units that are not qualified investments, the Trust will become taxable on its income attributable to the Units while they are not qualified investments. Where a Trust governed by a registered education savings plan holds Units that are not qualified investments, the registration of the registered education savings plan may be revoked.

The Trust

Status of the Trust

Based upon representations of PC and the Trustee as to certain factual matters, the Trust qualifies as a "unit trust" and a "mutual fund trust" as defined in the Tax Act, and this summary assumes that the Trust will also qualify at the time of acquisition of the Subscription Receipts by subscribers under this offering, and will continue to qualify thereafter, as a unit trust and as a mutual fund trust for the purposes of the Tax Act. The qualification of the Trust as a mutual fund trust under the Tax Act requires that certain factual conditions generally be met throughout its existence. These conditions generally include that the Trust must generally have at least 150 Unitholders each of whom owns not less than one "block" of Units having an aggregate fair market value of not less than $500 where a "block" of Units, in this case, means 100 Units if the fair market value of one Unit is less than $25. The Trust must also restrict its activities to investing and may not carry on any business. The Trust must also not be established nor maintained primarily for the benefit of non-residents, unless, at all times since the formation of the Trust, all or substantially all of the Trust's property consists of property other than taxable Canadian property. Under proposed amendments announced in the 2004 Federal Budget and released as draft legislation on September 16, 2004, a trust would be considered to be maintained primarily for the benefit of non-residents and would cease to qualify as a mutual fund trust at the time trust units having more than 50% of the fair market value of all issued trust units are held by non-residents of Canada or partnerships in which all of the partners are not residents of Canada (a "non-Canadian partnership"). However, in a press release issued on December 6, 2004 the Minister of Finance indicated that these proposed amendments would be suspended and further discussions would take place with the private sector concerning the appropriate tax treatment of investments by non-residents in mutual fund trusts holding interest in resource properties. Accordingly the Notice of Ways and Means Motion tabled by the Minister of Finance on December 6, 2004 did not include the proposed amendments relating to investments in mutual fund trusts by non-residents originally released on September 16, 2004. Based on information provided to the Trust by its transfer agent and registrar, as at October 31, 2005, non-residents held approximately 74% of the then outstanding Units. See the discussion under the headings "Risk Factors — Risks Related to the Securities Markets and the Ownership of Trust Units — Mutual Fund Trust" and "Risk Factors — Risks Related to the Securities Markets and the Ownership of Trust Units — Change in the Trust's Status under Tax Laws" in the AIF.

Counsel has been advised by PC that the Trust has satisfied the foregoing factual requirements and that it is intended these requirements will continue to be satisfied so that the Trust will continue to qualify as a mutual fund trust, and the balance of this summary assumes that the Trust does and will continue to so qualify. In the event the Trust were not to qualify as a mutual fund Trust, the income tax considerations would, in some

respects, be materially different from those described below. The Trust will continue to so qualify as a mutual fund trust throughout its taxation year if it so qualifies at the beginning of the taxation year and it would not otherwise qualify at any other particular time in such taxation year solely by virtue of a failure to satisfy the requirement regarding dispersal of ownership of Units.

If the Trust ceases to qualify as a mutual fund trust, it will be required to pay a tax under Part XII.2 of the Tax Act. The payment of Part XII.2 tax by the Trust may have adverse income tax consequences for certain Unitholders including non-resident persons and Exempt Plans that acquire an interest in the Trust.

Taxation of the Trust

The Trust is subject to taxation in each taxation year on its income for the year, including net realized taxable capital gains, less the portion thereof that is paid or payable in the year to Unitholders and which is deducted by the 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 is the calendar year.

The Trust will be required to include in its income any amounts accrued in respect of the royalties held by the Trust. The Trust will also be required to include in its income interest that accrues to the Trust to the end of the year, or becomes receivable or is received by the Trust before the end of the year, except to the extent that such interest was included in computing its income for a preceding taxation year, any dividends paid or deemed to be received on shares owned by the Trust and any amounts paid or payable to the Trust in respect of its interest in PVT. Provided that appropriate designations are made by the Trust, all dividends which would otherwise be included in its income as dividends received on shares held by the Trust will be deemed to have been received by Unitholders and not to have been received by the Trust.

Generally, the Trust may 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 ("COGPE") account at the end of that year, pro-rated for short taxation years. If, after taking into account all additions and deductions for any taxation year, the balance of the cumulative COGPE account of the Trust is negative at the end of the taxation year, the negative balance will be included in the income of the Trust for such year.

Where as a result of a release or other disposition of a royalty by the Trust, proceeds of disposition become receivable by the Trust in a taxation year, the amount of such proceeds ("Disposition Proceeds") will be required to be deducted from the balance of the Trust's cumulative COGPE account otherwise determined. If all or a portion of the Disposition Proceeds receivable in a taxation year is utilized in that year by the Trust to acquire additional interests in respect of one or more "Canadian resource properties", as defined under the Tax Act, the amount so utilized will be added, in that year, to its cumulative COGPE account.

In addition to annual deductions in respect of its cumulative COGPE account, the Trust will be entitled to deduct on an annual basis reasonable administrative expenses incurred in its ongoing operations. Generally, the Trust will be entitled to deduct, over five years on a straight-line basis pro-rated for short taxation years, reasonable costs incurred by it in connection with the issuance of Units, including Units issued by way of the Subscription Receipts provided such Units are issued.

Under the Trust Indenture, an amount equal to all of the royalty, interest, dividend and other income of the Trust for each year, together with the taxable and non-taxable portion of any capital gains realized by the Trust in the year (net of the Trust's expenses and amounts, if any, required to be retained to pay any tax liability of the Trust and certain other amounts) will be payable to the holders of Units. Disposition Proceeds will also be payable to the holders of Units to the extent such proceeds create a negative balance in the cumulative COGPE account of the Trust as of December 31 of any year. Subject to the exceptions described below, all amounts payable to the holders of Units shall be paid by way of cash distributions. Under the Trust Indenture, the Trust may, in certain circumstances, issue its own notes ("Repurchase Notes") or distribute notes of PC held by the Trust to finance the repurchase of Units.

For purposes of the Tax Act, Counsel is advised that the Trust intends to deduct, in computing its income, the full amount available for deduction in each year to the extent of its income for the year otherwise

determined. As a result of such deduction from income, it is expected that the Trust will not be liable for any material amount of tax under the Tax Act. However, no assurances can be given in this regard. Losses incurred by the Trust cannot be allocated to Unitholders but may be deducted by the Trust in future years in accordance with the Tax Act.

RISK FACTORS

An investment in the Subscription Receipts and Units is subject to certain risks. Investors should carefully consider the risks described under "Risk Factors" in the AIF in addition to the following risk factors.

Possible Failure to Realize Anticipated Benefits of Acquisitions

The Trust has completed a number of acquisitions to date in 2005 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 ability to realize the anticipated growth opportunities and synergies from combining the acquired businesses and operations with those of PC and PVT. 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.

Possible Failure to Complete the Acquisition

The Acquisition is subject to normal commercial risk that the Acquisition may not be completed on the terms negotiated or at all. If closing of the Acquisition does not take place by the Termination Time, the Escrow Agent and the Trust will repay to holders of Subscription Receipts, commencing on or before the second Business Day following the Termination Time, an amount equal to the issue price therefor plus a pro rata share of the interest earned on the Escrowed Funds.

Pursuant to the Purchase Agreement, PC paid a deposit of $48.5 million (the "Deposit") to the Vendor which amount will be credited to the purchase price in the event the Acquisition is completed and will be retained by the Vendor if the Acquisition is not completed in certain circumstances.

See "Recent Developments — The Acquisition".

Operational and Reserve Risks Relating to the New Properties

The risk factors set forth in the Trust's AIF and in this short form prospectus relating to the oil and natural gas business and the operations and reserves of the Trust apply equally in respect of the New Properties that the Trust is acquiring pursuant to the Acquisition. In particular, the reserve and recovery information contained in the GLJ Report in respect of the New Properties is only an estimate and the actual production from and ultimate reserves of those properties may be greater or less than the estimates contained in such report.

Market for Subscription Receipts

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, that such a market will be sustained at the price level of the offering.

Reserve Estimates

The reserve and recovery information contained in the GLJ Report and in the reserve reports as described in or incorporated by reference in this short form prospectus are only estimates and the actual production and

ultimate reserves from the properties may be greater or less than the estimates prepared. In addition, probable reserve estimates for properties may require revision based on the actual development strategies employed to prove such reserves. Estimated reserves may also be affected by changes in oil and natural gas prices. Declines in the reserves of PC and PVT which are not offset by the acquisition or development of additional reserves may reduce the underlying value of Units to Unitholders.

Credit Facilities — Limitations on Distributions

PC presently has in place the Current Credit Facilities and is negotiating the New Credit Facilities which will be utilized to pay for a portion of the purchase price of the Acquisition. See Note 1 to the table under the heading "Consolidated Capitalization of the Trust". The terms of the Current Credit Facilities may restrict future cash distributions to Unitholders as described in the AIF under "Information Relating to the Trust — Credit Facility — Limitations on Distributions". It is expected that the New Credit Facilities will, similarly to the Current Credit Facilities, contain terms which may restrict future cash distributions to Unitholders. The New Credit Facilities will increase the total debt of the Trust; however, the Trust does not expect that the terms of the New Credit Facilities will have any incremental or additional impact on future cash distributions.

Refinancing of Credit Facilities

Although PC has in place the Current Credit Facilities and is negotiating the New Credit Facilities, if it is necessary at some future time for PC to obtain alternative financing, there is no assurance that refinancing will be available or, if available, available on favourable terms. If the Trust is unable to refinance on favourable terms cash distributions may be unfavourably impacted.

MATERIAL CONTRACTS

The only material contracts entered into or to be entered into by the Trust in connection with the offering are as follows:

(a): the Subscription Receipt Agreement; and
(b): the Underwriting Agreement.

Copies of the foregoing agreements (in draft form prior to closing in the case of the Subscription Receipt Agreement) may be inspected during regular business hours at the offices of the Trust, at 600, 444 - 7^th Avenue S.W., Calgary, Alberta, T2P 0X8 until the expiry of the 30-day period following the date of the final short form prospectus.

LEGAL PROCEEDINGS

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

AUDITORS, TRANSFER AGENT AND REGISTRAR

The auditors of the Trust are Deloitte & Touche LLP, Chartered Accountants, 3000, 700 - 2^nd Street S.W., Calgary, Alberta, T2P 0S7.

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

CONSENT OF AUDITORS

We have read the short form prospectus of Petrofund Energy Trust (the "Trust") dated November 30, 2005 (the "Prospectus") qualifying the distribution of subscription receipts. We have complied with Canadian generally accepted standards for an auditor's involvement with offering documents.

We consent to the incorporation by reference in the Prospectus of our report to the unitholders of the Trust on the consolidated balance sheet of the Trust as at December 31, 2004 and 2003 and the consolidated statements of operations and accumulated earnings and cash flows for each of the years in the three-year period ended December 31, 2004. Our report is dated March 1, 2005.

We also consent to the incorporation by reference in the Prospectus of our report to the Directors of Ultima Ventures Corp. and Ultima Acquisitions Corp. on the consolidated balance sheet of Ultima Energy Trust as at December 31, 2003 and 2002 and the consolidated statements of income and deficit and cash flows for the years then ended. Our report is dated February 24, 2004 (except as to Notes 14 and 15 which are as of April 30, 2004).

Calgary, Canada		(Signed) DELOITTE & TOUCHE LLP
November 30, 2005		Chartered Accountants

CONSENT OF AUDITORS

We have read the short form prospectus of Petrofund Energy Trust (the "Trust") dated November 30, 2005 relating to the qualification for distribution of 12,500,000 subscription receipts, each representing the right to receive one trust unit of the Trust. We have complied with Canadian generally accepted standards for an auditor's involvement with offering documents.

We consent to the use in the above-mentioned short form prospectus of our report to the directors of Kaiser Energy Ltd. on the consolidated balance sheets of Kaiser Energy Ltd. as at December 31, 2004 and 2003 and the consolidated statements of operations and retained earnings (deficit) and cash flows for the years then ended. Our report is dated September 16, 2005, except as to notes 13 and 14 which are as of November 30, 2005.

We consent to the use in the above-mentioned short form prospectus of our report to the directors of Kaiser-Francis Oil Company of Canada on the balance sheets of Canadian Acquisition Limited Partnership as at December 31, 2004 and 2003 and the statements of operations and cash flows for the years then ended. Our report is dated September 16, 2005, except as to notes 7 and 8 which are as of November 30, 2005.

We consent to the use in the above-mentioned short form prospectus of our report to the directors of Kaiser Energy Ltd. on the statement of revenue and operating costs for the properties to be transferred to Kaiser Energy Ltd. for the years ended December 31, 2004 and 2003. Our report is dated September 16, 2005, except as to notes 4 and 5 which are as of November 30, 2005.

Calgary, Canada		(Signed) COLLINS BARROW CALGARY LLP
November 30, 2005		Chartered Accountants

OTHER SUPPLEMENTAL DISCLOSURES ABOUT OIL AND GAS ACTIVITIES
(unaudited)

The tables in this section set forth oil and gas information prepared by the Trust in accordance with U.S. disclosure standards, pertaining to FAS 69, "Disclosure about Oil and Gas Producing Activities".

Standardized Measure of Discounted Future Net Cash Flows and Changes Therein

In calculating the standardized measure of discounted future net cash flows, year-end constant prices and cost assumptions were applied to the Trust's annual future production from proved reserves to determine cash inflows. Future production and development costs are based on constant price assumptions and assume the continuation of existing economic, operating and regulatory conditions. Future income taxes are calculated by applying statutory income tax rates to future pre-tax cash flows after provision for the tax cost of the oil and natural gas properties based upon existing laws and regulations. The Trust is currently not taxable. The discount was computed by application of a 10 percent discount factor to the future net cash flows. The calculation of the standardized measure of discounted future net cash flows is based upon the discounted future net cash flows prepared by the Trust's independent qualified reserves evaluators in relation to the reserves they respectively evaluated, and adjusted by the Trust is to account for management's estimates of risk management activities, asset retirement obligations and future income taxes.

The Trust cautions that the discounted future net cash flows relating to proved oil and gas reserves are an indication of neither the fair market value of the Trust's oil and gas properties, nor of the future net cash flows expected to be generated from such properties. The discounted future cash flows do not include the fair market value of exploratory properties and probable or possible oil and gas reserves, nor is consideration given to the effect of anticipated future changes in crude oil and natural gas prices, development, asset retirement and production costs and possible changes to tax and royalty regulations. The prescribed discount rate of 10 percent may not appropriately reflect future interest rates.

Capitalized Costs Relating to Oil and Gas Producing Activities
($ thousands)

	As at December 31,
	2004		2003		2002
Proved oil and gas properties	$	1,858,291	$	1,364,296	$	1,194,736
Unproved oil and gas properties		21,071		16,316		25,436

Total capital costs⁽¹⁾		1,879,362		1,380,612		1,220,172
Accumulated depletion and depreciation		793,886		658,151		587,457

Net capitalized costs	$	1,085,476	$	722,461	$	632,715

(1): Certain numbers have been restated to conform to the 2004 presentation, as indicated in the Trust's 2004 Annual Report.

Costs Incurred in Oil and Gas Property Acquisition,
Exploration and Development Activities
($ thousands)

		For the Years Ended December 31,⁽¹⁾
		2004		2003		2002
Property acquisition costs⁽¹⁾
	Proved oil and gas properties	$	605,840	$	82,100	$	188,500
	Unproved oil and gas properties		1,695		1,700		2,300
Exploration costs⁽²⁾			678		5,700		2,670
Development costs⁽³⁾			75,637		64,000		35,830

Total		$	683,850	$	153,500	$	229,300

(1): Acquisitions are net of disposition of properties.
(2): Cost of geological and geophysical capital expenditures and drilling costs for exploration wells drilled.
(3): Development and facilities capital expenditures.

Results of Operations for Producing Activities
($ thousands)

	For the Years Ended December 31,⁽¹⁾
	2004		2003		2002
Oil and gas sales, net of royalties and commodity contracts	$	368,139	$	313,787	$	224,758
Lease operating costs and capital taxes		106,871		93,705		76,911
Transportation costs		5,862		5,482		4,516
Depletion, depreciation and accretion		138,495		95,044		80,081

Operating income		116,911		119,556		63,250
Income taxes⁽²⁾		539		569		38

Results of operations	$	116,372	$	118,987	$	63,212

(1): Certain numbers have been restated to conform to the 2004 presentation, as indicated in the Trust's 2004 Annual Report.
(2): The Trust is currently not taxable, current income tax disclosed for the years 2002 through 2004 represent Large Corporation Tax, which is calculated by reference to balance sheet items (debt and equity) and not by income items.

Reserve Quantity Information for the Year Ended December 31, 2004*
Constant Prices and Costs

	Net Proved Developed and Proved Undeveloped Reserves
	Light and Medium Oil		Heavy Oil		Natural Gas		Natural Gas Liquids		Barrels of Oil Equivalent
	(mbbls)		(mbbls)		(bcf)		(mbbls)		(mboe)
Beginning of year	37,793		750		164		4,036		69,957
Extensions	170		—		6		17		1,005
Improved recovery	567		45		9		56		2,090
Technical revisions	2,769		168		7		353		4,461
Discoveries	—		—		1		8		151
Acquisitions	23,163		—		21		594		27,305
Dispositions	—		—		—		—		(26	)
Economic factors	36		4		1		9		138
Production	(4,757	)	(95	)	(24	)	(596	)	(9,482	)

End of year	59,740		872		184		4,477		95,694

	Net Proved Developed Reserves
	Light and Medium oil	Heavy Oil	Natural Gas	Natural Gas Liquids	Barrels of Oil Equivalent
	(mbbls)	(mbbls)	(bcf)	(mbbls)	(mboe)
Beginning of year	29,978	750	160	3,781	61,192
End of year	45,872	872	176	4,160	80,245

*: Columns may not add due to rounding.

Standardized Measure of Discounted Future Net Cash Flows
Relating to Proved Oil and Gas Reserves
($ thousands)

	2004
Future cash inflows	$	3,761,000
Future production costs		1,489,000
Future development costs		251,000

Undiscounted pre-tax cash flows		2,021,000
Future income taxes⁽¹⁾		—

Future net cash flows		2,021,000
Less 10% annual discount factor		864,000

Standardized measure of discounted future net cash flows	$	1,157,000

(1): The Trust is currently not taxable.

Reconciliation of Changes in Standardized Measure of Discounted Future Net Cash Flows
Relating to Proved Oil and Gas Reserves
($ thousands)

	2004
Standardized measure of discounted future net cash flows, beginning of year	$	815,000
Oil and gas sales during the period⁽¹⁾		(313,000	)
Changes due to prices, production costs and royalties related to forecast production⁽²⁾		133,000
Development costs during the period⁽³⁾		(78,000	)
Changes in forecast development costs⁽⁴⁾		90,000
Changes resulting from extensions and improved recovery⁽⁵⁾		40,000
Changes resulting from discoveries⁽⁵⁾		2,000
Changes resulting from acquisitions of reserves⁽⁵⁾		321,000
Changes resulting from dispositions of reserves⁽⁵⁾		—
Accretion of discount⁽⁶⁾		81,000
Net change in income taxes⁽⁷⁾		—
Changes resulting from technical reserves revisions plus all other changes		66,000

Standardized measure of discounted future net cash flows, end of year	$	1,157,000

(1): Net of production costs and royalties, before income taxes.
(2): The impact of changes in prices and other economic factors on future net revenue.
(3): Actual capital expenditures relating to the exploration and development and production of oil and gas reserves.
(4): Includes the difference between actual and forecast development costs during the period.
(5): Production and capital costs associated with recovery of the related reserves are included in this category.
(6): 10% of after adjustments for dispositions.

(7): Includes the difference between actual and forecast income taxes during the period. The Trust is currently not taxable.

DOCUMENTS FILED AS PART OF THE REGISTRATION STATEMENT

The following documents have been filed with the SEC as part of the Registration Statement of which this prospectus forms a part: the Agreement of Purchase and Sale dated November 16, 2005 between Kaiser-Francis Oil Company of Canada and Petrofund Corp.; the Underwriting Agreement between the Trust and the underwriters listed therein, dated November 18, 2005; the documents referred to under "Documents Incorporated by Reference"; consents of Deloitte & Touche LLP, Burnet, Duckworth & Palmer LLP, Blake, Cassels & Graydon LLP, GLJ Petroleum Consultants Ltd. and Collins Barrow Calgary LLP; Power of Attorney; and the Amended and Restated Trust Indenture dated November 16, 2004 between the Trust and Computershare Trust Company of Canada, as trustee.

PRO FORMA COMBINED FINANCIAL
STATEMENTS OF THE TRUST

COMPILATION REPORT

To the Directors of Petrofund Corp.

We have read the accompanying unaudited pro forma combined balance sheet of Petrofund Energy Trust ("Petrofund") as at September 30, 2005 and unaudited combined statements of operations for the nine months then ended and for the year ended December 31, 2004, and have performed the following procedures.

1.

Compared the figures in the column captioned "Petrofund Energy" to the unaudited Consolidated Financial Statements of Petrofund as at September 30, 2005 and for the nine months then ended, and the audited Consolidated Financial Statements of Petrofund as at December 31, 2004 and for the year then ended and found them to be in agreement.

2.

Compared the figures in the columns captioned "Ultima Energy" to the unaudited Consolidated Financial Statements of Ultima Energy Trust ("Ultima") as at March 31, 2004 and for the three months then ended and to Ultima's accounting records for the period April 1, 2004 to June 16, 2004, and found them to be in agreement.

3.

Compared the figures in the columns captioned "Kaiser Energy" to the unaudited consolidated Financial Statements of Kaiser Energy Ltd. as at September 30, 2005 and for the nine months then ended and to the audited consolidated Financial Statements of Kaiser Energy Ltd. as at December 31, 2004 and for the year then ended and found them to be in agreement.

4.

Compared the figures in the columns captioned "Canadian Partnership" to the unaudited Financial Statements of Canadian Acquisition Limited Partnership ("Canadian Partnership") as at September 30, 2005 and for the nine months then ended and to the audited Financial Statements of Canadian Partnership as at December 31, 2004 and for the year then ended and found them to be in agreement.

5.

Compared the figures in the columns captioned "Properties to be Transferred" to the unaudited statement of revenue and operating costs for the Properties to be Transferred to Kaiser Energy Ltd. for the nine months ended September 30, 2005 and the audited statement of revenue and operating costs of the Properties to be Transferred to Kaiser Energy Ltd. for the year ended December 31, 2004 and found them to be in agreement.

6.

Made enquiries of certain officials of Petrofund who have responsibility for financial and accounting matters about:

(a): the basis for determination of the pro forma adjustments; and
(b): whether the pro forma combined financial statements comply as to form in all material respects with the regulatory requirements of the various Securities Commissions and similar regulatory authorities in Canada.

The officials of Petrofund:

(a): described to us the basis for determination of the pro forma adjustments, and
(b): stated that the pro forma combined 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 combined financial statements and found them to be consistent with the basis described to us for determination of the pro forma adjustments.

F-1

8.: Recalculated the application of the pro forma adjustments to the aggregate of the amounts in the captioned "Petrofund Energy", "Ultima Energy", "Kaiser Energy", "Canadian Partnership", and "Properties to be Transferred" columns, as applicable as at September 30, 2005 and for the nine months then ended, and the year ended December 31, 2004, and found the amounts in the column captioned "Pro Forma Combined" to be arithmetically correct.

A pro forma financial statement is based on management assumptions and adjustments which are inherently subjective. The forgoing 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 assumption, 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 combined financial statements, and we therefore make no representation about the sufficiency of the procedures for the purposes of a reader of such statement.

Calgary, Alberta		(Signed) DELOITTE & TOUCHE LLP
November 30, 2005		Chartered Accountants

F-2

COMMENTS BY INDEPENDENT REGISTERED CHARTERED ACCOUNTANTS FOR
UNITED STATES OF AMERICA READERS ON DIFFERENCES
BETWEEN CANADIAN AND UNITED STATES REPORTING STANDARDS

The above compilation report, provided solely pursuant to Canadian requirements, is expressed in accordance with standards of reporting generally accepted in Canada. To report in conformity with the United States of America standards on the reasonableness of the pro forma adjustments and their application to the pro forma financial statements would require an examination or review which would be substantially greater in scope than the review as to compilation only that we have conducted. Consequently, under the United States of America standards, such compilation report would not be included.

Calgary, Alberta		(Signed) DELOITTE & TOUCHE LLP
November 30, 2005		Independent Registered Chartered Accountants

F-3

PETROFUND ENERGY TRUST

PRO FORMA COMBINED BALANCE SHEET

As at September 30, 2005
(thousands of Canadian dollars)
(unaudited)

		Petrofund Energy			Kaiser Energy			Canadian Partnership			Properties to be Transferred		Pro Forma Adjustments			Pro Forma Combined			Notes
Assets
Current assets
	Cash	$	7,993		$	78,262		$	—		$	—	$	(78,262	)	$	7,993		2
	Accounts receivable		47,671			24,112			281			—		(24,393	)		47,671		2
	Due from affiliates		—			672			2,540			—		(3,212	)		—		2
	Deferred loss on commodity contracts		129			—			—			—		—			129		—
	Commodity contracts		745			—			—			—		—			745		—
	Prepaid expenses		16,591			1,526			3			—		(1,529	)		16,591		2

Total current assets			73,129			104,572			2,824			—		(107,396	)		73,129		—
Asset retirement reserve fund			8,538			—			—			—		—			8,538		—
Goodwill			190,247			—			—			—		159,822			350,069		2.2
Oil and natural gas royalty and property interests, net			1,297,522			63,015			15,616			—		417,268			1,793,421		2.2

		$	1,569,436		$	167,587		$	18,440		$	—	$	469,694		$	2,225,157		—

Liabilities and Unitholders' Equity
Current liabilities
	Accounts payable and accrued liabilities	$	42,052		$	14,612		$	456		$	—	$	(15,068	)	$	42,052		2
	Due to affiliates		—			10,637			—			—		(10,637	)		—		2
	Deferred gain on commodity contracts		38			—			—			—		—			38		—
	Commodity contracts		37,051			—			—			—		—			37,051		—
	Distributions payable to Unitholders		18,126			—			—			—		—			18,126		—

Total current liabilities			97,267			25,249			456			—		(25,705	)		97,267		—
Long-term debt			244,499			—			—			—		248,815			493,314		2.2
Future income taxes			87,658			24,154			—			—		134,799			246,611		2.2
Asset retirement obligations			55,266			989			795			—		9,369			66,419		2.2

			484,690			50,392			1,251			—		367,278			903,611		—

Unitholders' equity
Unitholders' capital			1,560,317			—			—			—		236,800			1,797,117		2.2
Exchangeable shares			6,038			—			—			—		—			6,038		—
Share capital			—			72,900			—			—		(72,900	)		—		2.2
Partners' capital, beginning of year			—			—			15,675			—		(15,675	)		—		2.2
Contributed surplus			—			68,776			—			—		(68,776	)		—		2.2
Accumulated earnings (deficit)			383,257			(24,481	)		10,904			—		13,577			383,257		2.2
Accumulated cash distributions			(864,866	)		—			—			—		—			(864,866	)	—
Withdrawals			—			—			(9,390	)		—		9,390			—		2.2

			1,084,746			117,195			17,189			—		102,416			1,321,546		—

		$	1,569,436		$	167,587		$	18,440		$	—	$	469,694		$	2,225,157		—

The accompanying notes are an integral part of this pro forma financial statement.

F-4

PETROFUND ENERGY TRUST

PRO FORMA COMBINED STATEMENT OF OPERATIONS

For the Nine Months Ended September 30, 2005
(thousands of Canadian dollars, except per unit amounts)
(unaudited)

		Petrofund Energy			Kaiser Energy			Canadian Partnership			Properties to be Transferred			Pro Forma Adjustments			Pro Forma Combined			Notes
Revenues
	Oil and natural gas sales	$	540,003		$	34,773		$	18,892		$	30,883		$	(7,949	)	$	616,602		2.5
	Royalties		(105,048	)		(7,378	)		(3,158	)		(6,760	)		1,783			(120,561	)	2.5
	Loss on commodity contracts		(54,254	)		—			—			—			—			(54,254	)	—

			380,701			27,395			15,734			24,123			(6,166	)		441,787		—

Expenses
	Lease operating		103,245			4,861			2,224			4,935			(4,271	)		110,994		2.5
	Transportation costs		6,222			1,030			600			894			—			8,746		—
	Financing costs		6,858			(987	)		—			—			8,038			13,909		2.4
	General and administrative		12,357			2,109			—			—			—			14,466		—
	Capital taxes		3,167			—			—			—			—			3,167		—
	Depletion, depreciation and accretion		141,960			7,571			2,006			—			36,488			188,025		2.3

			273,809			14,584			4,830			5,829			40,255			339,307		—

Income (loss) before the following			106,892			12,811			10,904			18,294			(46,421	)		102,480		—
Donations of trust units			—			(77,784	)		—			—			77,784			—		2.6
Equity loss of Taurus Exploration Ltd.			—			(14,079	)		—			—			14,079			—		2.6
Gain on disposal of partnership units			—			17,772			—			—			(17,772	)		—		2.6

Income (loss) before provision for income taxes			106,892			(61,280	)		10,904			18,294			27,670			102,480		—

Provision for (recovery of) income taxes
	Current		418			4,786			—			—			—			5,204		—
	Future		(4,171	)		(3,628	)		—			—			(12,588	)		(20,387	)	2.7

			(3,753	)		1,158			—			—			(12,588	)		(15,183	)	—

Net income (loss)		$	110,645		$	(62,438	)	$	10,904		$	18,294		$	40,258		$	117,663		—

Net Income per Trust unit
	Basic	$	1.08														$	1.02		3.0
	Diluted	$	1.08														$	1.02		3.0

The accompanying notes are an integral part of this pro forma financial statement.

F-5

PETROFUND ENERGY TRUST

PRO FORMA COMBINED STATEMENT OF OPERATIONS

For the Year Ended December 31, 2004
(thousands of Canadian dollars, except per unit amounts)
(unaudited)

					Ultima Energy
		Petrofund Energy			January 1 to March 31			April 1 to June 16			Kaiser Energy			Canadian Partnership			Properties to be Transferred			Pro Forma Adjustments			Pro Forma Combined			Notes
Revenues
	Oil and gas sales	$	517,081		$	36,176		$	34,880		$	45,154		$	23,006		$	33,204		$	(10,287	)	$	679,214		2.5
	Royalties		(100,230	)		(6,695	)		(6,099	)		(9,842	)		(3,985	)		(7,116	)		2,235			(131,732	)	2.5
	Loss on commodity contracts		(48,712	)		(5,599	)		(5,875	)		—			—			—			—			(60,186	)	—

			368,139			23,882			22,906			35,312			19,021			26,088			(8,052	)		487,296		—

Expenses
	Lease operating		103,610			6,037			7,004			6,015			3,863			7,390			(5,585	)		128,334		2.5
	Transportation costs		5,862			586			466			1,563			818			—			—			9,295		—
	Financing costs		5,849			545			371			(592	)		—			—			12,074			18,247		2.4
	General and administrative		14,441			1,778			986			1,502			—			—			—			18,707		—
	Unit based compensation		—			765			1,657			—			—			—			—			2,422		—
	Capital taxes		3,261			8			85			—			—			—			—			3,354		—
	Depletion, depreciation and accretion		153,079			12,443			10,590			10,448			2,500			—			51,493			240,553		2.3
	Merger costs		—			—			7,479			—			—			—			—			7,479		—

			286,102			22,162			28,638			18,936			7,181			7,390			57,982			428,391		—

Income (loss) before the following			82,037			1,720			(5,732	)		16,376			11,840			18,698			(66,034	)		58,905		—
Equity loss of Taurus Exploration Ltd.			—			—			—			(17,860	)		—			—			17,860			—		2.6

Income (loss) before provision for income taxes			82,037			1,720			(5,732	)		(1,484	)		11,840			18,698			(48,174	)		58,905		—

Provision for (recovery of) income taxes
	Current		539			—			—			6,993			—			—			—			7,532		—
	Future		7,139			(198	)		—			(3,710	)		—			—			(17,758	)		(14,527	)	2.7

			7,678			(198	)		—			3,283			—			—			(17,758	)		(6,995	)	—

Net income (loss)		$	74,359		$	1,918		$	(5,732	)	$	(4,767	)	$	11,840		$	18,698		$	(30,416	)	$	65,900		—

Net Income per Trust unit
	Basic	$	0.84																				$	0.58		3.0
	Diluted	$	0.84																				$	0.58		3.0

The accompanying notes are an integral part of this pro forma financial statement.

F-6

PETROFUND ENERGY TRUST

NOTES TO PRO FORMA COMBINED FINANCIAL STATEMENTS

As at and for the Nine Months Ended September 30, 2005
and for the Year Ended December 31, 2004
(unaudited)

1. BASIS OF PRESENTATION

The accompanying unaudited pro forma combined financial statements (the "Pro Forma Statements") of Petrofund Energy Trust ("Petrofund") have been prepared by management in accordance with Canadian generally accepted accounting principles ("GAAP") for inclusion in a short form prospectus relating to the sale and issue of subscription receipts.

On November 16, 2005, Petrofund entered into an agreement to acquire Kaiser Energy Ltd. ("Kaiser"). Kaiser holds (or will hold prior to the completion of the acquisition by Petrofund), either directly or indirectly, interests in Canadian Acquisition Limited Partnership ("Canadian Partnership") and certain Properties to be Transferred to Kaiser (the "Properties") (collectively, the "Kaiser Entities").

The Pro Forma Statements have been prepared from, and should be read in conjunction with:

•: The audited Consolidated Financial Statements of Petrofund as at and for the year ended December 31, 2004 and the unaudited Consolidated Financial Statements of Petrofund as at and for the nine months ended September 30, 2005;
•: The unaudited Consolidated Financial Statements of Ultima Energy Trust ("Ultima") as at and for the three months ended March 31, 2004;
•: The audited Consolidated Financial Statements of Kaiser as at and for the year ended December 31, 2004 and the unaudited Financial Statements of Kaiser as at and for the nine months ended September 30, 2005;
•: The audited Consolidated Financial Statements of Canadian Partnership as at and for the year ended December 31, 2004 and the unaudited financial statements of Canadian Partnership as at and for the nine months ended September 30, 2005; and
•: The audited statement of revenue and operating costs for the Properties for the year ended December 31, 2004 and the unaudited statement of revenue and operating costs of the Properties for the nine months ended September 30, 2005.

Other information which was available at the time of preparation of the Pro forma Statements has also been considered. In the opinion of management, these Pro Forma Statements include all material adjustments necessary for fair presentation.

The Pro Forma Statements are not necessarily indicative either of the results of operations that would have occurred for the year ended December 31, 2004 had the acquisition of the Kaiser Entities and Ultima been effected on January 1, 2004, or of the results of operations expected in 2005 and future years.

In preparing these Pro Forma Statements, no adjustments have been made to recognize any operating synergies or general and administrative cost savings which would be expected to occur as a result of combining the operations of Petrofund, Ultima and the Kaiser Entities.

F-7

2. PRO FORMA ASSUMPTIONS AND ADJUSTMENTS

The unaudited pro forma combined balance sheet as at September 30, 2005 gives effect to the acquisition by Petrofund of all of the assets and the assumption of all liabilities of the Kaiser Entities, except for working capital, and other adjustments as if they had occurred on September 30, 2005, while the unaudited pro forma combined statements of operations for the nine months ended September 30, 2005 and for the year ended December 31, 2004 gives effect to the acquisitions of the Kaiser Entities and Ultima and other adjustments as if they had occurred on January 1, 2004.

Accounting policies used in the preparation of the Pro Forma Statements is in accordance with those used in the preparation of the audited Consolidated Financial Statements of Petrofund as at and for the year ended December 31, 2004.

The Pro Forma Statements give effect to the following assumptions and adjustments:

2.1: Pursuant to the terms of a combination agreement, Petrofund issued 26.4 million Petrofund trust units which were distributed to the unitholders of Ultima on redemption of their Ultima trust units. After giving effect to the acquisition, Petrofund acquired all of the assets and assumed all of the liabilities of Ultima, and Ultima Unitholders became holders of Petrofund trust units on the basis of 0.442 Petrofund Trust units for each Ultima trust unit. The value assigned to each Petrofund trust unit of $17.12 was based on the weighted average trading price of the trust units for the period commencing five days before and ending five days after the acquisition was announced. The acquisition closed on June 16, 2004 and Ultima's assets, liabilities and results of operations have been included from that date. The following table illustrates the allocation of the purchase price to Ultima's assets and liabilities.

Purchase Price Allocation	$Cdn
	(000's)
Current assets	$	22,244
Asset retirement reserve		1,549
Goodwill		178,110
Oil and gas royalty and property interest		384,987
Current liabilities		(17,791	)
Long-term debt		(110,407	)
Asset retirement obligations		(16,672	)
Future income taxes		12,725

	$	454,745

2.2: Petrofund Energy Trust has entered into an agreement to acquire the Kaiser Entities for total consideration of Cdn $485 million, plus estimated acquisition costs of $615,000. The transaction is expected to close on or about December 15, 2005. Completion of the transaction is subject to certain regulatory and other conditions and there is no assurance that it will be completed. The transaction will be financed with a combination of proceeds from a bought deal equity financing in the amount of approximately Cdn $250 million ($236.8 million, net of issue costs) and debt drawn from Petrofund's credit facilities which are to be expanded in conjunction with the acquisition. The following table is

F-8

subject to change and illustrates the estimated determination of the purchase price and allocation to Kaiser's assets and liabilities at September 30, 2005:

Consideration	$Cdn
	(000's)
Cash consideration funded through the issuance of Trust Units, net	$	236,800
Debt issued upon acquisition		248,815

	$	485,615

Purchase Price Allocation	$Cdn
	(000's)
Oil and gas royalty and property interest	$	495,899
Goodwill		159,822
Asset retirement obligations		(11,153	)
Future income taxes		(158,953	)

	$	485,615

2.3: The provision for depletion, depreciation and accretion has been adjusted to reflect the value assigned to Ultima's and the Kaiser Entities and 100% of its oil and gas royalty and property interests and the consolidated oil and gas reserve volumes.
2.4: Financing costs has been adjusted to reflect the increase in long-term debt, effective January 1, 2004.

2.5

(a)

The results of operations have been adjusted to reflect oil and natural gas sales, royalties and lease operating costs of oil and gas properties not acquired by Petrofund.

(b): Transaction between the Kaiser Entities in respect of natural gas processing and gathering revenues and operating expenses of $3.2 million for the nine months ended September 30, 2005 and $4.3 million for the year ended December 31, 2004 have been eliminated from the statement of operations.
(c): Transaction between the Kaiser Entities in respect of gross overriding royalties and revenues of $1.1 million for the nine months ended September 30, 2005 and $1.4 million for the year ended December 31, 2004 have been eliminated from the statement of operations.

2.6: All transactions in the statement of operations related to Taurus Exploration Ltd. ("Taurus"), a wholly owned subsidiary of Kaiser, have been eliminated as all Taurus assets were disposed of prior to Petrofund's acquisition of Kaiser.
2.7: Future income taxes have been adjusted for all of the above assumptions.

F-9

3. PER UNIT INFORMATION

Pro forma net income per trust unit has been calculated using the weighted average number of Petrofund trust units and exchangeable shares of Petrofund Corp. outstanding plus Petrofund trust units issued to finance the acquisition of the Kaiser Entities and Ultima as if they had been outstanding for the respective period, as follows:

September 30, 2005 Per Unit Information

(000's)	Petrofund	December 2005	Pro Forma Combined
Basic	102,412	12,500	114,912
Diluted	102,441	12,500	114,941
At period-end	105,046	12,500	117,546

December 31, 2004 Per Unit Information

(000's)	Petrofund	Ultima Acquisition	December 2005	Pro Forma Combined
Basic	88,169	12,068	12,500	112,737
Diluted	88,292	12,068	12,500	112,860
At year-end	100,451	—	12,500	112,951

F-10

4. DIFFERENCES BETWEEN CANADIAN AND UNITED STATES GENERALLY ACCEPTED ACCOUNTING PRINCIPLES ("GAAP")

The application of U.S. GAAP would have the following effects on the pro forma combined net income and net income per trust unit of Petrofund:

($ Cdn (000's) other than per unit amounts)		Nine Months Ended September 30, 2005		Year Ended December 31, 2004
Pro forma combined net income, Canadian GAAP		$	117,663	$	65,900
Petrofund U.S. GAAP adjustments⁽²⁾			7,276		15,831
Kaiser Entities U.S. GAAP adjustments⁽¹⁾			—		—

Pro forma combined net income, U.S. GAAP		$	124,939	$	81,731

Pro forma combined net income per unit, Canadian GAAP:
	Basic	$	1.02	$	0.58
	Diluted	$	1.02	$	0.58
Pro forma combined net income per unit, U.S. GAAP:
	Basic	$	1.09	$	0.72
	Diluted	$	1.09	$	0.72

Note:

(1): None of the U.S. GAAP adjustments in the Kaiser Entities' financial statements applied to the operations acquired by Petrofund.
(2): The adjustments and related differences in generally accepted accounting principles in Canada from those followed in the United States of America are as presented in the historical consolidated financial statements of the Trust as at September 30, 2005 and for the nine months ended and for the year ended December 31, 2004.

The application of U.S. GAAP would have the following effects on the pro forma consolidated balance sheet as reported:

(000's)	Pro Forma Combined		Decrease⁽²⁾			U.S. GAAP
As at September 30, 2005
Oil and gas royalty and property interests, net	$	1,793,421	$	(149,051	)	$	1,644,370
Future income taxes		246,611		(42,734	)		203,877
Temporary equity		—		2,682,406			2,682,406
Unitholders' equity		1,321,546		(2,788,723	)		(1,467,177	)

F-11

FINANCIAL STATEMENTS OF KAISER ENERGY LTD.

AUDITORS' REPORT

To the Directors
Kaiser Energy Ltd.

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

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

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

Calgary, Alberta, Canada	(Signed) COLLINS BARROW CALGARY LLP
September 16, 2005, except as to notes 13 and 14 which are as of November 30, 2005	Chartered Accountants

F-12

KAISER ENERGY LTD.

CONSOLIDATED BALANCE SHEETS

(expressed in thousands of Canadian dollars)

					December 31,
		September 30, 2005			December 31,
		September 30, 2005			2004		2003
		(unaudited)
Assets
Current assets
	Cash and cash equivalents	$	78,262		$	26,257	$	18,229
	Accounts receivable and deposits		14,936			5,989		7,108
	Prepaid expenses		1,526			619		575
	Due from affiliates (note 3)		672			60		34
	Income taxes recoverable		9,158			2,668		4,772
	Investment in BNP partnership units (note 4)		18

			104,572			35,593		30,718
Investment in Taurus Exploration Ltd. (note 4)			—			40,227		56,518
Property and equipment (note 5)			63,015			58,747		56,953

		$	167,587		$	134,567	$	144,189

Liabilities
Current liabilities
	Accounts payable and accrued liabilities	$	14,612		$	8,486	$	8,575
	Due to affiliate (note 3)		10,637			3,003		4,153

			25,249			11,489		12,728
Asset retirement obligations (note 6)			989			930		836
Future income taxes (note 7)			24,154			15,414		19,124

			50,392			27,833		32,688

Shareholder's Equity
Share capital (note 8)			72,900			1		1
Contributed surplus			68,776			68,776		68,776
Retained earnings (deficit)			(24,481	)		37,957		42,724

			117,195			106,734		111,501

		$	167,587		$	134,567	$	144,189

Approved by the Board,

(Signed) GEORGE B. KAISER
Director

(Signed) JANICE LAMBERT
Director

The accompanying notes are an integral part of these consolidated financial statements.

F-13

KAISER ENERGY LTD.

CONSOLIDATED STATEMENTS OF OPERATIONS AND RETAINED EARNINGS (DEFICIT)

(expressed in thousands of Canadian dollars)

		Nine Months Ended September 30,						Years Ended December 31,
		2005			2004			2004			2003
		(unaudited)			(unaudited)
Revenue
	Petroleum and natural gas sales	$	34,773		$	33,563		$	45,154		$	36,523
	Royalties		7,378			7,421			9,842			7,659

			27,395			26,142			35,312			28,864

Expenses
	Petroleum and natural gas production		4,861			4,333			6,015			5,429
	Transportation costs		1,030			1,183			1,563			1,213
	General and administrative		2,109			1,297			1,502			1,940
	Depletion, depreciation and accretion		7,571			7,787			10,448			9,112

			15,571			14,600			19,528			17,694

Income before the following			11,824			11,542			15,784			11,170

Donations of trust units (note 4)			(77,784	)		—			—			—
Equity in earnings (loss) of Taurus Exploration Ltd.			(14,079	)		(11,087	)		(17,860	)		26,795
Gain on disposal of partnership units (note 4)			17,772			—			—			—
Interest income			1,050			467			656			403
Interest expense			(126	)		(55	)		(119	)		(56	)
Other			63			51			55			83

			(73,104	)		(10,624	)		(17,268	)		27,225

Income (loss) before income taxes			(61,280	)		918			(1,484	)		38,395

Income tax provision (note 7)
	Current		4,786			4,752			6,993			4,185
	Future (recovery)		(3,628	)		(2,284	)		(3,710	)		3,650

			1,158			2,468			3,283			7,835

Net income (loss)			(62,438	)		(1,550	)		(4,767	)		30,560
Retained earnings, beginning of period			37,957			42,724			42,724			12,164

Retained earnings (deficit), end of period		$	(24,481	)	$	41,174		$	37,957		$	42,724

The accompanying notes are an integral part of these consolidated financial statements.

F-14

KAISER ENERGY LTD.

CONSOLIDATED STATEMENTS OF CASH FLOWS

(expressed in thousands of Canadian dollars)

				Nine Months Ended September 30,						Years Ended December 31,
				2005			2004			2004			2003
				(unaudited)			(unaudited)
Cash flows relating to:
	Operating activities
		Net income (loss)		$	(62,438	)	$	(1,550	)	$	(4,767	)	$	30,560
		Items not affecting cash
			Non-cash donations		44,784			—			—			—
			Depletion, depreciation and accretion		7,571			7,787			10,448			9,112
			Equity in (earnings) loss of Taurus Exploration Ltd.		14,079			11,087			17,860			(26,795	)
			Gain on disposal of partnership units		(17,772	)		—			—			—
			Future income taxes		(3,628	)		(2,284	)		(3,710	)		3,650

					(17,404	)		15,040			19,831			16,527
		Changes in non-cash working capital related to operations			(12,450	)		2,867			823			(5,987	)

					(29,854	)		17,907			20,654			10,540

	Financing activities
		Advances from (repayments to) affiliate, net			7,634			2,851			(1,150	)		2,741

	Investing activities
		Cash acquired on business combination (note 4)			84,988			—			—			—
		Repayment from (advances to) affiliates, net			(612	)		(4	)		(26	)		8,514
		Proceeds from sale of shares of Taurus Exploration Ltd.			—			—			—			50
		Purchase of shares of Taurus Exploration Ltd.			—			(1,551	)		(1,569	)		—
		Property and equipment expenditures			(11,780	)		(8,150	)		(12,148	)		(10,729	)
		Changes in non-cash working capital related to investing activities			1,629			(533	)		2,267			3,263

					74,225			(10,238	)		(11,476	)		1,098

Increase in cash and cash equivalents					52,005			10,520			8,028			14,379
Cash and cash equivalents, beginning of period					26,257			18,229			18,229			3,850

Cash and cash equivalents, end of period				$	78,262		$	28,749		$	26,257		$	18,229

Supplemental cash flows disclosure:
	Income taxes paid			$	12,459		$	2,470		$	4,889		$	5,777

Cash and cash equivalents is comprised of:
		Amounts on deposit with banks (overdraft)		$	1,139		$	293		$	(187	)	$	18,229
		Short-term corporate paper and bankers' acceptances			77,123			28,456			26,444			—

				$	78,262		$	28,749		$	26,257		$	18,229

The accompanying notes are an integral part of these consolidated financial statements.

F-15

KAISER ENERGY LTD.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

As at and for the Nine Months Ended September 30, 2005 and 2004
(unaudited)
and as at and for the Years Ended December 31, 2004 and 2003
(expressed in Canadian dollars)

1. NATURE OF OPERATIONS

Kaiser Energy Ltd. ("KEL" or the "Corporation") explores for and develops petroleum and natural gas properties in Canada. KEL also operates, on a contract basis, certain properties of companies affiliated by virtue of common control (Canadian Acquisition Limited Partnership ("CALP") and Kaiser-Francis Oil Company of Canada). No direct fees are paid to KEL for these services, however, KEL charges overhead at standard industry rates for the operation of the properties.

On September 9, 2005, the Corporation announced that it has retained the services of a financial advisor to seek proposals with the intent of monetizing substantially all of its petroleum and natural gas assets.

2. SIGNIFICANT ACCOUNTING POLICIES

These financial statements have been prepared using accounting principles generally accepted in Canada. In the opinion of management, these financial statements have been properly prepared within reasonable limits of materiality and within the framework of the significant accounting policies summarized below.

(a): Basis of presentation

The consolidated financial statements of KEL include the accounts of the Corporation and its wholly-owned subsidiary, Taurus Exploration Ltd. ("Taurus") since April 21, 2005 (note 4). Taurus includes the accounts of its wholly-owned subsidiaries and its general partnership.

(b): Cash and cash equivalents

Cash and cash equivalents consist of amounts on deposit with banks and highly liquid investments with maturities of 90 days or less at issue. Bank overdraft consists of cheques issued in excess of funds on deposit.

(c): Joint ventures

A significant part of the Corporation's exploration, development and production activities are conducted jointly with others, and these financial statements reflect only the Corporation's proportionate interest in such activities.

(d): Petroleum and natural gas operations

The Corporation follows the full cost method of accounting for petroleum and natural gas operations and accordingly capitalizes and accumulates all exploration and development costs in cost centres by country. These costs include land acquisition, geological and geophysical costs, drilling on producing and non-producing properties, wellhead and gathering equipment, other carrying charges on unproved properties and overhead directly attributable to exploration and development activities.

Capitalized costs are depleted and depreciated using the unit-of-production method based on production volumes and estimated total proved petroleum and natural gas reserves as determined by independent and Corporation engineers. For the purpose of this calculation, production and reserves of petroleum and natural gas are converted to equivalent units based on the relative energy content of six thousand cubic feet of natural gas to one barrel of oil. Costs of acquiring and evaluating unproved properties are excluded from costs subject to depletion and depreciation until it is determined that proved reserves are attributable to the properties or impairment occurs. Gains or losses on sales of

F-16

properties are recognized only when crediting the proceeds to costs would result in a change of 20% or more in the depletion and depreciation rate.

In addition to the capitalized costs incurred to date in the exploration and development of petroleum and natural gas properties, the operations and further development require future expenditures and excludes estimated salvage values. For purposes of calculating depletion and depreciation expense, estimates of future expenditures and recoveries have been prepared for:

(i): Future development costs of proved developed and undeveloped reserves as determined by independent and Corporation engineers;
(ii): Net realizable value of production equipment and facilities after proved reserves are fully produced as determined by management.

(e): Impairment of petroleum and natural gas properties

Impairment is evaluated at least annually by performing a "ceiling test", whereby the carrying value of petroleum and natural gas properties less accumulated depletion and depreciation, related asset retirement obligations and the lesser of cost and fair value of unproved properties is compared to the estimated future cash flows expected to result from the Corporation's proved reserves. Cash flows are calculated on an undiscounted basis using forecast prices and costs, as provided by independent engineers.

If impairment occurs, the Corporation will measure the amount by comparing the carrying value of the property and equipment to the estimated net present value of future cash flows from the proved and probable reserves, discounted at the Corporation's risk-free interest rate. The excess of the carrying value less the net present value of future cash flows would be recorded as additional depletion and depreciation expense.

The cost of unproved properties are excluded from the ceiling test calculation and are subjected to a separate impairment test.

(f): Asset retirement obligations

The Corporation recognizes the estimated fair value of an asset retirement obligation in the period a well or related asset is drilled, constructed or acquired. The fair value of the obligation is estimated using the present value of estimated future cash outflows to abandon the asset, calculated at the Corporation's credit-adjusted risk-free interest rate. The obligation is reviewed regularly by the Corporation's management based on current regulations, costs, technological and industry standards. The fair value is recorded as a long-term liability with a corresponding increase in the carrying amount of the related asset. The liability is increased each reporting period with the accretion being charged to income until the property is depleted or sold. The capitalized amount is depleted on a unit-of-production basis over the life of the reserves. Actual abandonment and restoration costs incurred are charged against the asset retirement obligation.

(g): Income taxes

Income taxes are accounted for using the liability method of income tax allocation. Under the liability method, income tax assets and liabilities are recorded to recognize future income tax inflows and

F-17

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

(h): Depreciation

The cost of other property and equipment are depreciated approximating their useful lives on a declining balance basis at rates ranging from 20% to 30% per year.

(i): Revenue recognition

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

(j)

Investments

(i): BNP partnership units

The Corporation accounts for its investment in BNP partnership units using the cost method whereby the investment is initially recorded at cost. Earnings are recognized only to the extent received or receivable. Where there has been a permanent or other than temporary decline in value, the investment is stated at estimated net realizable value.

(ii): Taurus Exploration Ltd.

The Corporation had a 26.4% investment in Taurus until April 21, 2005 at which time 73.6% of the ownership was acquired from Kaiser-Francis Oil Company ("KFOC"), a company affiliated by virtue of common control (note 3), bringing the Corporation's ownership to 100%. The investment was recorded on the equity basis. The investment was periodically evaluated by management to determine if the facts and circumstances suggested that the investment may be impaired. Any impairment identified through this assessment would have resulted in a write-down of the investment and a corresponding charge to earnings.

(k): Measurement uncertainty

The amounts recorded for depletion and depreciation of property and equipment, the provision for and accretion of asset retirement obligations and the ceiling test are based on estimates of proved and probable reserves, production rates, future petroleum and natural gas prices, future costs and the remaining useful lives and period of future benefit of the related assets.

By their nature, these estimates are subject to measurement uncertainty and the effect on the consolidated financial statements of changes in such estimates in future periods could be significant.

F-18

3. DUE FROM/TO AFFILIATES

Balances with related parties are as follows (in thousands):

				December 31,
		September 30, 2005		December 31,
		September 30, 2005		2004		2003
Due from affiliates
	George Kaiser Family Foundation	$	300	$	—	$	—
	J-G Limited Partnership ("J-G")		372		25		1
	Selkirk Energy Canada Limited ("Selkirk")		—		35		33

		$	672	$	60	$	34

Due to affiliate
	Kaiser-Francis Oil Company of Canada ("KFOCC")	$	10,637	$	3,003	$	4,153

George Kaiser Family Foundation is related by virtue of significant influence by a trustee of the Foundation who is also a corporate officer of KEL and other companies related by virtue of common control. The amount due, which includes $21,000 of amounts due from others, is unsecured, non-interest bearing and was repaid in October 2005.

J-G, Selkirk and KFOCC are affiliated by virtue of common control and each has a lending arrangement with KEL under which KEL may lend up to $30 million under the terms of a demand note, which requires monthly interest payments based on the United States Short-Term Applicable Federal Rate. Additionally, KEL has a borrowing arrangement with KFOCC under which KEL may borrow up to $50 million under the terms of a demand note, requiring monthly interest payments based on the United States Short-Term Applicable Federal Rate. The lending arrangement with Selkirk ended in January 2005 and Selkirk ceased to be an affiliate at that time. Interest incurred by KEL pursuant to the arrangement with KFOCC for the periods ending September 30, 2005 and 2004 and for the years ending December 31, 2004 and 2003 was $121,000, $50,000, $99,000 and $20,000, respectively, and is included in amounts due to affiliates.

Included in general and administrative expenses are charges to KEL by KFOC for management, operational and administrative services work performed by employees of KFOC on behalf of KEL. The amounts for the periods ended September 30, 2005 and 2004 and December 31, 2004 and 2003 were $1,117,173, $1,341,405, $1,742,000 and $2,288,000, respectively.

Included in petroleum and natural gas properties are capitalized general and administrative services provided by KFOC for the periods ended September 30, 2005 and 2004 and December 31, 2004 and 2003 of $425,000, $387,000, $403,000 and $595,000, respectively.

4. INVESTMENT IN TAURUS EXPLORATION LTD.

On April 21, 2005, the Corporation acquired 73.6% of Taurus from KFOC, bringing the Corporation's ownership of Taurus to 100%.

F-19

Consideration for the purchase consisted of 1,000 Class A shares with an ascribed value of $72,899,038, being the carrying values of the net assets acquired as follows:

	(in thousands)
Cash	$	62,551
Accounts receivable		582
Investment in Bonavista Energy Exchangeable Limited
Partnership Units		19,894
Accounts payable and accrued liabilities		(154	)
Income taxes payable		(871	)
Future income taxes		(9,103	)

	$	72,899

During 2003, Taurus sold its operating assets to a publicly traded energy trust, Bonavista Energy Trust ("BNP"). Taurus received $101 million in cash and exchangeable partnership units in BNP with an assigned value of $187 million, resulting in a gain of $66 million. Petroleum and natural gas operations were discontinued with the closing of the sale. During 2004, Taurus settled Taurus Charitable Income Trust and Taurus Charitable Income Trust B (the "Taurus Trusts") with the Trusts having the purpose of receiving property from Taurus.

During the period ended September 30, 2005, Taurus exchanged BNP partnership units with an assigned value of $79,270,000 (September 30, 2004 — $65,323,000; December 31, 2004 — $108,120,000) and received BNP trust units ("BNP Trust Units") in exchange, having a fair market value at the time of exchange of $134,995,000 (September 30, 2004 — $87,898,000; December 31, 2004 — $150,734,000), resulting in a gain of $55,725,000 (September 30, 2004 — $22,576,000; December 31, 2004 — $42,614,000) of which $17,772,000 was realized subsequent to April 21, 2005. Immediately following each exchange, Taurus donated the BNP Trust Units received to the Taurus Trusts. During the period ended September 30, 2005, donations to the Taurus Trusts of BNP Trust Units and cash totaled $167,995,000 (September 30, 2004 — $87,898,000; December 31, 2004 — $150,734,000) of which $77,784,000 occurred after April 21, 2005.

Following the contributions noted above, Taurus retained ownership of partnership units in BNP with an assigned value of $18,000, having a fair market value of $37,000 at September 30, 2005.

The contributions to the Taurus Trusts are not deductible for income tax purposes as the Taurus Trusts are not registered charities under the tax laws of Canada.

The sole trustee of the Taurus Trusts is a corporate officer of companies related to KEL and Taurus by virtue of common ownership. The beneficiaries of the Taurus Trusts are the Tulsa Community Foundation and a subsidiary foundation controlled by the Tulsa Community Foundation. The Taurus Trusts and the subsidiary foundation have no restrictions on their investing powers and have entered into financing and leasing arrangements respectively with entities related to KEL and Taurus by virtue of common control or significant influence. The financing and leasing arrangements are on normal commercial terms and conditions, consistent with those that might have prevailed if the parties had been unrelated. Accordingly,

F-20

donations to the Taurus Trusts are treated as related party transactions, measured at the exchange amount, being the market value of the BNP Trust Units when the donations were made.

5. PROPERTY AND EQUIPMENT

Property and equipment is composed of (in thousands):

			December 31,
	September 30, 2005		December 31,
	September 30, 2005		2004		2003
Petroleum and natural gas properties including exploration and development costs thereon	$	148,214	$	136,413	$	124,285
Other		1,457		1,468		1,418

		149,671		137,881		125,703
Accumulated depletion and depreciation		86,656		79,134		68,750

	$	63,015	$	58,747	$	56,953

For the periods ended September 30, 2005 and 2004 and December 31, 2004 and 2003, the Corporation capitalized $425,000, $387,000, $403,000 and $595,000, respectively, of general and administrative expenses.

The Corporation prepares a ceiling test calculation to assess the recoverability of its petroleum and natural gas properties. The ceiling test is based upon a valuation prepared by an independent engineering firm based on future petroleum and natural gas benchmark prices and adjusted for commodity price differentials specific to the Corporation.

The benchmark and the Corporation prices on which the December 31, 2004 ceiling test is based are as follows:

	Crude Oil		Natural Gas		Natural Gas Liquids
	Edmonton Par Benchmark	Corporation Average	AECO Spot Benchmark	Corporation Average	Edmonton NGL Benchmark	Corporation Average
	($bbl)	($bbl)	($mcf)	($mcf)	($bbl)	($bbl)
2005	50.25	42.50	6.60	6.65	32.25	40.29
2006	46.75	40.15	6.35	6.41	30.50	38.09
2007	43.75	38.00	6.15	6.23	29.00	36.08
2008	40.75	35.85	6.00	6.08	27.75	34.12
2009	37.75	33.44	6.00	6.07	26.00	32.09
2010	35.75	32.56	6.00	6.07	25.25	31.15
2011	35.00	30.97	6.00	6.08	25.25	31.22
2012	34.50	30.07	6.00	6.07	25.25	31.18
2013	34.25	30.64	6.10	6.19	25.50	31.17
2014	34.00	31.45	6.20	6.30	26.00	31.61
2015	33.75	32.03	6.30	6.41	26.50	32.17

Prices increase at a rate of approximately 2% per year after 2015.

F-21

6. ASSET RETIREMENT OBLIGATIONS

The following table summarizes changes in asset retirement obligations for the periods ended September 30, 2005 and December 31, 2004 and 2003 (in thousands):

				Years Ended December 31,
		Nine Months Ended September 30, 2005		Years Ended December 31,
		Nine Months Ended September 30, 2005		2004		2003
Asset retirement obligations, beginning of period		$	930	$	836	$	751
	Liabilities incurred		10		29		27
	Liabilities settled		—		—		—
	Accretion expense		49		65		58

Asset retirement obligations, end of period		$	989	$	930	$	836

The total estimated inflated, undiscounted cash flows required to settle the obligations without including salvage, is $3,521,000. These amounts have been discounted using an average credit-adjusted risk-free interest rate of approximately 7.71%. The Corporation expects these obligations to be settled, on average, in 17 years, the majority of which is expected to be incurred between 2006 and 2023 and that the obligations will be funded from general corporate resources at the time of retirement.

7. INCOME TAXES

The components of the future income tax liability are as follows (in thousands):

					December 31,
		September 30, 2005			December 31,
		September 30, 2005			2004		2003
Temporary differences relating to:
	Property and equipment and asset retirement obligations	$	12,744		$	12,206	$	12,293
	Partnership income not taxable until following period		11,562			—		—
	Other		(152	)		—		—
	Investment in Taurus		—			3,208		6,831

		$	24,154		$	15,414	$	19,124

Income tax expense differs from that which would be expected from applying the combined effective Canadian federal and provincial income tax rates for the periods ended September 30, 2005 and 2004 and

F-22

December 31, 2004 and 2003 of 37.62%, 38.62%%, 38.62% and 39.62%, respectively, to income (loss) before income taxes as follows (in thousands):

	Nine Months Ended September 30,						Years Ended December 31,
	2005			2004			2004			2003
Expected income tax expense (recovery)	$	(23,054	)	$	355		$	(573	)	$	15,212
Tax rate adjustment		2,912			1,626			2,877			(8,214	)
Non-deductible crown charges		1,857			2,258			3,801			3,034
Resource allowance		(1,515	)		(1,771	)		(2,359	)		(2,333	)
Non-deductible donation		29,262			—			—			—
Non-taxable portion of capital gains		(8,424	)		—			—			—
Other		120			—			(463	)		136

	$	1,158		$	2,468		$	3,283		$	7,835

8. SHARE CAPITAL

(a) Authorized
Unlimited Class A shares

			December 31,
	September 30, 2005		December 31,
	September 30, 2005		2004		2003
(b) Issued 1,500 (December 31, 2004 and 2003 — 500) Class A shares	$	72,900,038	$	1,000	$	1,000

During the period ended September 30, 2005, the Corporation issued 1,000 Class A shares in exchange for a 73.6% interest in Taurus (note 4).

9. BANK CREDIT FACILITY

The Corporation has available a line of credit facility with a Canadian chartered bank, to a maximum of $10 million, which is renewed annually. The facility is available to the Corporation by way of prime rate based loans. Interest is payable quarterly at the chartered bank's prime rate. Related parties have guaranteed any debt drawn under this facility. Under the terms of the agreement, the Corporation is required to meet certain financial and engineering reporting requirements and may not breach certain financial tests without prior consent of the bank. As at the report date, the Corporation has not utilized this facility.

10. CONTINGENCIES

The Corporation may provide various guarantees and indemnifications in conjunction with certain transactions in the normal course of business. In the opinion of management, any obligations would not have a material impact on the Corporation's financial condition.

F-23

The Corporation is party to various legal claims associated with the ordinary conduct of business. Management does not anticipate that these claims will have a material impact on the Corporation's financial position.

11. FINANCIAL INSTRUMENTS

(a): Fair values

The fair values of the Corporation's cash and cash equivalents, accounts receivable and deposits, accounts payable and accrued liabilities and amounts due from and to affiliates are estimated to approximate their carrying values due to the immediate or short-term maturity of these financial instruments or because they bear interest at market rates.

At December 31, 2004 and 2003, the fair value of the investment in Taurus was not determinable as Taurus was a private company and, in the opinion of management, it was not practicable to value this investment.

(b): Credit risk

The majority of the Corporation's accounts receivable are due from joint venture partners in the oil and gas industry and from purchasers of the Corporation's petroleum and natural gas production. The Corporation generally extends unsecured credit to these customers and therefore the collection of accounts receivable may be affected by changes in economic or other conditions. Management believes the risk is mitigated by the size and reputation of the companies to which they extend credit.

(c): Commodity price risk

The nature of the Corporation's operations results in exposure to fluctuations in commodity prices. Management continuously monitors commodity prices and initiates instruments to manage its exposure to these risks when it deems appropriate.

(d): Interest cash flow risk

The Corporation's credit facility and lending and borrowing arrangements are subject to floating interest rates. The interest rates fluctuate with changes in market rates.

12. COMPARATIVE FIGURES

Certain comparative figures have been reclassified for the presentation adopted in the current period.

13. UNITED STATES ACCOUNTING PRINCIPLES AND REPORTING

The Corporation's consolidated financial statements have been prepared in Canadian dollars and in accordance with Canadian generally accepted accounting principles ("Canadian GAAP"), which in most

F-24

respects conform to accounting principles generally accepted in the United States ("U.S. GAAP"). Significant differences between Canadian and U.S. GAAP are described in this note:

(a): Full cost accounting

In accordance with U.S. GAAP, a ceiling test is applied to ensure the unamortized capitalized costs in each cost centre do not exceed the sum of the present value, discounted at 10 percent, of the estimated unescalated future net operating revenue from proved reserves plus unimpaired unproved property costs less future development costs, related production costs, asset retirement obligations and applicable taxes. Under Canadian GAAP, a similar ceiling test calculation is performed with the exception that future revenues are undiscounted and use forecast pricing to determine whether an impairment exists and are on a before tax basis. Any impairment amount is measured using the fair value of proved and probable reserves.

No ceiling test write-down was required for any of the periods presented in these financial statements.

Effective January 1, 2004, the Canadian Accounting Standard's Board amended the Full Cost Accounting Guideline. Under Canadian GAAP, depletion charges are calculated by reference to proved reserves estimated using estimated future prices and costs. Under U.S. GAAP, depletion charges are calculated by reference to proved reserves estimated using constant prices. The different prices did not result in significant changes to proved reserves or depletion recorded for any of the periods presented in these financial statements.

(b): Income taxes

Under U.S. GAAP, enacted tax rates are used to calculate future taxes, whereas under Canadian GAAP, substantively enacted tax rates are used.

(c): Investments

Under U.S. GAAP, the Corporation must classify investments in equity securities that have readily determinable fair values as either available for sale or trading. The Corporation's investment in BNP partnership units is classified as available for sale. This available for sale investment is revalued at the end of each period based on its fair value and any unrealized gain or loss is recorded, net of tax effects, as a component of other comprehensive income in the period.

Additionally, U.S. GAAP requires the disclosure, as other comprehensive income, of changes in equity during the period from transaction and other events from non-owner sources. Canadian GAAP does not require similar disclosure. Comprehensive income for U.S. purposes arose on valuing the Corporation's investment at its fair market value.

(d): Asset retirement obligations

The Corporation has applied the Canadian Institute of Chartered Accountant's standard on Asset Retirement Obligations. This standard is equivalent to U.S. SFAS No. 143, "Accounting for Asset Retirement Obligations".

(e): Consolidated statement of cash flows

Under U.S. GAAP, separate subtotals within cash flow from operating activities are not presented.

F-25

(f)

Recent accounting pronouncements

(i): Variable interest entities

The Canadian Institute of Chartered Accountants has issued a new standard effective for all periods beginning on or after November 1, 2004. This standard requires variable interest entities ("VIE") to be consolidated by their primary beneficiary which is similar to the Financial Accounting Standards Board's ("FASB") Interpretation No. 46 "Consolidation of Variable Interest Entities" ("FIN 46"). In December 2003, the FASB issued FIN 46(R) which superseded FIN 46 and restricts the scope of the definition of entities that would be considered VIE's that require consolidation.

The Corporation does not believe FIN 46(R) results in the consolidation of any additional entities.

(ii): Share-based payment

In 2004, FASB issued revised FAS 123 "Share-Based Payment". This amended statement eliminates the alternative to use Accounting Principles Board ("APB") Opinion No. 25's intrinsic value method of accounting, as was provided in the originally issued Statement 123.

As a result, public entities are required to use the grant-date fair value of the award in measuring the cost of employee services received in exchange for an equity award of equity instruments.

Compensation cost is required to be recognized over the requisite service period.

For liability awards, entities are required to re-measure the fair value of the award at each reporting date up until the settlement date. Changes in fair value of liability awards during the requisite service period are required to be recognized as compensation cost over the vesting period. Compensation cost is not recognized for equity instruments for which employees do not render the requisite service.

This amended statement is effective the beginning of the first interim or annual reporting period that begins after June 15, 2005.

(iii): Exchange of non-monetary assets

In 2004, FASB issued FAS 153 "Exchange of Non-monetary Assets". This statement is an amendment of APB Opinion No. 29 "Accounting for Non-monetary Transactions". Based on the guidance in APB Opinion No. 29, exchanges of non-monetary assets are to be measured based on the fair value of the assets exchanged. Furthermore, APB Opinion No. 29 previously allowed for certain exceptions to this fair value principle. FAS 153 eliminates APB Opinion No. 29's exception to fair value for non-monetary exchanges of similar productive assets and replaces this with a general exception for exchanges of non-monetary assets which do not have commercial substance. For purposes of this statement, a non-monetary exchange is defined as having commercial substance when the future cash flows of an entity are expected to change significantly as a result of the exchange.

The provisions of this statement are effective for non-monetary asset exchanges which occur in fiscal periods beginning after June 15, 2005 and are to be applied prospectively. Earlier application

F-26

is permitted for non-monetary asset exchanges which occur in fiscal periods beginning after the issue date of this statement.

Currently, this statement does not have an impact on the Corporation.

(iv): SAB 106

In 2004, the Securities and Exchange Commission issued Staff Accounting Bulletin 106 ("SAB 106") regarding the application of FAS 143 by oil and gas producing entities that follow the full cost accounting method. Under SAB 106, after the adoption of FAS 143, the future cash flows associated with the settlement of asset retirement obligations that have been accrued on the balance sheet should be excluded from the computation of the present value of estimated future net revenues in the ceiling test calculation. The Corporation excludes the future cash outflows associated with settling asset retirement obligations from the present value of estimated future net cash flows and does not reduce the capitalized oil and gas costs by the asset retirement obligation accrued on the balance sheet. Costs subject to depletion and depreciation include estimated costs required to develop proved undeveloped reserves and the associated addition to the asset retirement obligations. The application of SAB 106 did not create a ceiling test write-down for any of the periods presented in these financial statements.

(g)

Summary of significant differences between U.S. GAAP and Canadian GAAP

(i): Reconciliation of consolidated net income (loss) under Canadian GAAP to U.S. GAAP

	Nine Months Ended September 30,						Years Ended December 31,
	2005			2004			2004			2003
Net income (loss) under Canadian GAAP	$	(62,438	)	$	(1,550	)	$	(4,767	)	$	30,560
U.S. GAAP adjustments		—			—			—			—

Net income (loss) under U.S. GAAP		(62,438	)		(1,550	)		(4,767	)		30,560
Net realized gain on investment in BNP partnership units, net of tax of $(3,463) (September 30, 2004, December 31, 2004 and 2003 — $NIL)		(14,472	)		—			—			—
Net unrealized (realized) gain on investment in equity earnings (loss) of Taurus Exploration Ltd., net of tax of $(1,121) (September 30, 2004 — $1,144; December 31, 2004 — $462; December 31, 2003 — $1,545)		(6,816	)		4,778			1,931			6,455

Comprehensive income (loss)	$	(83,726	)	$	3,228		$	(2,836	)	$	37,015

F-27

(ii): Condensed consolidated balance sheets

									December 31,
			September 30, 2005						December 31,
			September 30, 2005						2004				2003
			Canadian GAAP			U.S. GAAP			Canadian GAAP		U.S. GAAP		Canadian GAAP		U.S. GAAP
Assets
	Current assets
		Investment in BNP partnership units	$	18		$	37		$	—	$	—	$	—	$	—
		Other current assets		104,554			104,554			35,593		35,593		30,718		30,718

				104,572			104,591			35,593		35,593		30,718		30,718
	Investment in Taurus Exploration Ltd.			—			—			40,227		50,620		56,518		64,518
	Property and equipment			63,015			63,015			58,747		58,747		56,953		56,953

			$	167,587		$	167,606		$	134,567	$	144,960	$	144,189	$	152,189

Liabilities and Shareholder's Equity
		Current liabilities	$	25,249		$	25,249		$	11,489	$	11,489	$	12,728	$	12,728
		Asset retirement obligations		989			989			930		930		836		836
		Future income taxes		24,154			24,158			15,414		17,421		19,124		20,669

				50,392			50,396			27,833		29,840		32,688		34,233

		Share capital		72,900			72,900			1		1		1		1
		Contributed surplus		68,776			68,776			68,776		68,776		68,776		68,776
		Retained earnings (deficit)		(24,481	)		(24,481	)		37,957		37,957		42,724		42,724
		Accumulated other comprehensive income		—			15			—		8,386		—		6,455

				117,195			117,210			106,734		115,120		111,501		117,956

			$	167,587		$	167,606		$	134,567	$	144,960	$	144,189	$	152,189

F-28

(iii): Non-cash working capital under U.S. GAAP

		Nine Months Ended September 30,						Years Ended December 31,
		2005			2004			2004			2003
Cash provided by (used for):
	Accounts receivable and deposits	$	(8,158	)	$	(558	)	$	1,119		$	(3,226	)
	Prepaid expenses		(907	)		(18	)		(44	)		(207	)
	Income taxes recoverable		(7,673	)		2,282			2,104			(1,592	)
	Accounts payable and accrued liabilities		5,917			628			(89	)		2,301

Changes in non-cash working capital		$	(10,821	)	$	2,334		$	3,090		$	(2,724	)

14. SUBSEQUENT EVENT

On November 16, 2005, Petrofund Energy Trust ("Petrofund") announced that it had agreed to acquire all of the outstanding shares of KEL.

The purchase price is Cdn $485 million plus working capital adjustments, and is expected to close on December 15, 2005, with an effective date of December 1, 2005. On closing, KEL will become a wholly-owned subsidiary of Petrofund.

Prior to the sale, KEL has agreed to undertake certain Reorganization Transactions that will result in the merger of KEL, its parent company, G.B.K. Holdings Ltd., and Canadian Acquisition Limited Partnership, as well as the acquisition by KEL of interests in resource properties, including interests owned by individuals related to KEL.

Completion of the transaction is subject to certain regulatory and other conditions.

F-29

FINANCIAL STATEMENTS OF THE LIMITED PARTNERSHIP

AUDITORS' REPORT

To the Board of Directors of
Kaiser-Francis Oil Company of Canada (General Partner)

We have audited the balance sheets of Canadian Acquisition Limited Partnership as at December 31, 2004 and 2003 and the statements of operations and cash flows for the years then ended. These financial statements are the responsibility of the Partnership's management. Our responsibility is to express an opinion on these financial statements based on our audits.

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

(Signed) COLLINS BARROW CALGARY LLP
Chartered Accountants

Calgary, Alberta, Canada
September 16, 2005, except as to
notes 7 and 8 which are as of
November 30, 2005

F-30

CANADIAN ACQUISITION LIMITED PARTNERSHIP

BALANCE SHEETS

(expressed in thousands of Canadian dollars)

					December 31,
		September 30, 2005			December 31,
		September 30, 2005			2004			2003
		(unaudited)
Assets
Current assets
	Accounts receivable	$	281		$	211		$	428
	Due from general partner (note 3)		2,540			1,807			1,550

			2,821			2,018			1,978

Property and equipment (note 4)
	Petroleum and natural gas properties		38,069			35,360			32,110
	Accumulated depletion and depreciation		(22,453	)		(20,482	)		(18,052	)

			15,616			14,878			14,058

Other			3			3			3

		$	18,440		$	16,899		$	16,039

Liabilities
Current liabilities
	Accounts payable and accrued liabilities	$	456		$	474		$	376

Asset retirement obligations (note 5)			795			750			663

			1,251			1,224			1,039

Partners' Capital
Partners' capital, beginning of period			15,675			15,000			15,379
Withdrawals			(9,390	)		(11,165	)		(13,305	)
Net income			10,904			11,840			12,926

Partners' capital, end of period			17,189			15,675			15,000

		$	18,440		$	16,899		$	16,039

Approved by the Board of Directors of Kaiser-Francis Oil Company of Canada, General Partner,

(Signed) GEORGE B. KAISER
Director

The accompanying notes are an integral part of these financial statements.

F-31

CANADIAN ACQUISITION LIMITED PARTNERSHIP

STATEMENTS OF OPERATIONS

(expressed in thousands of Canadian dollars)

		Nine Months Ended September 30,				Years Ended December 31,
		2005		2004		2004		2003
		(unaudited)		(unaudited)
Revenue
	Petroleum and natural gas sales	$	18,892	$	17,136	$	23,006	$	22,689
	Royalties, net of Alberta Royalty Tax Credit		3,158		3,113		3,985		3,970

			15,734		14,023		19,021		18,719

Expenses
	Petroleum and natural gas production		2,224		2,868		3,863		2,930
	Transportation costs		600		614		818		835
	Depletion, depreciation and accretion		2,006		2,005		2,500		2,028

			4,830		5,487		7,181		5,793

Net income		$	10,904	$	8,536	$	11,840	$	12,926

The accompanying notes are an integral part of these financial statements.

F-32

CANADIAN ACQUISITION LIMITED PARTNERSHIP

STATEMENTS OF CASH FLOWS

(expressed in thousands of Canadian dollars)

			Nine Months Ended September 30,						Years Ended December 31,
			2005			2004			2004			2003
			(unaudited)			(unaudited)
Cash flows relating to:
	Operating activities
		Net income	$	10,904		$	8,536		$	11,840		$	12,926
	Item not affecting cash
		Depletion, depreciation and accretion		2,006			2,005			2,500			2,028

				12,910			10,541			14,340			14,954
	Changes in non-cash working capital related to operations			(88	)		398			315			70

				12,822			10,939			14,655			15,024

Financing activity
	Distributions to partners, net of contributions			(9,390	)		(8,536	)		(11,165	)		(13,305	)

Investing activities
	Acquisition of property and equipment			(2,699	)		(2,425	)		(3,233	)		(2,493	)
	Repayments from (advances to) general partner, net			(733	)		22			(257	)		774

				(3,432	)		(2,403	)		(3,490	)		(1,719	)

Increase in cash				—			—			—			—
Cash, beginning of period				—			—			—			—

Cash, end of period			$	—		$	—		$	—		$	—

The accompanying notes are an integral part of these financial statements.

F-33

CANADIAN ACQUISITION LIMITED PARTNERSHIP

NOTES TO FINANCIAL STATEMENTS

As at and for the Nine Months Ended September 30, 2005 and 2004 (unaudited)
and as at and for the Years Ended December 31, 2004 and 2003

(expressed in Canadian dollars)

1. NATURE OF OPERATIONS

Canadian Acquisition Limited Partnership ("CALP" or the "Partnership") explores for and develops petroleum and natural gas properties in Canada. Through the general partner, Kaiser-Francis Oil Company of Canada ("KFOCC"), an affiliated entity by virtue of common control, Kaiser Energy Ltd. ("KEL") operates any properties not otherwise operated by outside parties and performs or contracts any administrative functions. No direct fees are paid to KFOCC or KEL for these services, but KEL receives any overhead earned for the operation of properties at standard industry rates. These financial statements include only the assets, liabilities, revenues and expenses related to the operation of CALP. They do not include all of the assets, liabilities, revenues and expenses of the individual partners.

On September 9, 2005, KEL announced that it has retained the services of a financial advisor to seek proposals with the intent of monetizing substantially all of the petroleum and natural gas assets of KEL and CALP.

2. SIGNIFICANT ACCOUNTING POLICIES

(a): Joint ventures

A significant part of the Partnership's exploration, development and production activities are conducted jointly with others, and these financial statements reflect only the Partnership's proportionate interest in such activities.

(b): Petroleum and natural gas operations

The Partnership follows the full cost method of accounting for petroleum and natural gas operations and accordingly capitalizes all exploration and development costs in cost centre by country. These costs include land acquisition, geological and geophysical costs, drilling on producing and non-producing properties, wellhead and gathering equipment, other carrying charges on unproved properties and overhead directly attributable to exploration and development activities.

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

F-34

excludes estimated salvage values. For purposes of calculating depletion and depreciation expense, estimates of future expenditures and recoveries have been prepared for:

(i): Future development costs of proved developed and undeveloped reserves as determined by independent engineers and engineers employed or contracted by KEL;
(ii): Net realizable value of production equipment and facilities after proved reserves are fully produced as determined by the Partnership's management.

(c): Impairment of petroleum and natural gas properties

Impairment is evaluated at least annually and is recognized if the carrying value of petroleum and natural gas properties less accumulated depletion and depreciation, related asset retirement obligations and the lesser of cost and fair value of unproved properties exceeds the estimated future cash flows expected to result from the Partnership's proved reserves. Cash flows are calculated on an undiscounted basis using forecast prices and costs, as provided by independent engineers.

If impairment occurs, the Partnership will measure the amount by performing a ceiling test, comparing the carrying value of the property and equipment to the estimated net present value of future cash flows from the proved and probable reserves, discounted at the Partnership's risk-free interest rate. The excess of the carrying value less the net present value of future cash flows would be recorded as additional depletion and depreciation expense.

The cost of unproved properties are excluded from the ceiling test calculation and are subjected to a separate impairment test.

(d): Asset retirement obligations

The Partnership recognizes the estimated fair value of an asset retirement obligation in the period a well or related asset is drilled, constructed or acquired. The fair value of the obligation is estimated using the present value of estimated future cash outflows to abandon the asset, calculated at the Partnership's credit-adjusted risk-free interest rate. The obligation is reviewed regularly by the Partnership's management based on current regulations, costs, technological and industry standards. The fair value is recorded as a long-term liability with a corresponding increase in the carrying amount of the related asset. The liability is increased each reporting period with the accretion being charged to income until the property is depleted or sold. The capitalized amount is depleted on a unit-of-production basis over the life of the reserves. Actual abandonment and restoration costs incurred are charged against the asset retirement obligation.

(e): Income taxes

The Partnership is not subject to federal or provincial income taxes, as partners must reflect their share of Partnership income in their tax returns. Therefore, no provision for income taxes is reflected in the financial statements.

F-35

(f): Revenue recognition

(g): Measurement uncertainty

By their nature, these estimates are subject to measurement uncertainty and the effect on the financial statements of changes in such estimates in future periods could be significant.

3. DUE FROM GENERAL PARTNER

All transactions for the Partnership are implemented by the general partner. The amount due from general partner at each period end represents the net cash flows accrued for activity recorded in the financial statements of the Partnership. Due from general partner is unsecured, non-interest bearing and has no stated terms of repayment.

The largest individual limited partner, with approximately 60% ownership of the Partnership, controls KFOCC, KEL, and the parent company of KFOCC.

4. PROPERTY AND EQUIPMENT

For the periods ended September 30, 2005 and 2004 and December 31, 2004 and 2003, no general and administrative expenses or interest have been capitalized.

The Partnership prepares a ceiling test calculation to assess the recoverability of its petroleum and natural gas properties. The ceiling test is based upon a valuation prepared by an independent engineering firm based on future petroleum and natural gas benchmark prices and adjusted for commodity price differentials specific to the Partnership.

F-36

The benchmark and CALP prices on which the December 31, 2004 ceiling test is based are as follows:

	Crude Oil		Natural Gas		Natural Gas Liquids
	Edmonton Par Benchmark	CALP Average	AECO Spot Benchmark	CALP Average	Edmonton NGL Benchmark	CALP Average
	($bbl)	($bbl)	($mcf)	($mcf)	($bbl)	($bbl)
2005	50.25	35.57	6.60	6.50	32.25	42.00
2006	46.75	34.44	6.35	6.24	30.50	39.36
2007	43.75	33.17	6.15	6.05	29.00	37.43
2008	40.75	31.28	6.00	5.90	27.75	35.47
2009	37.75	30.34	6.00	5.90	26.00	33.31
2010	35.75	28.99	6.00	5.90	25.25	32.23
2011	35.00	29.66	6.00	5.90	25.25	32.24
2012	34.50	30.25	6.00	5.91	25.25	32.26
2013	34.25	30.75	6.10	6.01	25.25	32.26
2014	34.00	31.50	6.20	6.12	26.00	33.38
2015	33.75	31.75	6.30	6.22	26.50	33.83

Prices increase at a rate of approximately 2% per year after 2015.

5. ASSET RETIREMENT OBLIGATIONS

The following table summarizes changes in asset retirement obligations for the periods ended September 30, 2005 and December 31, 2004 and 2003 (in thousands):

				Years Ended December 31,
		Nine Months Ended September 30, 2005		Years Ended December 31,
		Nine Months Ended September 30, 2005		2004		2003
Asset retirement obligations, beginning of period		$	750	$	663	$	579
	Liabilities incurred		10		17		19
	Liabilities settled		—		—		—
	Accretion expense		35		70		65

Asset retirement obligations, end of period		$	795	$	750	$	663

The total estimated inflated, undiscounted cash flows required to settle the obligations at September 30, 2005 without including salvage, is $1,771,000. These amounts have been discounted using an average credit-adjusted risk-free interest rate of approximately 9.78%. The Partnership expects these obligations to be settled on average in 16 years, the majority of which is expected to be incurred between 2011 and 2032, and will be funded from general Partnership resources at the time of retirement.

F-37

6. FINANCIAL INSTRUMENTS

(a): Fair values

The fair values of the Partnership's accounts receivable, due from general partner and accounts payable and accrued liabilities are estimated to approximate their carrying values due to the immediate or short-term maturity of these financial instruments.

(b): Credit risk

The majority of the Partnership's accounts receivable are due from joint venture partners in the oil and gas industry and from purchasers of the Partnership's petroleum and natural gas production. The Partnership generally extends unsecured credit to these customers and therefore the collection of accounts receivable may be affected by changes in economic or other conditions. Management believes the risk is mitigated by the size and reputation of the companies to which they extend credit.

(c): Commodity price risk

The nature of the Partnership's operations results in exposure to fluctuations in commodity prices. Management continuously monitors commodity prices and initiates instruments to manage its exposure to these risks when it deems appropriate.

7. UNITED STATES ACCOUNTING PRINCIPLES AND REPORTING

The Partnership's consolidated financial statements have been prepared in Canadian dollars and in accordance with Canadian generally accepted accounting principles ("Canadian GAAP"), which in most respects conform to accounting principles generally accepted in the United States ("U.S. GAAP"). Significant differences between Canadian and U.S. GAAP are described in this note:

(a): Full cost accounting

No ceiling test write-down was required for any of the periods presented in these financial statements.

F-38

(b): Asset retirement obligations

The Partnership has applied the Canadian Institute of Chartered Accountant's standard on Asset Retirement Obligations. This standard is equivalent to U.S. SFAS No. 143, "Accounting for Asset Retirement Obligations".

(c): Consolidated statement of cash flows

Under U.S. GAAP, separate subtotals within cash flow from operating activities are not presented.

(d)

Recent accounting pronouncements

(i): Variable interest entities

The Partnership does not believe FIN 46(R) results in the consolidation of any additional entities.

(ii): Exchange of non-monetary assets

The provisions of this statement are effective for non-monetary asset exchanges which occur in fiscal periods beginning after June 15, 2005 and are to be applied prospectively. Earlier application is permitted for non-monetary asset exchanges which occur in fiscal periods beginning after the issue date of this statement.

Currently, this statement does not have an impact on the Partnership.

(iii): SAB 106

F-39

net revenues in the ceiling test calculation. The Partnership excludes the future cash outflows associated with settling asset retirement obligations from the present value of estimated future net cash flows and does not reduce the capitalized oil and gas costs by the asset retirement obligation accrued on the balance sheet. Costs subject to depletion and depreciation include estimated costs required to develop proved undeveloped reserves and the associated addition to the asset retirement obligations. The application of SAB 106 did not create a ceiling test write-down for any of the periods presented in these financial statements.

(e)

Summary of significant differences between U.S. GAAP and Canadian GAAP

(i): Reconciliation of consolidated net income under Canadian GAAP to U.S. GAAP

	Nine Months Ended September 30,				Years Ended December 31,
	2005		2004		2004		2003
Net income under Canadian GAAP	$	10,904	$	8,536	$	11,840	$	12,926
U.S. GAAP adjustments		—		—		—		—

Net income under U.S. GAAP	$	10,904	$	8,536	$	11,840	$	12,926

(ii): Non-cash working capital under U.S. GAAP

		Nine Months Ended September 30,					Years Ended December 31,
		2005			2004		2004		2003
Cash provided by (used for)
	Accounts receivable	$	(70	)	$	220	$	217	$	66
	Accounts payable and accrued liabilities		(18	)		178		98		4

Changes in non-cash working capital		$	(88	)	$	398	$	315	$	70

8. SUBSEQUENT EVENT

On November 16, 2005, the shareholder of KEL entered into an agreement with Petrofund Energy Trust ("Petrofund") whereby, Petrofund will acquire all of the outstanding shares of KEL.

Prior to the sale, KEL has agreed to undertake certain Reorganization Transactions that will result in the merger of KEL, its parent company, G.B.K. Holdings Ltd., and CALP, as well as the acquisition by KEL of interests in resource properties, including interests owned by individuals related to KEL.

Completion of the transaction is subject to certain regulatory and other conditions.

F-40

FINANCIAL STATEMENTS OF THE UNINCORPORATED ASSETS

AUDITORS' REPORT

To the Directors Kaiser Energy Ltd.

We have audited the statement of revenue and operating costs for the properties to be transferred to Kaiser Energy Ltd. ("KEL") as described in Note 1 to the statement (the "Properties") for the years ended December 31, 2004 and 2003. This financial information is the responsibility of KEL's management. Our responsibility is to express an opinion on this financial information based on our audits.

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

In our opinion, the statement of revenue and operating costs presents fairly, in all material respects, the revenue and operating costs of the Properties for the years ended December 31, 2004 and 2003 in accordance with Canadian generally accepted accounting principles.

(Signed) COLLINS BARROW CALGARY LLP
Chartered Accountants

Calgary, Alberta, Canada
September 16, 2005, except as to
notes 4 and 5 which are as of November 30, 2005

F-41

PROPERTIES TO BE TRANSFERRED TO KAISER ENERGY LTD.

STATEMENT OF REVENUE AND OPERATING COSTS

(expressed in thousands of Canadian dollars)

	Nine Months Ended September 30,				Years Ended December 31,
	2005		2004		2004		2003
	(unaudited)		(unaudited)
Petroleum and natural gas sales	$	30,883	$	23,882	$	33,204	$	29,833
Royalties		6,760		4,950		7,116		7,921

		24,123		18,932		26,088		21,912

Petroleum and natural gas production		4,935		4,521		5,866		5,047
Transportation		894		935		1,524		1,128

		5,829		5,456		7,390		6,175

Income from operations	$	18,294	$	13,476	$	18,698	$	15,737

The accompanying notes are an integral part of this financial statement.

F-42

PROPERTIES TO BE TRANSFERRED TO KAISER ENERGY LTD.

NOTES TO STATEMENT OF REVENUE AND OPERATING COSTS

For the Nine Months Ended September 30, 2005 and 2004 (unaudited)
and the Years Ended December 31, 2004 and 2003

(expressed in Canadian dollars)

1. NATURE OF OPERATIONS

On September 9, 2005, Kaiser Energy Ltd. ("KEL") announced that it has retained the services of a financial advisor to seek proposals with the intent of monetizing substantially all of its petroleum and natural gas assets. KEL intends to acquire the assets ("the Properties") held by certain individuals ("the Individuals") and by Kaiser-Francis Oil Company of Canada ("KFOCC"), participants in the Properties, operated by KEL.

Certain Individuals with interests in the Properties are related to KEL through controlling shareholdings, or as officers or employees of KEL or other entities related by common ownership. KFOCC is related to KEL by common ownership.

The statement of revenue and operating expenses for the Properties includes only amounts applicable to the interests of the above-noted participants in the Properties.

The statement of revenue and operating expenses for the Properties does not include any provision for depletion, depreciation and accretion, asset retirement obligations, future capital costs, impairment of unevaluated properties, general and administrative costs, interest or income taxes for the Properties.

2. SIGNIFICANT ACCOUNTING POLICIES

(a): Revenue recognition

(b): Royalties

Royalties are recorded at the time the product is produced and sold. Royalties are calculated in accordance with Alberta Energy regulations or the terms of individual royalty agreements.

(c): Petroleum and natural gas production

Petroleum and natural gas production includes amounts incurred to bring the petroleum and natural gas to the surface, gather, transport, field process, treat, store, and sell same and operating overhead recoveries as established by KEL.

3. COMPARATIVE FIGURES

Certain comparative figures have been restated to conform with the presentation adopted for the current period.

4. UNITED STATES ACCOUNTING PRINCIPLES AND REPORTING

The statement of revenue and operating costs for the properties to be transferred to Kaiser Energy Ltd. has been prepared in Canadian dollars and in accordance with Canadian generally accepted accounting principles ("Canadian GAAP"), which conform to accounting principles generally accepted in the United States ("U.S. GAAP").

F-43

5. SUBSEQUENT EVENT

On November 16, 2005, the shareholder of KEL entered into an agreement with Petrofund Energy Trust ("Petrofund") whereby, Petrofund will acquire all of the outstanding shares of KEL.

Completion of the transaction is subject to certain regulatory and other conditions.

F-44

PART II

INFORMATION NOT REQUIRED TO BE DELIVERED TO OFFEREES OR PURCHASERS

Under the provisions of the Amended and Restated Trust Indenture dated as of November 16, 2004 providing for the creation of the Registrant, the trustee is entitled to be indemnified by the Registrant for any liability and costs, charges and expenses incurred in respect of any action, suit or proceeding against the trustee in respect of anything done or the performance by the trustee of its duties, responsibilities and powers and in respect of the administration and termination of the trust, unless the trustee shall not have exercised its powers and carried out its functions honestly, in good faith and in the best interests of the trust and unitholders.

Under the provisions of the Business Corporations Act (Alberta), the directors and officers of Petrofund Corp., former directors and officers and persons who act or acted at the request of Petrofund Corp. as a director or officer of a corporation of which Petrofund Corp. is or was a shareholder or creditor, and his or her heirs and legal representatives, are entitled to be indemnified by Petrofund Corp. against any costs, charges and expenses including an amount paid to settle an action or satisfy a judgement, reasonably incurred by him or her in respect of any civil, criminal or administrative action or proceeding to which he or she is made a party by reason of being or having been such a director or officer (except in respect of an action by or on behalf of Petrofund Corp. to procure a judgement in its favor), if (a) he or she acted honestly and in good faith with a view to the best interests of Petrofund Corp.; and (b) in the case of a criminal or administrative action or proceeding that is enforced by a monetary penalty, he or she had reasonable grounds for believing that his or her conduct was lawful. Such indemnification may be made in respect of an action by or on behalf of Petrofund Corp. to procure a judgement in its favor only with prior approval of the court having jurisdiction and only if such director or officer fulfils the conditions set forth in (a) and (b) above. Such director or officer is entitled to such indemnification as a matter of right if he or she was substantially successful on the merits in his or her defense in the proceeding and fulfils the conditions set forth in (a) and (b) above.

Liability insurance is in place for the benefit of the directors and officers, former directors and officers of Petrofund Corp. and every person who acts or acted at its request as a director or officer of a body corporate of which Petrofund Corp. is or was a shareholder or creditor, and their respective heirs and legal representatives, in the amount of Cdn$40,000,000 subject to a deductible.

Insofar as indemnification for liabilities arising under the Securities Act of 1933, as amended (the "Securities Act") may be permitted to directors, officers or persons controlling the Registrant pursuant to the foregoing provisions, the Registrant has been informed that, in the opinion of the U.S. Securities and Exchange Commission, such indemnification is against public policy as expressed in the Securities Act and is therefore unenforceable.

II-1

Exhibits

Exhibit Number		Description
1.1		Agreement of Purchase and Sale dated November 16, 2005 between Kaiser-Francis Oil Company of Canada and Petrofund Corp.
3.1		Underwriting Agreement between the Registrant and the underwriters listed therein, dated November 18, 2005.
4.1		Renewal Annual Information Form of the Registrant dated March 15, 2005 (incorporated herein by reference to the Registrant's Annual Report on Form 40-F, filed with the Commission on March 17, 2005).
4.2		Audited comparative consolidated financial statements and notes thereto of the Registrant as at December 31, 2004 and 2003 and for each of the years in the three-year period ended December 31, 2004, together with the reports of the independent registered chartered accountants thereon dated March 1, 2005 (incorporated herein by reference to the Registrant's Annual Report on Form 40-F, filed with the Commission on March 17, 2005).
4.3		Management's discussion and analysis of the financial condition and operating results of the Registrant for the year ended December 31, 2004 (incorporated herein by reference to the Registrant's Annual Report on Form 40-F, filed with the Commission on March 17, 2005).
4.4		Unaudited interim comparative consolidated financial statements of the Registrant for the nine months ended September 30, 2005 and 2004.
4.5		Management's discussion and analysis of the financial condition and operating results of the Registrant for the nine months ended September 30, 2005 (incorporated herein by reference to the Registrant's Interim Report on Form 6-K, filed with the Commission on November 10, 2005).
4.6		Information Circular of the Registrant dated February 28, 2005, relating to the annual meeting of Unitholders held on April 13, 2005 (excluding those portions thereof which appear under the headings "Report on Executive Compensation", "Performance Graph" and "Statement of Corporate Governance Practices") (incorporated herein by reference to the Registrant's Interim Report on Form 6-K, filed with the Commission on May 12, 2005).
4.7		Audited comparative consolidated financial statements and notes thereto of Ultima Energy Trust for the fiscal years ended December 31, 2003 and 2002, together with the report of the auditors thereon dated February 24, 2004 (except as to Notes 14 and 15 which are as of April 30, 2004).
4.8		Unaudited interim comparative consolidated financial statements of Ultima Energy Trust for the three months ended March 31, 2004 and 2003.
4.9		Material Change Report dated November 25, 2005.
5.1		Consent of Deloitte & Touche LLP, Independent Registered Chartered Accountants.
5.2		Consent of Burnet, Duckworth & Palmer LLP.
5.3		Consent of Blake, Cassels & Graydon LLP.
5.4		Consents of GLJ Petroleum Consultants Ltd.
5.5		Consent of Collins Barrow Calgary LLP.
6.1		Power of Attorney (included on the signature page of the Registration Statement).
7.1		Amended and Restated Trust Indenture dated November 16, 2004 between the Registrant and Computershare Trust Company of Canada, as trustee.

II-2

PART III

UNDERTAKING AND CONSENT TO SERVICE OF PROCESS

Item 1. Undertaking

The Registrant undertakes to make available, in person or by telephone, representatives to respond to inquiries made by the Commission staff, and to furnish promptly, when requested to do so by the Commission staff, information relating to the securities registered pursuant to Form F-10 or to transactions in said securities.

Item 2. Consent to Service of Process

Concurrently with the filing of this Registration Statement on Form F-10, the Registrant and Computershare Trust Company of Canada, as trustee with respect to the securities registered hereby, are filing with the Commission a written irrevocable consent and power of attorney on Form F-X.

III-1

SIGNATURES

Pursuant to the requirements of the Securities Act of 1933, the Registrant certifies that it has reasonable grounds to believe that it meets all of the requirements for filing on Form F-10 and has duly caused this Registration Statement to be signed on its behalf by the undersigned, thereunto duly authorized, in the City of Calgary, Province of Alberta, Canada, on November 30, 2005.

		PETROFUND ENERGY TRUST BY: PETROFUND CORP.
		By:	/s/ JEFFERY E. ERRICO Jeffery E. Errico President and Chief Executive Officer

III-2

POWER OF ATTORNEY

KNOW ALL MEN BY THESE PRESENTS, that each person whose signature appears below constitutes and appoints each of Jeffery E. Errico and Edward J. Brown, his true and lawful attorney-in-fact and agent, with full power of substitution and resubstitution, for him in his name, place and stead, in any and all capacities, to sign any and all amendments (including post-effective amendments) and supplements to this Registration Statement, and to file the same, with all exhibits hereto, and other documents in connection therewith, with the Securities and Exchange Commission, granting unto said attorneys-in-fact and agents, and each acting alone, full power and authority to do and perform each and every act and thing requisite and necessary to be done, as fully to all intents and purposes as they might or could do themselves, hereby ratifying and confirming all that said attorneys-in-fact and agents or any of them acting alone, or his or their substitute or substitutes, may lawfully do or cause to be done by virtue hereof.

Pursuant to the requirements of the Securities Act of 1933, this Registration Statement has been signed by the following persons in the capacities indicated on November 30, 2005:

Signature		Title

/s/ JEFFERY E. ERRICO Jeffery E. Errico		President and Chief Executive Officer, Petrofund Corp. (principal executive officer)
/s/ EDWARD J. BROWN Edward J. Brown		Vice President, Finance and Chief Financial Officer Petrofund Corp. (principal financial and accounting officer)
/s/ JAMES E. ALLARD James E. Allard		Director, Petrofund Corp.
/s/ SANDRA S. COWAN Sandra S. Cowan		Director, Petrofund Corp.
/s/ JOHN F. DRISCOLL John F. Driscoll		Director, Petrofund Corp.
/s/ ARTHUR E. DUMONT Arthur E. Dumont		Director, Petrofund Corp.
/s/ JEFFERY E. ERRICO Jeffery E. Errico		Director, Petrofund Corp.
/s/ GARY L. LEE Gary L. Lee		Director, Petrofund Corp.
/s/ WAYNE M. NEWHOUSE Wayne M. Newhouse		Director, Petrofund Corp.
/s/ FRANK POTTER Frank Potter		Director, Petrofund Corp.

III-3

Pursuant to the requirements of Section 6(a) of the Securities Act of 1933, the Authorized Representative has signed this Registration Statement, solely in his capacity as the duly authorized representative of Petrofund Energy Trust in the United States, in the City of Newark, State of Delaware, on November 30, 2005.

		PUGLISI & ASSOCIATES (Authorized U.S. Representative)
		By:	/s/ GREGORY F. LAVELLE Name: Gregory F. Lavelle Title: Managing Director

III-4

Exhibit Index

Exhibit Number		Description		Page Number
1.1		Agreement of Purchase and Sale dated November 16, 2005 between Kaiser-Francis Oil Company of Canada and Petrofund Corp.
3.1		Underwriting Agreement between the Registrant and the underwriters listed therein, dated November 18, 2005.
4.1		Renewal Annual Information Form of the Registrant dated March 15, 2005 (incorporated herein by reference to the Registrant's Annual Report on Form 40-F, filed with the Commission on March 17, 2005).
4.2		Audited comparative consolidated financial statements and notes thereto of the Registrant as at December 31, 2004 and 2003 and for each of the years in the three-year period ended December 31, 2004, together with the reports of the independent registered chartered accountants thereon dated March 1, 2005 (incorporated herein by reference to the Registrant's Annual Report on Form 40-F, filed with the Commission on March 17, 2005).
4.3		Management's discussion and analysis of the financial condition and operating results of the Registrant for the year ended December 31, 2004 (incorporated herein by reference to the Registrant's Annual Report on Form 40-F, filed with the Commission on March 17, 2005).
4.4		Unaudited interim comparative consolidated financial statements of the Registrant for the nine months ended September 30, 2005 and 2004.
4.5		Management's discussion and analysis of the financial condition and operating results of the Registrant for the nine months ended September 30, 2005 (incorporated herein by reference to the Registrant's Interim Report on Form 6-K, filed with the Commission on November 10, 2005).
4.6		Information Circular of the Registrant dated February 28, 2005, relating to the annual meeting of Unitholders held on April 13, 2005 (excluding those portions thereof which appear under the headings "Report on Executive Compensation", "Performance Graph" and "Statement of Corporate Governance Practices") (incorporated herein by reference to the Registrant's Interim Report on Form 6-K, filed with the Commission on May 12, 2005).
4.7		Audited comparative consolidated financial statements and notes thereto of Ultima Energy Trust for the fiscal years ended December 31, 2003 and 2002, together with the report of the auditors thereon dated February 24, 2004 (except as to Notes 14 and 15 which are as of April 30, 2004).
4.8		Unaudited interim comparative consolidated financial statements of Ultima Energy Trust for the three months ended March 31, 2004 and 2003.
4.9		Material Change Report dated November 25, 2005.
5.1		Consent of Deloitte & Touche LLP, Independent Registered Chartered Accountants.
5.2		Consent of Burnet, Duckworth & Palmer LLP.
5.3		Consent of Blake, Cassels & Graydon LLP.
5.4		Consents of GLJ Petroleum Consultants Ltd.
5.5		Consent of Collins Barrow Calgary LLP.
6.1		Power of Attorney (included on the signature page of the Registration Statement).
7.1		Amended and Restated Trust Indenture dated November 16, 2004 between the Registrant and Computershare Trust Company of Canada, as trustee.

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