No securities regulatory authority has expressed an opinion about these securities and it is an offence to claim otherwise.

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. These securities have not been, and will not be, registered under the United States Securities Act of 1933, as amended (the "1933 Act"), or any state securities laws. Accordingly, except as permitted by the Underwriting Agreement (as defined herein) and pursuant to an exemption from the registration requirements of the 1933 Act and applicable state securities laws, these securities may not be offered or sold within the United States. This short form prospectus does not constitute an offer to sell or a solicitation of an offer to buy any of these securities within the United States. See "Plan of Distribution".

Information has been incorporated by reference in this prospectus from documents filed with the securities commissions or similar authorities in Canada. For the purpose of the Province of Québec, this simplified prospectus contains information to be completed by consulting the permanent information record. Copies of the documents incorporated herein by reference and of the permanent information record may be obtained on request without charge from the secretary of Paramount Energy Operating Corp., the administrator of Paramount Energy Trust, at 500, 630 – 4^th Avenue S.W., Calgary, Alberta T2P 0J9, Telephone (403) 269-4400, and are also available electronically at www.sedar.com.

New Issue

June 12, 2007

SHORT FORM PROSPECTUS

$250,512,500
20,450,000 Subscription Receipts,
each representing the right to receive one trust unit

and

$75,000,000

6.50% Convertible Extendible Unsecured Subordinated Debentures

Paramount Energy Trust (the "Trust", "PET", "us", "we" or "our" and, where the context requires, also includes the Trust's subsidiaries) is hereby qualifying for distribution 20,450,000 subscription receipts ("Subscription Receipts") at a price of $12.25 per Subscription Receipt and 75,000 6.50% convertible extendible unsecured subordinated debentures (the "Debentures") at a price of $1,000 per Debenture (collectively, the "Offering").

Subscription Receipts

Each Subscription Receipt 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 indirect acquisition (the "Acquisition") by the Trust of certain petroleum and natural gas properties and related assets in east central Alberta by way of the indirect acquisition of all of the issued and outstanding shares (the "PrivateCo Shares") of a privately owned oil and gas company ("PrivateCo") and certain other transactions pursuant to the Share Purchase Agreement and Teaming Agreement (as such terms are defined herein) all as 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 August 31, 2007, the Escrowed Funds and the interest thereon will be released to the Trust and each holder of Subscription Receipts will receive one Unit for each Subscription Receipt held. The Trust will utilize the Escrowed Funds to pay a portion of the purchase price for the Acquisition.

If the closing of the Acquisition does not take place by 5:00 p.m. (Calgary time) on August 31, 2007, if the Acquisition is terminated at any earlier time or if the Trust has advised the Underwriters or announced to the public that it does not intend to

2

proceed with the Acquisition (in any case, the "Termination Time"), holders of Subscription Receipts shall be entitled to receive an amount equal to the full subscription price therefor and their pro rata entitlement to interest on such amount. The Escrowed Funds will be applied towards payment of such amount.

If the closing of the Acquisition takes place 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 terms of the Subscription Receipts. See "Details of the Offering".

Debentures

The Debentures have an initial maturity date ofAugust 31, 2007 (the "Initial Maturity Date"). If the closing of the Acquisition takes place by the Termination Time, the maturity date will be automatically extended from the Initial Maturity Date to June 30, 2012 (the "Final Maturity Date"). If closing of the Acquisition does not take place by the Termination Time, the Debentures will mature on the Initial Maturity Date. See "Details of the Offering".

The Debentures bear interest at an annual rate of 6.50% payable semi-annually in arrears on June 30 and December 31 in each year commencing December 31, 2007. The Debentures are redeemable by the Trust at a price of $1,050 per Debenture after June 30, 2010, and on or before June 30, 2011 and at a price of $1,025 per Debenture after June 30, 2011 and before maturity on June 30, 2012, in each case, plus accrued and unpaid interest thereon, if any. See "Details of the Offering".

Debenture Conversion Privilege

Each Debenture will be convertible into Units at the option of the holder at any time after the Initial Maturity Date and prior to the close of business on the earlier of the Final Maturity Date and the business day immediately preceding the date specified by the Trust for redemption of the Debentures, at a conversion price of $14.20 per Unit, subject to adjustment in certain events. Holders converting their Debentures will receive accrued and unpaid interest thereon. Notwithstanding the foregoing, no Debentures may be converted during the three business days preceding June 30 and December 31, in each year, commencing December 31, 2007, as the registers of the Debenture Trustee (as defined herein) will be closed during such periods.

In the opinion of Burnet, Duckworth & Palmer LLP, counsel to the Trust, and Stikeman Elliott LLP, counsel to the Underwriters (as defined herein), subject to the qualifications and assumptions discussed under the heading "Eligibility for Investment", the Securities (as defined herein), on the date of closing of the Offering, will be qualified investments under the Tax Act (as defined herein) and the regulations thereunder for trusts governed by registered retirement savings plans, registered retirement income funds, deferred profit sharing plans (except, in the case of the Debentures, a deferred profit sharing plan to which the Trust has made a contribution) and registered education savings plans. Although the October 31, 2006 Proposals (as defined herein) will not modify the eligibility for investment of the Securities for the above noted plans, it is expected that the October 31, 2006 Proposals will reduce the amount of cash available for distributions on the Units commencing in 2011. See "Eligibility for Investment".

The issued and outstanding Units are listed on the Toronto Stock Exchange (the "TSX") under the trading symbol PMT.UN. On May 28, 2007, the last trading day prior to the public announcement of the Offering, the closing price of the Trust Units on the TSX was $13.13 and on June 11, 2007, the last trading day prior to the filing of this short form prospectus, the closing price of the Trust Units on the TSX was $11.97. There is currently no market through which the Subscription Receipts or Debentures may be sold and purchasers may not be able to resell Subscription Receipts or Debentures purchased under this short form prospectus. The TSX has conditionally approved the listing of the Securities. Listing is subject to the Trust fulfilling all of the requirements of the TSX on or before August 31, 2007. The offering price of the Subscription Receipts and Debentures was determined by negotiation between Paramount Energy Operating Corp. (the "Administrator" or "PEOC") on behalf of the Trust, and BMO Nesbitt Burns Inc., on its own behalf and on behalf ofScotia Capital Inc., CIBC World Markets Inc., TD Securities Inc., National Bank Financial Inc., RBC Dominion Securities Inc., FirstEnergy Capital Corp., GMP Securities L.P., Raymond James Ltd., Blackmont Capital Inc., Canaccord Capital Corporation, Cormark Securities Inc., Dundee Securities Corporation and Peters & Co. Limited (collectively, the "Underwriters").

3

Price: $12.25 per Subscription Receipt and $1,000 per Debenture

						Net Proceeds
		Price to the Public		Underwriters' Fee(1)		to the Trust(2)
Per Subscription Receipt	$	12.25	$	0.6125	$	11.6375
Total	$	250,512,500	$	12,525,625	$	237,986,875
Per Debenture	$	1,000	$	40	$	960
Total	$	75,000,000	$	3,000,000	$	72,000,000
Total(3)	$	325,512,500	$	15,525,625	$	309,986,875

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 $500,000, which will be paid from the general funds of the Trust.
(3)	The Trust has granted to the Underwriters an option (the "Over-Allotment Option") to purchase up to an additional 3,067,500 Subscription Receipts at a price of $12.25 per Subscription Receipt on the same terms and conditions as the Offering, exercisable in whole or in part from time to time, not later than the earlier of (i) the 30th day following the closing of the Offering, and (ii) the Termination Time, for the purposes of covering the Underwriters' over-allocation position. If the Over-Allotment Option is exercised in whole or in part following the closing of the Acquisition, an equal number of Units will be issued in lieu of Subscription Receipts.
	If the Over-Allotment Option is exercised in full, the Total Price to the Public, Underwriters' Fee and Net Proceeds to the Trust (before deducting expenses of the Offering) will be $363,089,375, $17,404,468.75 and $345,684,906.25 respectively. This short form prospectus also qualifies for distribution of the grant of the Over-Allotment Option and the issuance of Subscription Receipts pursuant to the exercise of the Over-Allotment Option. See "Plan of Distribution" and the table below.

	Maximum size or number of
Underwriters' Position	securities held	Exercise period	Exercise price
Over-Allotment Option	3,067,500 Subscription	Earlier of 30 days following closing of the	$12.25 per
	Receipts	Offering and the Termination Time	Subscription Receipt

The Underwriters, as principals, conditionally offer the Subscription Receipts and the Debentures, subject to prior sale, if, as and when issued by the Trust 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 Stikeman Elliott LLP.

The head office of the Trust, and the head and registered office of the Administrator are located at 500, 630 – 4th Avenue S.W., Calgary, Alberta T2P 0J9.

BMO Nesbitt Burns Inc., Scotia Capital Inc., CIBC World Markets Inc., TD Securities Inc. and National Bank Financial Inc., five of the Underwriters, are direct or indirect wholly-owned subsidiaries of Canadian chartered banks which are lenders to the Trust. Consequently, the Trust may be considered to be a connected issuer of these Underwriters within the meaning of applicable Canadian securities legislation. See "Relationship Among the Trust and Certain Underwriters".

A return on an investment in the Trust is not comparable to the return on an investment in a fixed-income security. The recovery of an initial investment in the Trust is at risk, and the anticipated return on such investment is based on many performance assumptions. Although the Trust intends to make distributions of its available cash to holders of Trust Units ("Unitholders"), these cash distributions are not guaranteed and may be reduced or suspended. The actual amount distributed will depend on numerous factors including the financial performance of the subsidiaries of the Trust, debt obligations, commodity prices, production levels, working capital requirements, future capital requirements, the timing and application of the October 31, 2006 Proposals, 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 or if the October 31, 2006 Proposals apply to the Trust and its Unitholders before 2011, and that decline may be significant.

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 it receives. See, for example, the risks described under "Risk Factors"

4

herein and in the AIF (as defined herein). These sections also describe the Trust's assessment of those risk factors, as well as the potential consequences to an investor if a risk should occur. The Trust has not obtained a stability rating from an independent rating agency regarding the relative stability and sustainability of the Trust's cash distribution stream. Cash distributions by the Trust to Unitholders are not guaranteed.

The after-tax return from an investment in Trust Units to Unitholders subject to Canadian income tax can be made up of both a return on, and a return of, capital. That composition may change over time, thus affecting an investor's after-tax return.

On May 15, 2007, Bill C-52 An Act to implement certain provisions of the budget tabled in Parliament on March 19, 2007 ("Bill C-52") received Second Reading in the Canadian House of Commons. Bill C-52 includes legislative provisions to implement proposals originally announced on October 31, 2006 relating to the taxation of certain income trusts and partnerships (the "October 31, 2006 Proposals") under the Tax Act. Pursuant to the October 31, 2006 Proposals, commencing January 1, 2011 (provided the Trust does not exceed "normal growth" guidelines issued by the Department of Finance) certain distributions from the Trust which would have otherwise been taxed as ordinary income generally will be characterized as dividends, in addition to the Trust generally being subject to tax on certain income at tax rates that approximate those applicable to corporations. Returns of capital generally are (and under the October 31, 2006 Proposals will continue to be) tax-deferred for Unitholders who are resident in Canada for purposes of the Tax Act (and reduce such Unitholder's adjusted cost base in the Trust Unit for purposes of the Tax Act). Distributions, whether of income or capital, to a Unitholder who is not resident in Canada for purposes of the Tax Act, or that is a partnership that is not a "Canadian partnership" for purposes of the Tax Act, generally will be subject to Canadian withholding tax. Prospective purchasers should consult their own tax advisors with respect to the Canadian income tax considerations applicable in their own circumstances. See "Recent Developments – Proposed Federal Tax Changes" and "Certain Canadian Federal Income Tax Considerations".

Subscriptions for Subscription Receipts and Debentures will be received subject to rejection or allotment in whole or in part and the right is reserved to close the subscription books at any time without notice. It is expected that closing will occur on or about June 20, 2007 or such other date not later than June 30, 2007 as the Trust and the Underwriters may agree. The Subscription Receipts will be represented by a global certificate issued in registered form to CDS Clearing and Depository Services Inc. ("CDS") or its nominee under the book-based system administered by CDS. Certificates for the aggregate principal amount of the Debentures will be issued in registered form to CDS and will be deposited with CDS on the date of closing. No certificates evidencing the Subscription Receipts or Debentures will be issued to subscribers except in certain limited circumstances, and registration will be made in the depositary service of CDS. Subscribers for Subscription Receipts and Debentures will receive only a customer confirmation from the Underwriter or other registered dealer who is a CDS participant and from or through whom a beneficial interest in the Subscription Receipts or Debentures is purchased. Subject to applicable laws, the Underwriters may, in connection with the Offering, effect transactions which stabilize or maintain the market price of the Subscription Receipts, the Units or the Debentures at levels other than those that might otherwise prevail on the open market. The Underwriters may offer the Subscription Receipts at a price lower than the price noted above. See "Plan of Distribution".

The interest coverage ratio in respect of the Debentures for the year ended December 31, 2006 and the twelve month period ended March 31, 2007, is less than 1:1. Interest coverage ratios based on funds flow (as defined herein) for these periods exceed 1:1. See "Interest Coverage".

The Subscription Receipts, the Units and the Debentures 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.

5

TABLE OF CONTENTS

	Page
SPECIAL NOTE REGARDING FORWARD-LOOKING STATEMENTS	6
NON-GAAP MEASURES	6
PRESENTATION OF OIL AND GAS RESERVES AND PRODUCTION INFORMATION	6
SELECTED ABBREVIATIONS AND DEFINITIONS	6
CONVENTIONS	9
DOCUMENTS INCORPORATED BY REFERENCE	9
SUMMARY DESCRIPTION OF THE BUSINESS	10
RECENT DEVELOPMENTS	10
INFORMATION CONCERNING PRIVATECO, ACQUISITIONCO, BCO AND THE ACQUIRED ASSETS	14
DESCRIPTION OF SECURITIES BEING DISTRIBUTED	22
INTEREST COVERAGE	22
CONSOLIDATED CAPITALIZATION	23
PRICE RANGE AND TRADING VOLUME OF THE TRUST UNITS	23
DISTRIBUTION TO UNITHOLDERS	24
USE OF PROCEEDS	24
DETAILS OF THE OFFERING	25
PLAN OF DISTRIBUTION	31
RELATIONSHIP AMONG THE TRUST AND CERTAIN UNDERWRITERS	32
INTEREST OF EXPERTS	33
CERTAIN CANADIAN FEDERAL INCOME TAX CONSIDERATIONS	33
ELIGIBILITY FOR INVESTMENT	40
RISK FACTORS	41
MATERIAL CONTRACTS	44
AUDITORS, TRANSFER AGENT AND REGISTRAR	44
STATUTORY AND CONTRACTUAL RIGHTS OF RESCISSION AND STATUTORY RIGHTS OF WITHDRAWAL	44
AUDITORS' CONSENTS	46
FINANCIAL STATEMENTS	F-1
CERTIFICATE OF THE TRUST	C-1
CERTIFICATE OF THE UNDERWRITERS	C-2

6

SPECIAL NOTE REGARDING FORWARD-LOOKING STATEMENTS

Certain statements contained in this short form prospectus and the documents incorporated by reference herein constitute forward-looking statements. These statements relate to future events or the Trust's future performance as noted in the documents incorporated by reference herein and including, without limitation, the completion and closing of the Acquisition and Offering and the timing thereof, the amount of oil and natural gas reserves and future production relating to the Acquired Assets, the effect of the October 31, 2006 Proposals and the use of the proceeds of the Offering. All statements other than statements of historical fact are forward-looking statements. Wherever possible, the use of any of the words "anticipate", "plan", "continue", "estimate", "expect", "may", "will", "project", "could", "believe", "predict", "potential", "should" 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, performance, achievements or events to differ materially from those anticipated, discussed or implied in such forward-looking statements. The Trust and the Administrator believe the expectations reflected in such 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 this short form prospectus and the documents incorporated by reference herein should be considered carefully and investors should not place undue reliance on them as the Trust and the Administrator cannot assure investors that actual results will be consistent with these forward-looking statements. These statements speak only as of the date of this prospectus or the particular document incorporated by reference herein. The forward looking statements contained in this short form prospectus and the documents incorporated by reference herein are expressly qualified by this cautionary statement. Neither the Trust, the Administrator, Paramount Operating Trust nor any of the Underwriters undertakes any obligation to publicly update or revise any forward-looking statements except as expressly required by applicable securities law. See "Special Note Regarding Forward-Looking Statements" in the AIF.

NON-GAAP MEASURES

In this short form prospectus, we use funds flow from operations before changes in non-cash working capital, settlement of asset retirement obligations and certain exploration costs ("funds flow"), funds flow per Trust Unit and annualized funds flow to analyze operating performance and financial leverage. Funds flow as presented does not have any standardized meaning prescribed by Canadian generally accepted accounting principles ("GAAP") and, therefore, it may not be comparable to the calculation of similar measures for other entities. Funds flow as presented is not intended to represent operating funds flow or operating profits for the period nor should it be viewed as an alternative to cash flow from operating activities, net earnings or other measures of financial performance calculated in accordance with GAAP. Funds flow cannot be assured and future distributions may vary. A reconciliation of funds flow to cash flow from operating activities is presented in our management's discussion and analysis. We use the term "funds flow" as an indicator of financial performance because the term "funds flow" is often utilized by investors to evaluate royalty trusts and income funds in the oil and gas sector. See "Non-GAAP Measures" in the AIF and "Significant Accounting Policies and Non-GAAP Measures" in our management's discussion and analysis.

PRESENTATION OF OIL AND GAS RESERVES AND PRODUCTION INFORMATION

All oil and natural gas reserve information contained in this short form prospectus and the documents incorporated by reference herein has been prepared and presented in accordance with NI 51-101 (as defined herein). The actual oil and natural gas reserves and future production will be greater than or less than the estimates provided in this short form prospectus and in the documents incorporated by reference herein. The estimated future net revenue from the production of the disclosed oil and natural gas reserves does not represent the fair market value of these reserves. The Trust has adopted the standard of 6 Mcf:1 boe when converting natural gas to barrels of oil equivalent and 6 Mcfe:1bbl when converting barrels of oil to thousands of cubic fee of natural gas equivalent. Boes and Mcfe's may be misleading, particularly if used in isolation. A conversion ratio of 6 Mcf:1 boe and 6Mcfe:1bbl is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead.

SELECTED ABBREVIATIONS AND DEFINITIONS

In this short form prospectus, and in addition to the abbreviations and terms defined elsewhere in this short form prospectus, the abbreviations and terms set forth below have the meanings indicated:

"$000s" means thousands of dollars

"Mcf" means one thousand cubic feet

"bbl" means one barrel

"Mcfe" means thousand cubic feet equivalent

7

"bbl/d" means barrels per day

"Mcfe/d" means thousand cubic feet equivalent per day

"Bcf" means one billion cubic feet

"MMboe" means one thousand barrels of oil equivalent

"Bcfe" means one billion cubic feet equivalent

"MMcf" means one million cubic feet

"boe" means barrels of oil equivalent

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

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

"MMcfe/d" means one million cubic feet equivalent per day

"Mbbls" means one thousand barrels

"NGL" means natural gas liquids

"Mboe" means one thousand barrels of oil equivalent

"Acquired Assets" means those petroleum and natural gas properties and related assets forming part of the Vendor Assets that the Trust will indirectly own following completion of the Acquisition, as described in more detail under "Information Concerning PrivateCo, AcquisitionCo, BCo and the Acquired Assets";

"Acquisition" means, collectively, the acquisition by AcquisitionCo of the PrivateCo Shares pursuant to the Share Purchase Agreement and the indirect acquisition by POT and Baytex of the Vendor Assets (in the case of the Trust, the indirect acquisition of the Acquired Assets and, in the case of Baytex, the indirect acquisition of the Baytex Assets) pursuant to the Share Purchase Agreement and the Teaming Agreement as more particularly described under "Recent Developments – The Acquisition";

"AcquisitionCo" means 1325115 Alberta Ltd., a corporation formed, and solely owned, by POT under the ABCA solely for the purpose of acquiring the PrivateCo Shares and participating in the transactions contemplated by the Share Purchase Agreement and the Teaming Agreement;

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

"AIF" means the Annual Information Form of the Trust dated March 13, 2007;

"Baytex" means Baytex Energy Trust, a trust formed pursuant to the laws of Alberta;

"Baytex Assets" means those petroleum and natural gas properties and related assets forming part of the Vendor Assets that Baytex Energy will own following completion of the Acquisition;

"Baytex Energy" means Baytex Energy Ltd., a corporation incorporated under the ABCA;

"BCo" means 1325059 Alberta Ltd., a corporation formed and solely owned by POT under the ABCA solely for the purpose of participating in the transactions contemplated by the Teaming Agreement;

"COGE Handbook" means the Canadian Oil and Gas Evaluation Handbook;

"Debenture Trustee" means Computershare Trust Company of Canada or its successor as trustee under the Indenture;

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

"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;

"Final Maturity Date" means June 30, 2012;

"Indenture" means the third supplemental trust indenture to be dated as of the date of closing of the Offering, together with the trust indenture dated August 10, 2004 between the Trust and the Debenture Trustee governing the terms of the Debentures;

"Initial Maturity Date" means August 31, 2007;

8

"NI 51-101" means National Instrument 51-101 – Standards of Disclosure for Oil and Natural Gas Activities;

"Partnership"means a partnership organized under the laws of Alberta, which holds all of the Vendor Assets;

"PET Trust Indenture" or "Trust Indenture" means the First Amended and Restated Trust Indenture made effective as of August 1, 2002, which amended and restated the trust indenture dated June 28, 2002 pursuant to which PET was formed, as the same may be further amended, restated or replaced from time to time;

"Post-Closing Transactions" means the various transactions that will occur immediately following the closing of the transactions contemplated by the Share Purchase Agreement;

"POT" means Paramount Operating Trust, an unincorporated trust of which PET is the sole beneficiary, formed under the laws of the Province of Alberta pursuant to the POT Trust Indenture;

"POT Royalty" means a contractual royalty of 99% of POT's net revenue from its petroleum and natural gas properties may acquire from time to time less permitted deductions with respect to debt payments, capital expenditures and certain other amounts, granted by POT to PET pursuant to the POT Royalty Agreement;

"POT Royalty Agreement" means the royalty agreement entered into between POT, as grantor, and PET, as royalty owner;

"POT Trust Indenture" means the First Amended and Restated Trust Indenture made effective as of August 1, 2002, which amended and restated the trust indenture dated June 28, 2002 pursuant to which POT was formed, as the same may be further amended, restated or replaced from time to time;

"Pre-Closing Transactions" means the various transactions that will occur prior to the closing of the transactions contemplated by the Share Purchase Agreement;

"PrivateCo" means a privately owned oil and gas company incorporated under the ABCA, currently owned by the Sellers and to be acquired by AcquisitionCo pursuant to the Share Purchase Agreement and, where the context requires, also includes all of the Sellers' Canadian exploration and production operating affiliates and subsidiaries on a consolidated basis;

"PrivateCo Shares" means all of the issued and outstanding shares of PrivateCo;

"Ryder Scott" means Ryder Scott Company Petroleum Consultants, independent oil and gas reservoir engineers of Calgary, Alberta;

"Ryder Scott Report" means the independent engineering evaluation dated effective December 31, 2006 evaluating the oil, natural gas and NGL reserves and the net present values of the reserves for these oil, natural gas and NGL reserves of the Acquired Assets prepared by Ryder Scott, based on forecast prices and costs as at December 31, 2006;

"Securities" means, collectively, the Subscription Receipts (including those issuable on exercise of the Over-Allotment Option), the Debentures and the Units issued pursuant to the Subscription Receipts and on the conversion, redemption or maturity of the Debentures;

"Sellers" means certain affiliates of a public U.S. energy company;

"Share Purchase Agreement" means the agreement dated May 29, 2007 among AcquisitionCo, the Trust, Baytex and the Sellers pursuant to which AcquisitionCo agreed to purchase all of the PrivateCo Shares and the Trust and Baytex agreed to guarantee the obligations of AcquisitionCo thereunder;

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

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

9

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

"Teaming Agreement" means the agreement dated May 29, 2007 among Baytex Energy, POT, AcquisitionCo and BCo pursuant to which the parties agreed to complete (or cause their affiliates to complete) the Pre-Closing Transactions, to execute the Share Purchase Agreement and close the transactions contemplated thereby, and to undertake the Post-Closing Transactions, and pursuant to which the parties have outlined their respective rights, duties and obligations in connection with the foregoing;

"Trustee" means Computershare Trust Company of Canada, or its successor as trustee of the Trust;

"TSX" means the Toronto Stock Exchange;

"Underwriting Agreement" means the agreement dated as of May 29, 2007 among the Trust, POT, the Administrator and the Underwriters in respect of the Offering;

"Underwriters" means, collectively, BMO Nesbitt Burns Inc., Scotia Capital Inc., CIBC World Markets Inc., TD Securities Inc., National Bank Financial Inc., RBC Dominion Securities Inc., FirstEnergy Capital Corp., GMP Securities L.P., Raymond James Ltd., Blackmont Capital Inc., Canaccord Capital Corporation, Cormark Securities Inc., Dundee Securities Corporation and Peters & Co. Limited;

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

"Unitholders" means the holders from time to time of the Units;

"Units" or "TrustUnits" means trust units of the Trust; and

"Vendor Assets" means all of the petroleum and natural gas properties and related assets of PrivateCo, which will be indirectly acquired by the Trust and Baytex pursuant to the Share Purchase Agreement and the transactions contemplated by the Teaming Agreement.

CONVENTIONS

Certain terms used herein are defined in NI 51-101 and the COGE Handbook and, unless the context otherwise requires, shall have the same meanings in this short form prospectus as in NI 51-101 and the COGE Handbook. Unless otherwise indicated, references in this short form prospectus to "$" or "dollars" are to Canadian dollars. All financial information contained in this short form prospectus has been presented in Canadian dollars in accordance with generally accepted accounting principles in Canada unless otherwise noted. Words importing the singular number only include the plural, and vice versa, and words importing any gender include all genders.

DOCUMENTS INCORPORATED BY REFERENCE

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

(a)	the AIF;
(b)	the audited comparative consolidated financial statements of the Trust as at and for the years ended December 31, 2006 and 2005, together with the notes thereto and the auditors' report thereon;
(c)	the management's discussion and analysis of the financial condition and results of operations of the Trust as at and for the year ended December 31, 2006;
(d)	the unaudited comparative consolidated financial statements of the Trust as at and for the three month period ended March 31, 2007, together with the notes thereto;

10

(e)	the management's discussion and analysis of the financial condition and results of operations of the Trust as at and for the three month period ended March 31, 2007;
(f)	the Trust's Management Information Circular and Proxy Statement dated March 20, 2007 relating to the annual general meeting of Unitholders held on May 11, 2007;
(g)	the Trust's Management Information Circular and Proxy Statement dated March 21, 2006 relating to the annual general and special meeting of Unitholders held on May 11, 2006; and
(h)	the material change report of the Trust dated June 12, 2007 relating to the Acquisition and the Offering.

Any documents of the type described in Section 11.1 of Form 44-101F1 - Short Form Prospectus, if filed by the Trust with the securities commissions or similar authorities in the provinces of Canada after the date of this short form prospectus and before the termination of this distribution, are deemed to be incorporated by reference in this short form prospectus.

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

SUMMARY DESCRIPTION OF THE BUSINESS

Our goal is to provide Unitholders with a vehicle through which we can distribute income and add value through the exploitation of current assets, low exposure exploration of our undeveloped land base and prudent acquisitions of additional lands and assets. Our business plan is based on four pillars: asset optimization; funds flow maximization; accretive acquisitions; and balance sheet strength. See "Description of the Business" in the AIF.

RECENT DEVELOPMENTS

The Acquisition

Overview

On May 29, 2007, AcquisitionCo, Baytex Energy and POT entered into the Share Purchase Agreement with the Sellers, which provides for the acquisition by AcquisitionCo of PrivateCo, the material assets of which are its interest in the Partnership, which holds the Vendor Assets, and the shares in certain affiliated entities for an aggregate purchase price (the "Purchase Price") of approximately $630 million, subject to certain closing adjustments including working capital adjustments. The Acquisition is expected to close on or about June 26, 2007 or such other date as AcquisitionCo and the Sellers may agree, and will have an effective date of June 1, 2007. AcquisitionCo paid a $63 million deposit (the "AcquisitionCo Deposit") to the Sellers concurrently with the execution of the Share Purchase Agreement, $39.18 million of which was funded by POT and the balance of which was funded by Baytex in accordance with the Teaming Agreement.

On May 29, 2007, Baytex Energy, POT, AcquisitionCo and BCo entered into the Teaming Agreement. Pursuant to the Teaming Agreement, the parties agreed to complete (or cause their affiliates to complete) the Pre-Closing Transactions, to execute the Share Purchase Agreement and close the transactions contemplated thereby, and to undertake the Post-Closing Transactions, and pursuant to which the parties have outlined their respective rights, duties and obligations in connection with the foregoing including their respective obligations to fund AcquisitionCo's payment obligations under the Share Purchase Agreement. Following the completion of the Post-Closing Transactions, POT will hold the Acquired Assets, BCo will hold the Baytex Assets, and Baytex Energy will hold all of the issued and outstanding shares of BCo.

11

After giving effect to the transactions contemplated by the Share Purchase Agreement and the Teaming Agreement, POT will have acquired the Acquired Assets for approximately $391.8 million, subject to closing adjustments, and Baytex Energy will have acquired BCo from POT, which will hold the Baytex Assets, for approximately $238.2 million, subject to closing adjustments.

Benefits of the Acquisition

The key attributes of the Acquired Assets are:

Current average daily production of approximately 47 MMcfe/d (7,800 boe/d), comprised of 40 MMcf/d of working interest natural gas production, 550 bbls/d of working interest oil and natural gas liquids production and an additional 600 boe/d of royalty volumes;

Proved and probable reserves of 269.1 Bcfe (44.8 MMboe; 96% natural gas) as evaluated by Ryder Scott in the Ryder Scott Report;

Favorable transaction metrics of:

o $43,725 per flowing boe of production at June 1, 2007;

o 4.7 times annualized first quarter 2007 funds flow of $18.2 million; and

o $7.62 per proved plus probable boe ($13.85 per proved boe) based on the Ryder Scott Report, excluding $50 million for seismic and land with no reserves assigned;

At current production and based on the December 31, 2006 estimate of proved plus probable reserves set forth in the Ryder Scott Report, the Acquired Assets have a reserve life index of 15.7 years;

Estimated 2007 operating costs of $1.63 per Mcf and royalties of less than 20% are consistent with PET’s existing cost structure, resulting in minimal dilution to the Trust’s high field operating netbacks from its existing properties;

Monthly funds flow from operations of approximately $6 million at current natural gas prices of $7.00 per Mcf;

Average working interest of 71% in approximately 1,100 wells (not including 1,450 royalty interest wells), strategic infrastructure ownership and operatorship in 13 gas plants/major compressor stations, 31 booster compressor stations and working interest in 15 non-operated facilities;

Approximately 130 wellbores with behind pipe reserves assigned, presenting recompletion opportunities for low cost production additions;

Over 1,400 prospective drilling locations focused on the Viking shallow gas resource play;

Over 30 drill-ready prospects and more than 100 additional drilling prospects which require additional delineation, targeting conventional multi-zone shallow gas plays, all of which have no reserves assigned in the Ryder Scott Report;

Approximately 232,000 net acres of undeveloped land with an average 82% working interest of which 140,000 net acres are fee title freehold acreage with no Crown royalty. In addition, the Acquisition includes 78,000 net acres of undeveloped fee title freehold acreage which has been leased to third parties;

Approximately 33 square miles of 3-D seismic data and 8,750 miles of 2-D seismic data for continued future prospect definition and delineation; and

Opportunity to participate in developing plays in the Colorado shale, Mannville coal bed methane, particularly at West Holden which is in the early stages of delineation, and the Belly River coal bed methane plays that are emerging in the area.

12

For detailed information regarding the Acquired Assets, see "Information Concerning PrivateCo, AcquisitionCo, BCo and the Acquired Assets", "Financial Statements – Unaudited Proforma Consolidated Financial Statements" and "Financial Statements –Schedule of Revenue, Royalty Income, Royalties and Operating Expenses".

Closing Conditions, Deposit and Liability Arrangements under the Share Purchase Agreement

Conditions to closing of the acquisition of the PrivateCo Shares under the Share Purchase Agreement include, but are not limited to, the following: (i) the delivery by the parties of certificates in respect of the accuracy of representations and warranties and performance of covenants; (ii) receipt of all necessary approvals under the Competition Act (Canada); and (iii) no restraining order, injunction or other order or decree shall have been issued which would prevent the completion of the purchase of the PrivateCo Shares in accordance with the Share Purchase Agreement.

The Share Purchase Agreement provides for AcquisitionCo to conduct certain title reviews and a mechanism for adjusting the Purchase Price should uncured title defects exist which affect assets having an aggregate value in excess of 5% of the Purchase Price and entitles either the Sellers or AcquisitionCo to terminate the Share Purchase Agreement if such uncured title defects affect assets having an aggregate value in excess of 15% of the Purchase Price.

In accordance with the terms of the Share Purchase Agreement, if the acquisition of the PrivateCo Shares is completed, the AcquisitionCo Deposit (together with interest thereon) will be credited to the Purchase Price. If the closing of the acquisition of the PrivateCo Shares does not occur for any reason other than a default of AcquisitionCo, the AcquisitionCo Deposit (together with interest thereon) will be returned to AcquisitionCo. If closing does not occur due to a default by AcquisitionCo under the Share Purchase Agreement, the Share Purchase Agreement shall terminate and the AcquisitionCo Deposit (together with interest thereon) will be forfeited and retained by the Sellers. If the default is attributable to Baytex or PET failing to complete the financings contemplated by the Share Purchase Agreement as a result of the occurrence of a "Market Out" (as defined in the Share Purchase Agreement), the parties have agreed that the AcquisitionCo Deposit (together with interest thereon) will represent the Seller's sole remedy in respect of AcquisitionCo's failure to close. In all other cases, if closing does not occur due to a default of AcquisitionCo, forfeiture of the AcquisitionCo Deposit (together with the interest thereon) will represent only partial consideration for the Sellers liquidated damages as a result of closing not occurring and such forfeiture will be in addition to any other rights or remedies the Sellers have under or in respect of the Share Purchase Agreement as a result of AcquisitionCo's default provided that: (i) the maximum liability of AcquisitionCo for or in respect of that default will not exceed 35% of the Purchase Price (with the AcquisitionCo Deposit and any interest accrued thereon prior to forfeiture being applied to that maximum liability); and (ii) if AcquisitionCo's default was attributable to one but not both of Baytex and PET failing to provide AcquisitionCo with Baytex's or PET's share of the amount required to be paid by AcquisitionCo under the Share Purchase Agreement on closing, then the Sellers will only have a claim against AcquisitionCo and Baytex or PET, whichever is the defaulting party, for the amount in (i) above; and the liability of the non-defaulting party will be limited to the forfeiture of the AcquisitionCo Deposit and any interest accrued thereon.

In connection with the Acquisition, the Sellers have agreed to indemnify AcquisitionCo and AcquisitionCo has agreed to indemnify the Sellers and their respective affiliates, successors and permitted assigns and their directors, officers, employees, shareholders, agents, members and partners (collectively, the "Indemnified Persons") from and against all claims and losses (as defined in the Share Purchase Agreement) which may be made or brought against them, or which they may suffer or incur, directly or indirectly, as a result of, arising out of, or in connection with any breach of any covenant on the part of the Sellers or AcquisitionCo, as the case may be, under the Share Purchase Agreement or any inaccuracy or incorrectness of any representation or warranty contained in the Share Purchase Agreement, or other document or certificate furnished by the Indemnified Persons pursuant to Share Purchase Agreement including with respect to any tax matters.

In addition, AcquisitionCo has agreed to indemnify the Sellers and the applicable Indemnified Persons in respect of certain other liabilities, including those relating to AcquisitionCo's Acquisition, the Vendor Assets, certain environmental matters and the financing by AcquisitionCo, Baytex or PET of all or any part of the Purchase Price and the Sellers have agreed to indemnify AcquisitionCo and the applicable Indemnified Persons in respect of certain other liabilities, including those arising in connection with certain excluded liabilities and pre-closing transactions to be completed by PrivateCo. Certain of the Seller's indemnities are subject to a minimum threshold of $1,000,000 and 5% of the Purchase Price with an aggregate cap of 25% of the Purchase Price. Other Sellers' indemnities are not subject to any minimum amount or threshold before claims can be made. The Sellers have agreed to indemnify AcquisitionCo for certain environmental matters in certain limited circumstances. These indemnities are subject to the same thresholds and caps that apply to certain of the Sellers' indemnities.

13

Covenants, Deposit and Liability Arrangements under the Teaming Agreement

Pursuant to the Teaming Agreement, Baytex Energy, POT, AcquisitionCo and BCo have agreed to complete (or cause their affiliates to complete), as applicable, the Pre-Closing Transactions, to execute the Share Purchase Agreement and close the transactions contemplated thereby, and pursuant to which Baytex Energy and POT wish to outline their respective duties, obligations and relationship in connection with the foregoing including their respective obligations to fund AcquisitionCo's payment obligations under the Share Purchase Agreement. Although PET and Baytex Energy currently anticipate that Baytex Energy will indirectly acquire the Baytex Assets from POT through the purchase of all of the shares of BCo, PET and Baytex Energy may determine to amend the Teaming Agreement to provide for the acquisition by Baytex of the Baytex Assets in another manner acceptable to PET and Baytex.

Pursuant to the Teaming Agreement, POT and Baytex Energy have agreed to fund their pro rata share of the Purchase Price (as adjusted) payable by AcquisitionCo to the Sellers, subject to certain additional adjustments between them related to the net working capital amount. The parties will proceed to implement the Pre-Closing Transactions and Post-Closing Transactions in order to acquire their interests, directly or indirectly, in and to the Vendor Assets, subject to the following: (i) if the conditions precedent of AcquisitionCo under the Share Purchase Agreement are not satisfied, each of Baytex Energy and POT are entitled to elect whether to cause AcquisitionCo to waive the unsatisfied conditions precedent. If only one of them chooses to waive the conditions precedent, it will be entitled to complete the transactions contemplated by the Share Purchase Agreement for its own account and will lend AcquisitionCo an amount equal to the Acquisition Deposit (plus interest thereon) paid by the non-waiving party; (ii) if either of Baytex Energy or POT fail to perform any of their obligations in respect of the Pre-Closing Transactions resulting in a default by AcquisitionCo of its obligations under the Share Purchase Agreement and the Sellers terminate the Share Purchase Agreement prior to closing of the Acquisition, the party that caused the default will be liable to the non-defaulting party for the non-defaulting party's share of any damages and will reimburse the other party for its pro rata share of the deposit (plus interest thereon); and (iii) if the non-defaulting party is able to cure the default, it is entitled to complete the transactions contemplated by the Share Purchase Agreement for its own account and the defaulting party will assign its pro rata share of the deposit to the curing party and will be liable for its share of any damages.

The parties shall use all reasonable efforts to satisfy and comply with and assist in all matters related to the Closing of the Acquisition in accordance with their respective obligations under the Share Purchase Agreement. If a consent, approval, authorization, decision or determination of AcquisitionCo is required under the Share Purchase Agreement, Baytex Energy will be entitled to instruct AcquisitionCo to give such consent, approval or authorization to make such decision or determination if it relates to the Baytex Assets and POT will be entitled to instruct AcquisitionCo to give such consent or approval or to make such decision or determination if it relates to the Acquired Assets.

Under the Teaming Agreement AcquisitionCo has assigned to each of POT and Baytex Energy the rights and benefits of AcquisitionCo pertaining to the Sellers' covenants, representations and warranties and indemnity obligations and each of them is entitled to make such claims, in the name of AcquisitionCo, and to have carriage thereof, as it would be entitled to if it were a party to the Share Purchase Agreement. Certain claims are subject to minimum and maximum liability thresholds. In such event, each of Baytex Energy and POT is entitled to its pro rata share of eligible claims, above or below, as applicable, the relevant threshold, plus any amount to which the other is entitled.

POT will indemnify Baytex Energy for a number of items, including the following: (a) in relation to the Share Purchase Agreement, any liabilities of AcquisitionCo to the Sellers related to: (i) to the Acquired Assets; (ii) any assets or liabilities of the partnership or its partners that are not specifically related to the Acquired Assets, to the extent of its pro rata share; (iii) the failure of POT to fulfil its covenants and obligations under the Teaming Agreement; and (b) in relation to the Teaming Agreement, any liabilities of Baytex Energy or any of its affiliates (other than BCo) related to (i) a breach by POT of its covenants and obligations under the Teaming Agreement; (ii) a breach by POT or any of its affiliates (including BCo) of any of the representations and warranties, covenants or obligations under any of the agreements required to implement the Pre-Closing Transactions and the Post-Closing Transactions; (iii) the exercise by POT of any of the rights of AcquisitionCo under the Share Purchase Agreement prior to or following the closing of the Acquisition of the transactions contemplated by the Share Purchase Agreement, including in relation to bringing claims against the Sellers; (iv) the Acquired Assets and the operation thereof; (v) all environmental liabilities, whether past, present or future, associated with the Acquired Assets; and (vi) any assets or liabilities of the Partnership or its partners that are not specifically related to the Acquired Assets or the Baytex Assets, to the extent of its pro rata share, unless such assets or liabilities are located within a specified area in and around the location of the Acquired Assets, in which case, in respect of all such liabilities. Baytex Energy will indemnify POT in respect of the same matters, except in relation to the Acquired Assets.

14

Each of PET and Baytex will execute and deliver a guarantee of the obligations of POT and Baytex Energy, respectively, under the Teaming Agreement.

Proposed Federal Tax Changes

On May 15, 2007, Bill C-52, which includes legislative provisions to implement the October 31, 2006 Proposals, received Second Reading in the Canadian House of Commons. Under the October 31, 2006 Proposals, commencing January 1, 2011 (provided the Trust does not exceed "normal growth" before then) certain distributions from the Trust which would have otherwise been taxed as ordinary income generally will be characterized as dividends, in addition to the Trust generally being subject to the tax rates that approximate the tax rates applicable to a corporation. See "Risk Factors – Income Tax Matters" and "Certain Canadian Federal Income Tax Considerations".

INFORMATION CONCERNING PRIVATECO, ACQUISITIONCO, BCO AND THE ACQUIRED ASSETS

All information regarding PrivateCo and the Acquired Assets, contained herein, including all reserve and related information, financial information and all pro forma financial information reflecting the pro forma effects of a combination of PrivateCo and the Trust, derived in part from PrivateCo's financial information, has been derived by necessity from information provided by PrivateCo. See "Risk Factors" in this short form prospectus.

PrivateCo

PrivateCo is a foreign-controlled private oil and gas exploration and production company with operations in Central Alberta. See "Financial Statements – Financial Statements of PrivateCo".

AcquisitionCo

AcquisitionCo was incorporated on May 24, 2007 to participate in the transactions contemplated by the Share Purchase Agreement and the Teaming Agreement. AcquisitionCo has not carried on any business and prior to the closing of the Acquisition, will not undertake or carry on, any activities or business, other than activities incidental and necessary or desirable to fulfill its obligations under the Share Purchase Agreement and the Teaming Agreement.

BCo

BCo was incorporated on May 24, 2007 to participate in the transactions contemplated by the Share Purchase Agreement and the Teaming Agreement. BCo has not carried on any business and prior to the closing of the Acquisition, will not undertake or carry on, any activities or business, other than activities incidental and necessary or desirable to fulfill its obligations under the Teaming Agreement.

Disclosure of Reserves Data

As the Trust does not currently own PrivateCo or the Acquired Assets, the following information has been summarized from information obtained from PrivateCo and other third parties.

The reserves data for the Acquired Assets set forth below is based upon an evaluation by Ryder Scott dated December 31, 2006 with an effective date of December 31, 2006 and a preparation date of February 27, 2007 contained in the Ryder Scott Report. The reserves data summarizes the crude oil, NGL and natural gas reserves of the Acquired Assets and the net present values of future net revenue for these reserves using forecast prices and costs. The reserves data conforms to the requirements of NI 51-101. Additional information not required by NI 51-101 has been presented to provide additional information that the Trust believes is important to the readers of this information.

The Ryder Scott Report was prepared by Ryder Scott for PrivateCo prior to negotiations between the Sellers and the Trust commenced and, accordingly, the Trust was not given the opportunity to participate in the preparation of the Ryder Scott Report or to review the reserves data with management of the Sellers, PrivateCo or Ryder Scott in conjunction with the preparation. As a result of not participating in the preparation of the Ryder Scott Report, the Trust is unable to assess PrivateCo's procedures for

15

providing information to Ryder Scott or for assembling and reporting other information to Ryder Scott associated with PrivateCo's oil and gas activities.

The pricing used in the forecast evaluation, set forth in the reserves tables below, is based on Ryder Scott's pricing as of December 31, 2006.

All evaluations of future revenue are after deduction of royalties, development costs, production costs and well abandonment costs but before consideration of indirect costs such as administrative, overhead and other miscellaneous expenses. Other assumptions and qualifications relating to costs and other matters are included in the Ryder Scott Report. The recovery and reserves estimates on the properties described herein are estimates only. The actual oil and natural gas reserves and future production of the Acquired Assets will be greater or less than those calculated.

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 forecast prices and costs or other assumptions will be attained and variances could be material.

All future net revenues are stated prior to provision for interest, general and administrative expenses and after deduction of royalties and estimated future capital expenditures. Future net revenues have been presented on the basis that no income taxes will be paid by the Trust in the future and therefore after-tax future net revenues from the Trust's oil and gas reserves are equal to the before-tax future net revenues. Refer to "Tax Horizons".

All reserves associated with the Acquired Assets are located in Canada and, specifically, in the Province of Alberta. There are no heavy oil or non-conventional oil and gas reserves associated with the Acquired Assets. All of the Acquired Assets are onshore and are a combination of producing and exploratory assets. There are no material statutory or other mandatory relinquishments, surrenders, back-ins or changes in ownership in respect of the Acquired Assets. Estimates of reserves and future net revenue for individual properties may not reflect the same confidence level as estimates of reserves and future net revenue for all properties, due to the effects of aggregation.

Reserves Data (Forecast Prices and Costs)

The following tables provide reserves data and future net revenues associated with the Acquired Assets based on the Ryder Scott Report using forecast prices and costs.

SUMMARY OF OIL AND GAS RESERVES
AND NET PRESENT VALUES OF FUTURE NET REVENUE 
AS OF DECEMBER 31, 2006 
FORECAST PRICES AND COSTS

				Reserves
	Light And
	Medium Oil		Natural Gas		Natural Gas Liquids		Total Reserves
Reserves Category	Gross	Net	Gross	Net	Gross	Net	Gross	Net
	(Mbbl)	(Mbbl)	(Bcf)	(Bcf)	(Mbbl)	(Mbbl)	(Mboe)	(Mboe)
PROVED
Developed Producing	1,003.0	1,044.1	74.3	67.5	10.6	8.3	13,404.4	12,299.7
Developed Non-Producing	-	-	18.0	15.4	-	-	3,005.8	2,571.2
Undeveloped	236.5	196.9	40.9	36.0	-	-	7,060.5	6,191.5
TOTAL PROVED	1,239.5	1,241.0	133.3	118.9	10.6	8.3	23,470.7	21,062.4
TOTAL PROBABLE	314.3	300.7	117.2	102.3	1.8	1.6	19,845.7	17,355.8
TOTAL PROVED PLUS PROBABLE	1,553.8	1,541.6	250.5	221.2	12.4	9.9	43,316.5	38,418.2

16

		Net Present Values Of Future Net Revenue
		Before Income Taxes Discounted At (%/Year)
	0%	5%	10%	15%
Reserves Category	($000s)	($000s)	($000s)	($000s)
PROVED
Developed Producing	205,219	225,582	203,339	180,103
Developed Non-Producing	3,107	8,171	10,433	10,999
Undeveloped	116,926	80,522	55,753	38,519
TOTAL PROVED	325,252	314,275	269,525	229,621
TOTAL PROBABLE	359,839	233,587	156,889	107,284
TOTAL PROVED PLUS PROBABLE	685,091	547,862	426,414	336,905

TOTAL FUTURE NET REVENUE 
(UNDISCOUNTED) 
AS OF DECEMBER 31, 2006 
FORECAST PRICES AND COSTS

											Future Net
											Revenue
									Well		Before
					Operating				Abandonment		Income
	Revenue		Royalties		Costs		Development Costs		Costs		Taxes
Reserves Category	($000	s)	($000	s)	($000	s)	($000	s)	($000	s)	($000	s)
Proved	1,114,929		167,319		473,783		85,165		63,409		325,252
Proved Plus Probable	2,030,712		297,953		674,566		286,499		86,602		685,092
Pricing Assumptions

The following sets forth the benchmark reference prices and pricing, inflation rate and exchange rate assumptions, as at December 31, 2006 for the forecast prices and costs reflected in the Ryder Scott Report.

Forecast Prices and Costs

The forecast cost and price assumptions include increases in actual wellhead selling prices and take into account inflation with respect to future operating and capital costs. Crude oil, natural gas and NGL benchmark reference pricing, as at December 31, 2006, inflation and exchange rates utilized in the Ryder Scott Report were as follows:

SUMMARY OF PRICING AND INFLATION RATE ASSUMPTIONS AS OF DECEMBER 31, 2006 FORECAST PRICES AND COSTS

	Oil		Natural Gas
		Edmonton Par
	WTI Cushing	Price 40o API	Aeco Gas Price	Inflation Rates	Exchange Rate
Year	Oklahoma ($Us/Bbl)	($Cdn/Bbl)	($Cdn/Mmbtu)	(%/Year)	($Us/$Cdn)
Forecast
2007	61.00	69.17	6.90	2.0	0.87
2008	61.00	69.17	7.77	2.0	0.87
2009	60.00	68.02	7.48	2.0	0.87
2010	58.00	65.72	7.48	2.0	0.87
2011	57.00	64.57	7.48	2.0	0.87
2012	56.00	63.42	7.48	2.0	0.87
Thereafter			+2%/year

17

Weighted average prices realized by PrivateCo in respect of the Acquired Assets for the year ended December 31, 2006, were $6.46/Mcf for natural gas and $44.98/bbl for light crude oil and NGL. Weighted average prices received by PrivateCo in respect of the Acquired Assets for the three months ended March 31, 2007 were $6.65/Mcf for natural gas and $39.00/bbl for light crude oil and NGL.

Additional Information Relating to Reserves Data

Undeveloped Reserves

Proved and probable undeveloped reserves are attributed by Ryder Scott in accordance with standards and procedures contained in the COGE Handbook. Proved undeveloped reserves are those reserves that can be estimated with a high degree of certainty to be recoverable and are expected to be recovered from known accumulations where a significant expenditure is required to render them capable of production. Probable undeveloped reserves are those additional reserves that are less certain to be recovered than proved reserves and are expected to be recovered from known accumulations where a significant expenditure is required to render them capable of production.

In some cases, it will take longer than two years to develop these reserves. The Trust plans to develop approximately one-quarter to one thirdof the proved undeveloped reserves in the Ryder Scott Report over the next two years and a majority of the proved undeveloped reserves over the next five years. There are a number of factors that could result in delayed or cancelled development, including the following: (i) changing economic conditions (due to pricing, operating and capital expenditure fluctuations); (ii) changing technical conditions (including production anomalies, such as water breakthrough or accelerated depletion); (iii) multi-zone developments (for instance, a prospective formation completion may be delayed until the initial completion is no longer economic); (iv) a larger development program may need to be spread out over several years to optimize capital allocation and facility utilization; and (v) surface access issues (including those relating to land owners, weather conditions and regulatory approvals). For more information, see "Risk Factors".

Proved Undeveloped Reserves

Ryder Scott has assigned 7,060.5 Mboe (company gross) of proved undeveloped reserves in the Ryder Scott Report under forecast prices and costs, together with $85.5 million of associated undiscounted future capital expenditures. Proved undeveloped capital spending in the first two forecast years of the Ryder Scott Report accounts for $40.9 million, or 48%, of the total forecast. These figures increase to $66.8 million or 78%, during the first five years of the Ryder Scott Report.

The majority of the proved undeveloped reserves evaluated in the Ryder Scott Report are attributable to future development from an infill project in the Viking formation. An extensive study on infill drilling the Viking zone in east central Alberta supports 160 acre spacing development. Most of the Viking development in the Birchwavy area is currently on 640 acre well spacing.

Probable Reserves

Ryder Scott has assigned 19,845.7 Mboe (company gross) of probable reserves in the Ryder Scott Report under forecast prices and costs, together with $224.5 million of associated undiscounted future capital expenditures. Capital spending associated with the probable reserves in the first two forecast years of the Ryder Scott Report accounts for $68.1 million, or 30%, of the total forecast. These figures increase to $150.8 million or 67%, during the first five years of the Ryder Scott Report.

The majority of the probable reserves evaluated in the Ryder Scott Report are attributable to future development from an infill project in the Viking formation. An extensive study on infill drilling the Viking zone in east central Alberta supports 160 acre spacing development. Most of the Viking development in the Birchwavy area is currently on 640 acre well spacing.

Significant Factors or Uncertainties

The Ryder Scott Report contains forward-looking statements including expectations of future production and capital expenditures. Information concerning reserves may also be deemed to be forward-looking as estimates imply that the reserves described herein can be profitably produced in the future. These statements are based on current expectations that involve a number of risks and uncertainties, which could cause the actual results to differ from those anticipated. These risks include but are not limited to: the underlying risks of the oil and gas industry (i.e. operational risks in development and production; potential delays or changes in

18

plans with respect to development projects or capital expenditures; the uncertainty of reserve estimates; the uncertainty of estimates and projections relating to production, operating expenses and capital costs, and political and environmental factors); and commodity price, inflation rate and exchange rate fluctuation. Other general industry factors or uncertainties that may impact the reserves and values attributable to the properties are described elsewhere in this short form prospectus. See "Special Note Regarding Forward Looking Statements" and "Risk Factors".

Future Development Costs

The following table below sets forth development costs deducted in the estimation of the future net revenue attributable to the Acquired Assets in the Ryder Scott Report in each of the reserve categories noted below.

			Forecast Prices and Costs ($000s)
Year			Proved Reserves		Proved Plus Probable Reserves
	0	%	10	%	0	%	10	%
2007	30,315		28,904		60,417		57,605
2008	17,208		14,915		55,184		47,833
2009	16,704		13,163		42,225		33,272
2010	6,698		4,798		37,828		27,098
2011	3,294		2,145		30,620		19,040
Thereafter	10,946		5,582		60,225		30,771
Total	85,165		69,507		286,499		215,619

The future development costs are capital expenditures required in the future for the Acquired Assets to convert proved undeveloped reserves and probable reserves into proved developed producing reserves. The Trust expects to fund the development costs of the reserves associated with the Acquired Assets through a combination of internally generated funds flow, debt and equity financings. The Trust withholds approximately 40 – 50% of funds flow to assist in funding its total development activities. There can be no guarantee that funds will be available or that the Board of Directors will allocate funding to develop all of the reserves attributed in the Ryder Scott Report. Failure to develop these reserves would have a negative impact on the Trust's future funds flow.

The interest or other costs of external funding are not included in the reserves and future net revenue estimates and would reduce reserves and future net revenue to some degree depending upon the funding sources utilized. The Trust does not anticipate that interest or other funding costs would make development of any of the Acquired Assets uneconomic.

Other Oil and Gas Information

Oil and Gas Properties

The main assets to be acquired by the Trust pursuant to the Acquisition are located in the Birchwavy area of Alberta. The following is a description of these properties as at March 31, 2007.

Birchwavy Area

The Birchwavy area is located in east central Alberta approximately 70 kilometres southeast of Edmonton. The area comprises 1,083,084 gross acres (712,334 net acres) with an average 71% working interest in 704 (499.8 net) producing oil and gas wells. The average daily production for 2006 from the Birchwavy area was 7,327 boe/d plus 662 boe/d of estimated equivalent volumes from royalty revenue. Current production in Birchwavy is processed through 13 gas plants/major compressor stations, 31 booster compressor stations and working interest in 15 non-operated facilities.

Oil and Gas Wells

The following table sets forth the number and status of wells, as at March 31, 2007, in which the Trust will acquire a working interest pursuant to the Acquisition.

19

			Oil Wells			Natural Gas Wells			Other Wells (1)
	Producing		Non-Producing		Producing		Non-Producing (1)
	Gross	Net	Gross	Net	Gross	Net(3)	Gross	Net	Gross	Net
Alberta	62	51.9	-	-	642	447.9	365	259.2	-	-
Total	62	51.9	-	-	642	447.9	365	259.2	-	-

Note:

(1) "Other Wells" includes wells cased but not completed and service wells.

Properties With No Attributed Reserves

The following table sets out, for the Acquired Assets, the total land holdings as at March 31, 2007 of developed and undeveloped properties to be acquired by the Trust.

				Undeveloped
	Developed (Acres)		Properties (Acres)			Total (Acres)
	Gross	Net	Gross	Net	Gross	Net
Alberta	710,896	402,938	372,188	309,396	1,083,084	712,334
Total	710,896	402,938	372,188	309,396	1,083,084	712,334

The Trust expects that rights to explore, develop and exploit approximately 35,319 net acres of the undeveloped land holdings associated with the Acquired Assets may expire by March 31, 2008.

Forward Contracts

The Acquired Assets were not bound by any agreement (including any transportation agreement), directly or through an aggregator, under which it may be precluded from fully realizing, or may be protected from the full effect of, future market prices for oil or natural gas. In addition, the Acquired Assets' transportation obligations or commitments for future physical deliveries of oil or natural gas will not exceed the Acquired Assets' expected related future production from its proved reserves, estimated using forecast prices and costs, as disclosed herein.

Additional Information Concerning Abandonment and Reclamation Costs

The future net present values disclosed in this short form prospectus are after well abandonment costs (net of salvage values) and excluding surface reclamation costs. Well abandonments are scheduled at the end of the economic life of each well. Well abandonments were estimated by the Trust based on actual average costs. The Trust expects to incur such costs for 1,759 net wells.

The following sets forth certain information regarding the Trust's anticipated abandonment and reclamation costs for surface leases, wells, facilities and pipelines in respect of the Acquired Assets.

(a)	The Trust's abandonment and reclamation costs are estimated based on industry costs and experience.
(b)	It is expected that the Trust will incur reclamation and abandonment costs in respect of approximately 759 net currently existing wells plus approximately 1,000 wells to be drilled in the future.
(c)	The total amount of the Trust's abandonment and reclamation costs expected to be incurred, net of estimated salvage value, is $108.9 million (undiscounted) and $38.9 million (discounted at 10%).
(d)	$22.3 million (undiscounted) and $14.0 million (discounted at 10%) of abandonment and reclamation costs disclosed in paragraph (c) above were not deducted as abandonment and reclamation costs in estimating the future net revenue disclosed elsewhere in this short form prospectus.

$6.5 million (undiscounted) and $5.3 million (discounted at 10%) of abandonment and reclamation costs disclosed in paragraph (c) above are expected to be paid in the next three years by the Trust.

20

Tax Horizons

For the purposes of the disclosure in respect of tax horizons in this short form prospectus, it has been assumed that the Trust will not pay income taxes during the life of the reserves. The Trust is a taxable entity under the Tax Act and is currently taxable only on income that is not distributed or distributable to Unitholders. As a result it is expected the Trust will not incur any cash income taxes in the future under existing legislation. The October 31, 2006 Proposals apply a tax at the trust level on distributions of certain income from publicly traded mutual fund trusts at rates comparable to the combined federal and provincial corporate tax and to treat such distributions as dividends to the unitholders. Existing trusts will have a four-year transition period and, subject to not exceeding "normal growth", will not be subject to the October 31, 2006 Proposals until January 1, 2011. See "Risk Factors – Income Tax Matters".

Costs Incurred

The following table summarizes the capital expenditures (net of incentives and net of certain proceeds and including capitalized general and administrative expenses) related to the Acquired Assets for the periods indicated.

	Capital Expenditures
	($000s)
		Three Months Ended	Year Ended
		March 31, 2007	December 31, 2006
Property acquisition costs:
Proved properties (1)		-	-
Unproved properties		192	1,864
Development Costs (2)		18,032	22,015
Exploration Costs (3)		956	2,463
Total		19,180	26,342

Notes:

(1)	Acquisitions are net of disposition of properties.
(2)	Cost of drilling and completion activities for development wells drilled, facilities, plus pro-rata share of asset retirement obligations and capitalized general and administrative expenditures.
(3)	Cost of land acquired, drilling and completion costs for exploratory wells drilled, geological and geophysical costs plus pro-rata share of asset retirement obligations and capitalized general and administrative.

Exploration and Development Activities

The following table sets forth the gross and net exploratory and development wells drilled on the Acquired Assets during the periods indicated.

	Three Months Ended		Year Ended
	March 31, 2007		December 31, 2006
	Gross	Net	Gross	Net
Light and Medium Oil	5	3.5	-	-
Natural Gas	39	34.4	73	58.6
Other (1)	-	-	6	6.0
Total	44	37.9	79	64.6

Note:

(1) "Other" includes service wells, standing wells, dry holes, and wells that are rig released but the status is not yet known.

21

The Trust has plans to spend $20 to $30 million on the development of the Acquired Assets including the drilling of up to 30 wells and recompleting up to an additional 30 wells.

Production Estimates

The following table sets out the volume of production estimated for the Acquired Assets for the first year which is reflected in the estimate of future net revenue for the reserves disclosed in the tables contained under "Reserves Data (Forecast Prices and Costs)" above. These volumes exclude equivalent volumes from royalty revenue estimated at approximately 600 boe/d.

Birchwavy Total
	Light and		Natural Gas
	Medium Oil	Natural Gas	Liquids	BOE
	(Bbls/d)	(Mcf/d)	(Bbls/d)	(Boe/d)
PROVED
Developed Producing	499	34,019	5	6,173
Developed Non-Producing	-	4,668	-	778
Undeveloped	56	3,879	-	703
TOTAL PROVED	555	42,566	5	7,654
TOTAL PROBABLE	34	6,578	-	1,130
TOTAL PROVED PLUS PROBABLE	589	49,144	5	8,784

Other than the Birchwavy property, it is not anticipated that any one field will account for 20% or more of the Acquired Assets estimated total production for the year ended December 31, 2007 as disclosed above.

Production History

The following table summarizes certain information in respect of average daily production, before deduction of royalties, prices received, royalties paid, production costs and the resulting netback in respect of the Acquired Assets for the periods indicated. Current production (May 2007) from the Acquired Assets is approximately 7,800 boe/d consisting of 40.0 MMcf/d of natural gas, 550 bbl/d of crude oil and NGL and 600 bbl/d of equivalent volumes from royalty revenues. As the crude oil and NGL amounts are insignificant, the data has been presented on an Mcfe basis.

	2007	2006
	Mar. 31	Dec. 31	Sept. 30	June 30	Mar. 31
Average Daily Production
Gas (Mcfe/d)	48,245	41,276	44,489	44,347	45,802
Average Price Received
Gas ($/Mcfe)	6.64	6.28	5.73	6.05	8.05
Royalties
Gas ($/Mcfe)	1.23	1.07	0.94	1.02	1.42
Production Costs
Gas ($/Mcfe)	1.92	1.86	2.03	1.71	1.44
Netback Received
Gas ($/Mcfe)	3.49	3.35	2.76	3.32	5.19

This information excludes equivalent volumes from royalty revenue estimated at 710 boe/d for the three months ended March 31, 2007 and 662 boe/d for the year ended December 31, 2006.

The following tables indicate the average daily production from the important fields associated with the Acquired Assets for the periods indicated.

22

		Year Ended December 31, 2006
	Light/Medium		Natural
	Crude Oil	Heavy Oil	Gas	NGL	Total
	(Bbls/d)	(Bbls/d)	(Mcf/d)	(Bbls/d)	(Boe/d)
Birchwavy	554	-	40,610	5	7,327
Total	554	-	40,610	5	7,327

These volumes exclude equivalent volumes from royalty revenue estimated at 662 boe/d.

		Three Months Ended March 31, 2007
	Light/Medium		Natural
	Crude Oil	Heavy Oil	Gas	NGL	Total
	(Bbls/d)	(Bbls/d)	(Mcf/d)	(Bbls/d)	(Boe/d)
Birchwavy	547	-	44,927	6	8,041
Total	547	-	44,927	6	8,041

These volumes exclude equivalent volumes from royalty revenue estimated at 710 boe/d.

DESCRIPTION OF SECURITIES BEING DISTRIBUTED

A description of the Subscription Receipts and Debentures being distributed pursuant to this short form prospectus is contained in this short form prospectus under the headings "Details of the Offering – Subscription Receipts" and "Details of the Offering –Debentures" below, respectively. A description of the Trust Units issued pursuant to the Subscription Receipts and on the conversion, redemption or maturity of the Debentures is contained in the AIF under the heading "Description of Capital Structure".

INTEREST COVERAGE

The following interest coverages are calculated on a consolidated basis for the twelve month periods ended December 31, 2006 and March 31, 2007 and are derived from audited financial information in the case of December 31, 2006 and unaudited financial information in the case of March 31, 2007. Interest expense and funds flow are on a pro forma basis and includes interest expense on the Debentures. Funds flow coverage disclosure included herein is provided as supplemental information only.

The interest expense of the Trust for the twelve month periods ended December 31, 2006 and March 31, 2007 was $24.6 million and $27 million, respectively. Including the non-cash writedown of property, plant and equipment, the income of the Trust before interest, income tax reduction and before non-controlling interests for the twelve-month periods ended December 31, 2006 and March 31, 2007 was $7.0 million and a loss of $37.8 million, respectively, for an interest coverage deficiency of $17.6 million and $64.8 million, respectively. Funds flow (as defined above under the heading "Non-GAAP Measures") for the twelve month periods ended December 31, 2006 and March 31, 2007 was $236.7 million and $241.1 million, respectively, resulting in funds flow coverage for such periods of 9.6 times and 8.9 times, respectively.

The interest expense of the Trust for the twelve month periods ended December 31, 2006 and March 31, 2007 was $24.6 million and $27 million, respectively. The income of the Trust before the non-cash writedown of property, plant and equipment, interest, income tax reduction and before non-controlling interests for the twelve-month periods ended December 31, 2006 and March 31, 2007 was $65.7 million and $20.9 million, respectively, for an interest coverage ratio of 2.7 times and 0.8 times, respectively. The dollar amount of the excess coverage for the twelve month periods ended December 31, 2006 and March 31, 2007 would have been $41.2 million and a deficiency of $6.0 million, respectively.

The interest expense of the Trust for the twelve month periods ended December 31, 2006 and March 31, 2007 was $30.6 million and $32.6 million, respectively, after giving effect to the Acquisition. Including the non-cash writedown of property, plant and equipment, the income of the Trust before interest, income tax reduction and before non-controlling interests for the twelvemonth periods ended December 31, 2006 and March 31, 2007 was $15.5 million and a loss of $26.3 million, respectively, for an interest coverage deficiency of $15.0 million and $58.9 million, respectively. Funds flow (as defined above under the heading "Non-GAAP Measures") for the twelve month periods ended December 31, 2006 and March 31, 2007 was $285.7 million and $295.9 million, respectively, resulting in funds flow coverage for such periods of 9.3 times and 9.1 times, respectively.

23

After giving effect to the Acquisition, the income of the Trust before the non-cash writedown of property, plant and equipment, interest, income tax reduction and before non-controlling interests for the twelve-month periods ended December 31, 2006 and March 31, 2007 was $74.3 million and $32.4 million, respectively, for an interest coverage ratio of 2.4 times and 1.0 times, respectively. The dollar amount of the excess coverage for the twelve month periods ended December 31, 2006 and March 31, 2007 would have been $43.7 million and a deficiency of $0.2 million, respectively.

These interest coverage ratios reflect historical earnings and funds flow. Under GAAP, the Debentures are and will be classified as a liability with a portion allocated to equity related to the conversion feature and with the related interest expensed as incurred and financing charges amortized over the term of such Debentures. The entire amount of the annual carrying charges for the Debentures is reflected in interest expense and, accordingly, the coverage ratios described above would be unchanged had the entire amount of the Debentures been classified as a liability.

The portion of the Debentures classified as equity will be accreted to interest expense over the term of such Debentures to increase the carrying value of the liability to the face value of the Debentures.

CONSOLIDATED CAPITALIZATION

Other than as discussed below, there have been no material changes in the unit capitalization or in the indebtedness of the Trust since March 31, 2007 other than an increase in net bank debt to approximately $340 million as at June 11, 2007. After giving effect to the Offering and the Acquisition and the use of proceeds discussed herein, the Trust anticipates an increase in bank debt of approximately $50 million leaving a balance of approximately $390 million and an increase in unit capital of $237 million (20,450,000 Trust Units). If the Over-Allotment Option is exercised in full and after giving effect to the Acquisition, the Trust anticipates an increase in bank debt of approximately $14 million leaving a balance of approximately $354 million and an increase in unit capital of $274 million (23,517,500 Trust Units). See "Use of Proceeds".

PET currently has an extendible revolving credit facility (the "Current CreditFacilities") which provides for a $330 million production loan facility and a $10 million working capital facility. The Trust's lenders reconfirmed the borrowing base under the Current Credit Facilities at $310 million for a further six months as at April 30, 2007. In order to provide short-term funding for the acquisition by the Trust of certain oil and gas properties in northeast Alberta for $45.4 million on April 30, 2007, the total amount available under the Current Credit Facilities was temporarily increased to $340 million effective April 30, 2007, and are required to be reduced to $310 million by September 3, 2007 through asset sale proceeds, debt and equity proceeds and in all events through mandatory monthly decreases of $10 million commencing July 3, 2007. In addition to amounts outstanding under the Current Credit Facilities, PET has outstanding letters of credit in the amount of $6.85 million and an unsecured demand bridge credit facility in the amount of $39.2 million which was used to pay POT's portion of the AcquisitionCo Deposit. The cost of funds borrowed under the Current Credit Facilities is based on prime rate loans, LIBOR loans, US base rate loans, bankers' acceptance ("BA") rates or letters of credit at the Trust's option. In the case of BA advances, interest is subject to certain basis point or stamping fee adjustments ranging from 0% to 1.5% depending on the Trust's debt to funds flow ratio. In the case of prime rate loans and US base rate loans, interest is charged at the lenders' prime rate subject to basis point adjustments ranging from 0-50 basis points, depending on the Trust's debt to cash flow ratio. The Current Credit Facilities are secured by a fixed and floating charge demand debenture, a general security agreement and a subordination agreement from the Trust covering all existing and after acquired property of the Trust as well as unconditional full liability guarantees from all subsidiaries in respect of amounts borrowed under the Current Credit Facilities and by similar security from all such subsidiaries. The Current Credit Facilities expire on May 26, 2008, if not extended. Pursuant to the terms of the agreement governing the Current Credit Facilities, the Trust will request that the Current Credit Facilities be extended for 364 days and anticipates that this request will be granted. See "Risk Factors" in the AIF. PET has obtained a commitment from one of the lenders under the Current Credit Facilities to provide additional credit under the Current Credit Facilities such that the maximum aggregate principal amount available under the Current Credit Facilities is increased to $430 million for purposes of closing the Acquisition. This additional credit is also subject to $10 million monthly reductions commencing July 3, 2007, as described above. This increase to the Current Credit Facilities is subject to certain consents from other existing lenders, who may or may not participate therein, and to the provision of security on the Acquired Assets.

PRICE RANGE AND TRADING VOLUME OF THE TRUST UNITS

The outstanding Trust Units are listed and posted for trading on the TSX under the trading symbol "PMT.UN". The following table sets forth the closing price range and trading volume of the Trust Units as reported by the TSX for the periods indicated. See "Market for Securities" in the AIF for the trading history of the Trust Units in 2006.

24

		Price Range
	High ($)		Low ($)	Volume
2007
January	12.99		11.45	6,155,526
February	12.98		11.25	5,914,648
March	11.49		8.40	9,031,982
April	11.20		9.20	6,134,737
May	13.18		11.00	6,134,930
June 1 to 11	11.90		12.29	2,396,288

On May 28, 2007, the last trading day prior to the public announcement of the Offering, the closing price of the Trust Units on the TSX was $13.13, and on June 11, 2007, the last trading day prior to the filing of this short form prospectus, the closing price of the Trust Units on the TSX was $11.97 .

DISTRIBUTION TO UNITHOLDERS

The Trust makes monthly distributions of its available cash to Unitholders to the extent determined prudent by the Administrator. Monthly distributions are paid to Unitholders of record on the last business day of each calendar month or such other date as may be determined from time to time by the Administrator and are paid generally on the 15^th day of the following month.

The following cash distributions have been paid or declared payable by the Trust to its Unitholders for the periods indicated:

	Cash Distribution Per Unit
For the Month Ending		2007		2006		2005		2004
January(1)	$	0.20	$	0.24	$	0.22	$	0.20
February	$	0.14	$	0.24	$	0.22	$	0.16
March	$	0.14	$	0.24	$	0.22	$	0.16
April	$	0.14	$	0.24	$	0.22	$	0.16
May	$	0.14	$	0.24	$	0.22	$	0.16
June		-	$	0.24	$	0.22	$	0.18
July		-	$	0.20	$	0.22	$	0.20
August		-	$	0.20	$	0.22	$	0.20
September		-	$	0.20	$	0.24	$	0.20
October		-	$	0.20	$	0.24	$	0.20
November		-	$	0.20	$	0.24	$	0.20
December		-	$	0.20	$	0.24	$	0.20
Total	$	0.76	$	2.64	$	2.72	$	2.22

Note:

(1) The record date for the distribution was December 31 of the prior year.

The historical distributions described above may not be reflective of future distributions, which will be subject to review by the board of directors of the Administrator taking into account the prevailing circumstances at the relevant time.

See "Risk Factors".

If the Acquisition closes on or before June 30, 2007 as currently contemplated, holders of Subscription Receipts will become holders of Units on or before June 30, 2007 and will be entitled, provided they hold on June 30, 2007 the Units received pursuant to the Subscription Receipts, to receive the monthly distribution expected to be paid on or about July 15, 2007 to Unitholders of record on June 30, 2007. See "Plan of Distribution".

USE OF PROCEEDS

The net proceeds to the Trust from the sale of the Subscription Receipts and the Debentures hereunder are estimated to be $309,486,875 after deducting the fees of $15,525,625 payable to the Underwriters and the estimated expenses of the issue of $500,000. If the Over-Allotment Option is exercised in full, the net proceeds from the sale of the Subscription Receipts and Debentures hereunder are estimated to be $345,184,906.25 after deducting the fees of $17,404,468.75 payable to the Underwriters

25

and the estimated expenses of the issue of $500,000. See "Plan of Distribution". The net proceeds of the Offering will be used by the Trust to pay a portion of the purchase price of the Acquisition and the balance of the purchase price of the Acquisition will be funded from the increased Current Credit Facilities. See "Relationship Among the Trust and Certain Underwriters".

DETAILS OF THE OFFERING

Subscription Receipts

The following summary of the material attributes and characteristics of the Subscription Receipts does not include a description of all of the terms of the Subscription Receipts and reference should be made to the Subscription Receipt Agreement for a complete description of the terms of the Subscription Receipts.

At closing of the Offering, a certificate representing the Subscription Receipts will be issued in registered form to CDS or its nominee, CDS & Co., and will be deposited with CDS on the closing date of this Offering pursuant to the book-entry only system. Unless the book-entry only system is terminated, and except in certain other 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 August 31, 2007, 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 who will then issue the Units to the Receiptholders. 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 prior to the Termination Time, holders of Subscription Receipts shall be entitled to receive an amount equal to the full subscription price therefor and their pro rata entitlements to interest earned thereon between the date of the closing of the Offering and the Termination Time. 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 (the "Special Interest"). 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. If the Acquisition closes on or before June 30, 2007 as currently contemplated, holders of Subscription Receipts will become holders of Units on or before June 30, 2007 and will be entitled, provided they hold on June 30, 2007 the Units received pursuant to the Subscription Receipts, to receive the monthly distribution expected to be paid on or about July 15, 2007 to Unitholders of record on June 30, 2007.

26

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.

Debentures

The following summary of the material attributes and characteristics of the Debentures does not include a description of all of the terms of the Debentures and reference should be made to the Indenture for a complete description of the terms of the Debentures.

General

The Debentures will be issued under the Indenture. The Debentures authorized for issue immediately will be limited in aggregate principal amount to $75,000,000. The Trust may, however, from time to time, without the consent of the holders of the Debentures but subject to the limitations described herein, issue additional debentures of the same series or of a different series under the Indenture, in addition to the Debentures offered hereby. The Debentures will be issuable only in denominations of $1,000 and integral multiples thereof.

The Debentures will be dated as of the closing date of the Offering and will have an initial maturity date of August 31, 2007. If the closing of the Acquisition takes place prior to Termination Time, the maturity date will be automatically extended from the Initial Maturity Date to June 30, 2012, the Final Maturity Date. If the closing of the Acquisition does not take place by the Termination Time, the Debentures will mature on the Initial Maturity Date.

The Debentures will bear interest from the date of issue at 6.50% per annum, which will be payable semi-annually in arrears on June 30 and December 31 in each year, commencing with December 31, 2007. The first interest payment will include interest accrued from the closing of the Offering to December 31, 2007.

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

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

Conversion Privilege

The Debentures will be convertible at the holder's option into fully paid and non-assessable Units at any time after the Initial Maturity Date and prior to the close of business on the earlier of the Final Maturity Date, as applicable, and the business day immediately preceding the date specified by the Trust for redemption of the Debentures, at a conversion price of $14.20 per Unit (the "Conversion Price"), being a conversion rate of 70.4225 Units for each $1,000 principal amount of Debentures. No adjustment will be made for distributions on Units issuable upon conversion or for interest accrued on Debentures surrendered for conversion; however, holders converting their Debentures will receive accrued and unpaid interest thereon. Notwithstanding the foregoing, no Debentures may be converted during the three business days preceding June 30 and December 31 in each year, commencing December 31, 2007, as the registers of the Debenture Trustee will be closed during such periods.

27

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

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

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

Redemption and Purchase

The Debentures will not be redeemable on or before June 30, 2010. After June 30, 2010 and prior to maturity, the Debentures may be redeemed in whole or in part from time to time at the option of the Trust on not more than 60 days and not less than 30 days prior notice, at a redemption price of $1,050 per Debenture after June 30, 2010 and on or before June 30, 2011 and at a redemption price of $1,025 per Debenture after June 30, 2011 and before maturity (each a "Redemption Price"), in each case, plus accrued and unpaid interest thereon, if any.

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

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

Payment upon Redemption or Maturity

On redemption or at maturity, the Trust will repay the indebtedness represented by the Debentures by paying to the Debenture Trustee in lawful money of Canada an amount equal to the aggregate Redemption Price of the outstanding Debentures which are to be redeemed or the principal amount of the outstanding Debentures which have matured, as the case may be, together with accrued and unpaid interest thereon. Except in the case of the Initial Maturity Date, the Trust may, at its option, on not more than 60 days and not less than 40 days prior notice and subject to applicable regulatory approval, elect to satisfy its obligation to pay the Redemption Price of the Debentures which are to be redeemed or the principal amount of the Debentures which have matured, as the case may be, by issuing and delivering Units to the holders of the Debentures. Any accrued and unpaid interest thereon will be paid in cash. The number of Units to be issued will be determined by dividing the aggregate Redemption Price of the outstanding Debentures which are to be redeemed or the principal amount of the outstanding Debentures which have matured, as the case may be, by 95% of the current market price on the date fixed for redemption or the maturity date, as the case may be. No fractional Units will be issued on redemption or maturity but in lieu thereof the Trust shall satisfy fractional interests by a cash payment equal to the current market price of any fractional interest.

28

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

Subordination

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

The Indenture will provide that in the event of any insolvency or bankruptcy proceedings, or any receivership, liquidation, reorganization or other similar proceedings relative to the Trust, or to its property or assets, or in the event of any proceedings for voluntary liquidation, dissolution or other winding-up of the Trust, whether or not involving insolvency or bankruptcy, or any marshalling of the assets and liabilities of the Trust, then those holders of Senior Indebtedness, including any indebtedness to trade creditors, will receive payment in full before the holders of Debentures will be entitled to receive any payment or distribution of any kind or character, whether in cash, property or securities, which may be payable or deliverable in any such event in respect of any of the Debentures or any unpaid interest accrued thereon. The Indenture will also provide that the Trust will not make any payment, and the holders of the Debentures will not be entitled to demand, institute proceedings for the collection of, or receive any payment or benefit (including, without any limitation, by set-off, combination of accounts or realization of security or otherwise in any manner whatsoever) on account of indebtedness represented by the Debentures (a) in a manner inconsistent with the terms (as they exist on the date of issue) of the Debentures or (b) at any time when an event of default has occurred under the Senior Indebtedness and is continuing and the notice of such event of default has been given by or on behalf of the holders of Senior Indebtedness to the Trust, unless the Senior Indebtedness has been repaid in full.

The Debentures will also be effectively subordinate to claims of creditors of the Trust's subsidiaries except to the extent the Trust is a creditor of such subsidiaries ranking at least pari passu with such other creditors. Specifically, the Debentures will be subordinated in right of payment to the prior payment in full of all indebtedness under the Current Credit Facilities.

Priority over Trust Distributions

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

Change of Control of the Trust

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

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

If 90% or more of the aggregate principal amount of the Debentures outstanding on the date of the giving of notice of the Change of Control have been tendered to the Trust pursuant to the Debenture Offer, the Trust will have the right and obligation to redeem all the remaining Debentures at the Debenture Offer Price. Notice of such redemption must be given by the Trust to the

29

Debenture Trustee within 10 days following the expiry of the Debenture Offer, and promptly thereafter, by the Debenture Trustee to the holders of the Debentures not tendered pursuant to the Debenture Offer.

Interest Payment Option

The Trust may elect, from time to time and subject to regulatory approval, if required, to satisfy its obligation to pay all or any part of the interest on the Debentures (the "Interest Obligation"), on the date it is payable under the Indenture (an "Interest Payment Date"), by delivering sufficient Units to the Debenture Trustee to satisfy all or the part, as the case may be, of the Interest Obligation in accordance with the Indenture (the "Unit Interest Payment Election"). The Indenture will provide that, upon such election, the Debenture Trustee shall (a) accept delivery from the Trust of Units, (b) accept bids with respect to, and consummate sales of, such Units, each as the Trust shall direct in its absolute discretion, (c) invest the proceeds of such sales in short-term permitted government securities (as defined in the Indenture) which mature prior to the applicable Interest Payment Date, and use the proceeds received from such permitted government securities, together with any proceeds from the sale of Units not invested as aforesaid, to satisfy the Interest Obligation, and (d) perform any other action necessarily incidental thereto.

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

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

Events of Default

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

Offers for Debentures

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

Modification

The rights of the holders of the Debentures as well as any other series of debentures that may be issued under the Indenture may be modified in accordance with the terms of the Indenture. For that purpose, among others, the Indenture will contain certain provisions which will make binding on all Debenture holders resolutions passed at meetings of the holders of Debentures by votes cast thereat by holders of not less than 66% of the principal amount of the Debentures present at the meeting or represented by

30

proxy, or rendered by instruments in writing signed by the holders of not less than 66% of the principal amount of the Debentures then outstanding. In certain cases, the modification will, instead or in addition, require assent by the holders of the required percentage of Debentures of each particularly affected series.

Limitation on Issuance of Additional Debentures

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

Limitation on Non-Resident Ownership

At no time may non-residents of Canada be the beneficial owners of a majority of the Units, on a fully diluted basis, including any Units which may be issued upon conversion, redemption or maturity of the Debentures. The Debenture Trustee may require declarations as to the jurisdictions in which beneficial owners of Debentures are resident. If the Debenture Trustee becomes aware as a result of requiring such declarations as to beneficial ownership, that the beneficial owners of 49% of the Units then outstanding, on a fully diluted basis, are, or may be, non-residents or that such a situation is imminent, the Debenture Trustee may make a public announcement thereof and shall not register a transfer of Debentures to a person unless the person provides a declaration that the person is not a non-resident. If, notwithstanding the foregoing, the Debenture Trustee determines that a majority of the Units are held by non-residents, the Debenture Trustee may send a notice to non-resident holders of Debentures, chosen in inverse order to the order of acquisition or registration of the Debentures or in such manner as the Debenture Trustee may consider equitable and practicable, requiring them to sell their Debentures or a portion thereof within a specified period of not less than 60 days. If the Debenture holders receiving such notice have not sold the specified number of Debentures or provided the Debenture Trustee with satisfactory evidence that they are not non-residents within such period, the Debenture Trustee may on behalf of such Debenture holder sell such Debentures, and, in the interim, shall suspend the rights attached to such Debentures. Upon such sale the affected holders shall cease to be holders of Debentures, and their rights shall be limited to receiving the net proceeds of sale upon surrender of such Debentures. The trustee of the Trust has similar obligations in respect of the Units. More information regarding these obligations is set forth at pages 41 and 43 of the AIF, incorporated herein by reference.

Book-Entry System for Debentures

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

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

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

31

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

The Debentures will be issued to Beneficial Owners in fully registered and certificate form (the "DebentureCertificates") only if: (a) required to do so by applicable law; (b) the book-entry only system ceases to exist; (c) the Trust or CDS advises the Debenture Trustee that CDS is no longer willing or able to properly discharge its responsibilities as depositary with respect to the Debentures and the Trust is unable to locate a qualified successor; (d) the Trust, at its option, decides to terminate the book-entry only system through CDS; (e) the Trust, at its option, decides to issue Debenture Certificates to holders who acquired the Debentures pursuant to Rule 144A under the 1933 Act; or (f) after the occurrence of an Event of Default (as defined herein), provided that Participants acting on behalf of Beneficial Owners representing, in the aggregate, more than 25% of the aggregate principal amount of the Debentures then outstanding advise CDS in writing that the continuation of a book-entry only system through CDS is no longer in their best interest, and provided further that the Debenture Trustee has not waived the Event of Default in accordance with the terms of the Indenture.

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

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

PLAN OF DISTRIBUTION

Pursuant to the Underwriting Agreement, the Trust has agreed to issue and sell an aggregate of 20,450,000 Subscription Receipts and an aggregate of 75,000 Debentures to the Underwriters, and the Underwriters have severally agreed to purchase such Subscription Receipts and Debentures on June 20, 2007, or such other closing date not later than June 30, 2007 as may be agreed among the parties to the Underwriting Agreement. Delivery of the Subscription Receipts and Debentures is conditional upon payment on closing of $12.25 per Subscription Receipt by the Underwriters to the Escrow Agent and $1,000 per Debenture by the Underwriters to the Trust. The Underwriting Agreement provides that the Trust will pay the Underwriters' fee of $0.6125 per Subscription Receipt for Subscription Receipts issued and sold by the Trust and $40 per Debenture for Debentures issued and sold by the Trust, for an aggregate fee payable by the Trust of $15,525,625, in consideration for their services in connection with the Offering. The Underwriters' fee in respect of the Subscription Receipts is payable as to 50% upon the closing of the Offering and 50% upon closing of the Acquisition. If the Acquisition is not completed by August 31, 2007, the Underwriters' fee in respect of the Subscription Receipts will be reduced to the amount payable upon closing of the Offering. The terms of the Offering were determined by negotiation between the Administrator, on behalf of the Trust, and BMO Nesbitt Burns Inc. on its own behalf and on behalf the other Underwriters.

The Trust has granted to the Underwriters the Over-Allotment Option to purchase up to an additional 3,067,500 Subscription Receipts at a price of $12.25 per Subscription Receipt on the same terms and conditions of the Offering, exercisable in whole or in part from time to time, not later than the earlier of (i) the 30^th day following the closing of the Offering and (ii) the Termination Time for the purposes of covering the Underwriters' over-allocation position. If the Over-Allotment Option is exercised in full, the total Offering, Underwriters' fee and net proceeds to the Trust (before deducting expenses of the Offering) will be $363,089,375, $17,404,468.75 and $345,684,906.25, respectively. This short form prospectus also qualifies for distribution of grant of the Over-Allotment Option and the issuance of Subscription Receipts pursuant to the exercise of the Over-Allotment Option.

32

The Underwriters propose to offer the Subscription Receipts initially at the public offering price on the face page of this short form prospectus. The offering price for the Subscription Receipts was determined by negotiation by the Administrator, on behalf of the Trust, and BMO Nesbitt Burns Inc., on its own behalf and on behalf of the Underwriters. After the Underwriters have made a reasonable effort to sell all the Subscription Receipts offered by this short form prospectus at the price specified herein, the offering price may be decreased, and further changed from time to time to an amount not greater than the offering price specified herein and the compensation realized by the Underwriters will be decreased by the amount that the aggregate price paid by the purchasers for the Subscription Receipts is less than the gross proceeds paid by the Underwriters to the Trust.

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

Except in certain limited circumstances, the Subscription Receipts and the Debentures will be issued in "book-entry only" form and must be purchased or transferred through a participant in the depository service of CDS. See "Details of the Offering –Subscription Receipts" and "Details of the Offering – Book-Entry System for Debentures".

The Trust has been advised by the Underwriters that, in connection with the Offering, the Underwriters may effect transactions that stabilize or maintain the market price of the Subscription Receipts, the Units or the Debentures 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 BMO Nesbitt Burns Inc., on behalf of the Underwriters, which consent may not be unreasonably withheld. In addition, the Underwriting Agreement requires Mr. C.H. Riddell to enter into an agreement with the Underwriters whereby Mr. Riddell agrees, among other things, not to sell more than an aggregate of 400,000 Trust Units at any time within 90 days following the closing date of the Offering, without the consent of BMO Nesbitt Burns Inc., on behalf of the Underwriters, which consent may not be unreasonably withheld.

The TSX has conditionally approved the listing of the Securities. Listing is subject to the Trust fulfilling all of the requirements of the TSX on or before August 31, 2007.

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

In addition, until 40 days after the commencement of the Offering, an offer or sale of Securities within the United States by any dealer (whether or not participating in the Offering) may violate the registration requirements of the 1933 Act if such offer or sale is made otherwise than in accordance with Rule 144A under the 1933 Act.

RELATIONSHIP AMONG THE TRUST AND CERTAIN UNDERWRITERS

BMO Nesbitt Burns Inc., Scotia Capital Inc., CIBC World Markets Inc., TD Securities Inc. and National Bank Financial Inc. are direct or indirect wholly-owned subsidiaries of Canadian chartered banks which are lenders to the Trust pursuant to the Current Credit Facilities. Consequently, the Trust may be considered a connected issuer of these Underwriters within the meaning of

33

applicable Canadian securities legislation. Additionally, BMO Nesbitt Burns Inc. acted as financial advisor to the Trust in connection with the Acquisition.

As at June 11, 2007, approximately $340 million was outstanding under the Current Credit Facilities. See "Consolidated Capitalization". The Trust is in compliance with all material terms of the agreement governing the Current Credit Facilities and none of the lenders under the Current Credit Facilities have waived any breach by PET of that agreement since its execution. The Current Credit Facilities are secured by a fixed and floating charge demand debenture, a general security agreement and a subordination agreement from the Trust covering all existing and after acquired property of the Trust as well as unconditional full liability secured guarantees from all subsidiaries in respect of amounts borrowed under the Current Credit Facilities. Neither the financial position of the Trust nor the value of the security under the Current Credit Facilities has changed substantially since the indebtedness under the Current Credit Facilities was incurred. PET has obtained a commitment from one of the banks to, among other things, refinance amounts outstanding under the Current Credit Facilities and to pay a portion of the purchase price of the Acquisition. See "Use of Proceeds".

The decision to distribute the Subscription Receipts and Debentures offered hereunder and the determination of the terms of the distribution were made through negotiations primarily between the Administrator, on behalf of the Trust, and BMO Nesbitt Burns Inc. on its own behalf and on behalf of the other Underwriters. The lenders under the Current Credit Facilities did not have any involvement in such decision or determination, but have been advised of the issuance and terms thereof. As a consequence of this issuance, BMO Nesbitt Burns Inc., Scotia Capital Inc., CIBC World Markets Inc., TD Securities Inc. and National Bank Financial Inc. will receive their respective share of the Underwriters' fee.

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 Stikeman Elliott LLP on behalf of the Underwriters. As at the date hereof, the partners and associates of Burnet, Duckworth & Palmer LLP, as a group and Stikeman Elliott LLP, as a group, each own, directly or indirectly, less than 1% of the Trust Units. Reserves estimates contained herein are based upon the Ryder Scott Report prepared by Ryder Scott. As of the date hereof, the principals of Ryder Scott, as a group, beneficially own, directly or indirectly, less than 1% of the Trust Units.

CERTAIN CANADIAN FEDERAL INCOME TAX CONSIDERATIONS

In the opinion of Burnet, Duckworth & Palmer LLP and Stikeman Elliott LLP (together, "Counsel"), the following summary fairly describes the principal Canadian federal income tax considerations pursuant to the Tax Act generally applicable to a subscriber who acquires Subscription Receipts or Debentures pursuant to the Offering and who, for purposes of the Tax Act, holds the Securities as capital property and deals at arm's length with, and is not affiliated with, the Trust and the Underwriters. Generally speaking, the Securities will be considered to be capital property to a holder provided the holder does not hold the Securities in the course of carrying on a business of trading or dealing in securities and has not acquired them in one or more transactions considered to be an adventure in the nature of trade. Certain holders resident in Canada who might not otherwise be considered to hold their Debentures or Units as capital property may, in certain circumstances, be entitled to have them treated as capital property by making the irrevocable election permitted by subsection 39(4) of the Tax Act. This summary is not applicable to: a holder that is a "financial institution", or a holder in an interest which would be a "tax shelter investment", or a holder that is a "specified financial institution", all 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 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 that have been publicly announced by, or on behalf of, the federal Minister of Finance (Canada) ("Finance") prior to the date hereof, this summary does not take into account or anticipate changes in the income tax law, whether by legislative, governmental 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.

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.

34

2006 Proposed Changes

On October 31, 2006, Finance announced a Tax Fairness Plan which, in part, proposed changes to the manner in which certain flow-through entities and the distributions from such entities are taxed. On December 15, 2006, Finance released guidelines on normal growth for income trusts and other flow-through entities (the "Guidelines"). On May 15, 2007, Bill C-52 An Act to implement certain provisions of the budget tabled in Parliament on March 19, 2007 ("Bill C-52") received Second Reading in the Canadian House of Commons. Bill C-52 includes legislative provisions to implement proposals originally announced on October 31, 2006 relating to the October 31, 2006 Proposals.The summary below is based strictly on the general information found in the background paper issued by Finance at the time of the October 31, 2006 announcement (which is not legislation), the Guidelines, and Bill C-52. No assurance can be given that the final legislation implementing the October 31, 2006 Proposals will be consistent with the foregoing or that Canadian federal income tax law respecting income trusts and other flow-through entities will not be further changed in a manner which adversely affects the Trust and its Unitholders. To the extent that changes, including the October 31, 2006 Proposals, are implemented, such changes could result in the income tax considerations described below being materially different in certain respects. The October 31, 2006 Proposals, if enacted, would apply a tax on certain income earned by a "specified investment flow-through" ("SIFT") trust, as well as taxing the taxable distributions received by investors from such entities as dividends.

Pursuant to the October 31, 2006 Proposals, the Trust will constitute a SIFT trust and, as a result, the Trust and its Unitholders will be subject to the October 31, 2006 Proposals. It is assumed for the purposes of this summary that the Trust will be characterized as a SIFT trust.

Subject to the "undue expansion" issue discussed below, as currently drafted, for income trusts the units of which were publicly traded as of October 31, 2006, such as the Trust, there will be a four year transition period and the October 31, 2006 Proposals will not apply until 2011. However, the October 31, 2006 Proposals also indicate that the application date of 2011 is subject to the possible need to foreclose inappropriate new avoidance techniques. The October 31, 2006 Proposals indicate that, as an example, while there is now no intention to prevent existing income trusts from "normal growth" prior to 2011, any "undue expansion" of an existing income trust (such as might be attempted through the insertion of a disproportionately large amount of additional capital) could cause this to be revisited. The Guidelines indicate that no change will be recommended to the 2011 date in respect of any SIFT whose equity capital grows as a result of issuances of new equity (which includes trust units, debt that is convertible into trust units, and potentially other substitutes for such equity), before 2011, by an amount that does not exceed the greater of $50 million and an objective "safe harbour" amount based on a percentage of the SIFT's market capitalization as of the end of trading on October 31, 2006 (measured in terms of the value of a SIFT's issued and outstanding publicly-traded units, not including debt, options or other interests that were convertible into units of the SIFT). For the period from November 1, 2006 to the end of 2008, the Guidelines provide that a SIFT's safe harbour will be 60% of the October 31, 2006 benchmark. Management of the Trust has advised Counsel that, in the case of the Trust, the aggregate of the offering of Subscription Receipts and Debentures pursuant to this short form prospectus (including the exchange of Subscription Receipts for Units) will not exceed the applicable limit of 60% equity growth for the period extending from November 1, 2006 to December 31, 2008 and thus should not, by themselves, cause the Trust to be subject to the October 31, 2006 Proposals prior to 2011. It is therefore assumed, for the purposes of this summary, that the Trust will not be subject to the October 31, 2006 Proposals until January 1, 2011. However, under the October 31, 2006 Proposals, in the event that the Trust issues additional Units or convertible debentures (or other equity substitutes) on or before 2011, the Trust may become subject to the October 31, 2006 Proposals prior to 2011. No assurance can be provided that the October 31, 2006 Proposals will not apply to the Trust prior to 2011.

Taxation of Holders of Subscriptions Receipts Resident in Canada

No capital gain or capital loss will be realized by a holder on the issuance of a Unit pursuant to a Subscription Receipt. However, if the Acquisition is completed prior to the Termination Time, the holder of a Subscription Receipt, in addition to receiving a Unit in exchange therefor, will be entitled to receive an 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. Counsel is of the view that this additional amount must be included in the holder's income. 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.

35

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

Generally, one-half of any capital gain (a "taxable capital gain") realized by the holder will be included in the holder's income under the Tax Act for the year of disposition as a taxable capital gain and one-half of any capital loss (an "allowable capital loss") realized on a disposition of a Subscription Receipt must be deducted against taxable capital gains realized by the holder in the year of disposition. Allowable capital losses for a taxation year in excess of taxable capital gains for that year generally may be carried back and deducted in any of the three preceding taxation years or in any subsequent taxation year against taxable capital gains realized in such years, to the extent and under the circumstances described in the Tax Act.

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

Taxation of Holders of Subscriptions Receipts Not Resident in Canada

Prospective holders of Subscription Receipts who are not resident in Canada should consult their own tax advisors with respect to their particular circumstances in their country of residence.

No capital gain or capital loss will be realized by a holder on the issuance of a Unit pursuant to a Subscription Receipt. However, if the Acquisition is completed prior to the Termination Time, the holder of a Subscription Receipt, in addition to receiving a Unit in exchange therefor, will be entitled to receive an 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. Counsel is of the view that this additional amount must be included in the holder's income and will be subject to Canadian withholding tax at the rate of 25%, unless such rate is reduced under the provisions of a tax treaty between Canada and the Unitholder's jurisdiction of residence. Counsel has been advised that where a Unitholder is resident in the United States who is entitled to claim the benefit of the Canada-US Tax Convention the Trust the Trust will be withholding at the rate of 15%.

In the event the Acquisition does not close before the Termination Time or if the Acquisition is terminated at an earlier time, a holder of Subscription Receipts who is not resident or deemed to be resident in Canada will be subject to withholding tax on such holder's proportionate share of interest on the Escrowed Funds which is paid or credited to such holders at the rate of 25%, unless such rate is reduced under the provisions of a tax treaty between Canada and the holder jurisdiction of residence. A holder resident in the United States who is entitled to claim the benefit of the Canada-US Tax Convention will generally be entitled to have the rate of withholding reduced to 10% of the amount of any interest paid or credited. If and to the extent the Escrowed Funds are invested in obligations of, or guaranteed by, the Government of Canada, interest on such obligations that is paid or credited to a non-resident holder of Subscription Receipts will not be subject to Canadian tax.

A disposition or deemed disposition of Subscription Receipts will not give rise to any capital gains subject to tax under the Tax Act to a holder who is not resident or deemed to be resident in Canada provided that the Subscription Receipts are not "taxable Canadian property" of the holder for the purposes of the Tax Act. Generally, Subscription Receipts will not constitute "taxable Canadian property" to a non-resident holder at the time of the disposition or deemed disposition thereof unless (i) the holder uses or holds or is deemed to use or hold the Subscription Receipts (or the Units issuable pursuant thereto) in, or in the course of, carrying on a business in Canada, (ii) the Subscription Receipts (or the Units issuable pursuant thereto) are "designated insurance property" of the holder for purposes of the Tax Act, (iii) the holder, persons with whom the holder does not deal at arm's length (within the meaning of the Tax Act) or any combination thereof owned or has rights or interests in 25% or more of the Units at any time during the 60-month period immediately preceding the disposition, or (iv) the Trust is not a "mutual fund trust" for the purposes of the Tax Act on the date of disposition.

36

Taxation of Holders of Debentures Resident in Canada

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

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

A holder of a Debenture who exchanges the Debenture for Units pursuant to the conversion privilege will be considered to have disposed of the Debenture for proceeds of disposition equal to the aggregate of the fair market value of the Units so acquired at the time of the exchange and the amount of any cash received in lieu of any fractional Unit.

The cost to the holder of the Units so acquired will be equal to their fair market value at the time of the exchange and must be averaged with the adjusted cost base of all other Units held at that time as capital property by the holder for the purpose of calculating the adjusted cost base of each such Unit.

If the Trust redeems a Debenture prior to maturity or repays a Debenture upon maturity and the holder does not exercise the conversion privilege prior to such redemption or repayment, the holder will be considered to have disposed of the Debenture for proceeds of disposition equal to the amount received by the holder (other than the amount received as interest) on such redemption or repayment. If the holder receives Units on redemption or repayment, the holder will be considered to have received proceeds of disposition equal to the fair market value of the Units so received and the amount of any cash received in lieu of any fractional Unit. The cost to the holder of the Units so received will be equal to their fair market value at the time of the exchange and must be averaged with the adjusted cost base of all other Units held at that time as capital property by the holder for the purpose of calculating the adjusted cost base of each such Unit.

On any disposition or deemed disposition a Debenture as described above or otherwise, the holder thereof will generally realize a capital gain (or capital loss) equal to the amount by which the proceeds of disposition (adjusted as described below) are greater (or less) than the aggregate of the holder's adjusted cost base of the Debenture and any reasonable costs of the disposition. Upon such a disposition or deemed disposition of a Debenture, interest accrued thereon to the date of disposition will be included in computing the holder's income, except to the extent such amount was otherwise included in the holder's income, and will be excluded in computing the holder's proceeds of disposition of the Debenture.

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

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

Taxation of Holders of Debentures Not Resident in Canada

A holder of a Debenture who is not resident or deemed to be resident in Canada will generally be subject to Canadian withholding tax at the rate of 25% on interest paid or credited pursuant to the Debenture, unless such rate is reduced under the provisions of a tax treaty between Canada and the holder's jurisdiction of residence. A holder of a Debenture resident in the United States who is entitled to claim the benefit of the Canada-US Tax Convention will generally be entitled to have the rate of withholding reduced to 10% of the amount of any interest paid or credited. Any premium paid on a redemption or repurchase of Debentures prior to maturity will be deemed to be interest for Canadian withholding tax purposes.

37

A disposition or deemed disposition of a Debenture, whether on conversion, redemption, or otherwise, will not give rise to any capital gains subject to tax under the Tax Act to a holder who is not resident or deemed to be resident in Canada provided that (i) the holder does not hold or use and is not deemed to hold or use the Debenture in the course of carrying on business in Canada; (ii) the Debenture is not a "designated insurance property" of the holder for purposes of the Tax Act; and (iii) the Debenture does not otherwise constitute "taxable Canadian property" to the holder within the meaning of the Tax Act. Generally, a Debenture will not otherwise constitute taxable Canadian property to a non-resident holder at the time of the disposition or deemed disposition thereof unless the holder, persons with whom the holder does not deal at arm's length (within the meaning of the Tax Act) or the holder together with such persons owned 25% or more of the Units at any time during the 60-month period immediately preceding the disposition.

If a Debenture is sold or transferred by a non-resident holder to a purchaser that is resident in Canada at a time when interest has accrued and remains unpaid on the Debenture, the portion of the purchase or transfer price attributable to such accrued interest may be deemed to be interest, and there may be liability on the part of the purchaser to remit withholding tax on such deemed interest (and any other amounts deemed to be interest) under the Tax Act. The computation of the amount of interest which is deemed to have been paid on a transfer of Debentures, including a conversion, is complex, and in some circumstances unclear. Non-resident sellers or transferors of Debentures should consult their own advisors as to whether any liability for withholding obligation applies.

Status of the Trust

Based upon representations made by PEOC, in the opinion of Counsel, the Trust presently qualifies as a "mutual fund trust" as defined by the Tax Act, and this summary assumes that the Trust will continue to so qualify. Counsel is advised by PEOC that it is intended that the requirements necessary for the Trust to qualify as a mutual fund trust will continue to be satisfied so that the Trust will continue to qualify as a mutual fund trust at all times throughout its existence. In the event that the Trust were not to so qualify, the income tax considerations would in some respects be materially different from those described below.

Income of the Trust

PET is subject to taxation in each taxation year on its taxable income for that year including interest which accrues to it from POT and all amounts that accrue to it in respect of royalties, including the POT Royalty, less the portion thereof that it deducts in respect of amounts paid or payable in the year to Unitholders. An amount will be considered to be payable to a Unitholder in a taxation year if the Unitholder is entitled in that year to enforce payment of the amount. PET's taxation year ends on December 31 of each year. Any loss of PET for purposes of the Tax Act cannot be allocated to, or treated as a loss of, a Unitholder.

Costs incurred by PET on the issuance of Trust Units and Debentures, including underwriting fees, generally may be deducted by PET at the rate of 20% per year, pro-rated where PET's taxation year is less than 365 days. PET also will be entitled to deduct reasonable current expenses incurred in its ongoing operations.

Amounts paid by PET as consideration for royalty interests in respect of one or more Canadian resource properties, including the POT Royalty, in a taxation year generally will be added to its cumulative Canadian oil and gas property expense ("COGPE") account. In computing its income for a taxation year, PET may deduct from any source an amount not exceeding 10%, on a declining balance basis, of its cumulative COGPE account at the end of that year. Where, as a result of a sale of a property by POT and the extinguishment of the POT Royalty with respect thereto, proceeds of disposition become receivable by PET in a taxation year, the amount of such proceeds will be required to be deducted from the balance of PET's cumulative COGPE account otherwise determined. If, after taking into account all additions and deductions for any taxation year, the balance of PET's cumulative COGPE account is negative at the end of such taxation year, the negative balance will be included in the income of PET for such year.

Under the October 31, 2006 Proposals, on the basis that the Trust is a SIFT trust, once it becomes subject to the October 31, 2006 Proposals (which is anticipated to be, subject to any "undue expansion", deferred until January 1, 2011), the Trust will no longer be able to deduct any part of the amounts payable to Unitholders in respect of: (i) income from businesses it carries on in Canada or from its non-portfolio properties (exceeding any losses for the taxation year from businesses or non-portfolio properties); and (ii) taxable capital gains from its dispositions of non-portfolio properties (exceeding its allowable capital losses from the disposition of such properties). A deduction is permitted for dividends received by a SIFT trust where the dividends could have been deducted if the SIFT trust were a corporation. "Non-portfolio properties" include: (i) Canadian real and resource properties

38

if the total fair market value of such properties is greater than 50% of the equity value of the SIFT trust itself; (ii) a property that the SIFT trust (or a non-arm's length person or partnership) uses in the course of carrying on a business in Canada; and (iii) securities of a subject entity if the SIFT trust holds securities of the subject entity that have a fair market value greater than 10% of the subject entity's equity value or if the SIFT trust holds securities of the subject entity or its affiliates that have a total fair market value greater than 50% of the SIFT trust's equity value. A subject entity includes corporations resident in Canada, trusts resident in Canada, and Canadian resident partnerships. It is expected that the Notes, POT Royalty will be non-portfolio properties for this purpose. Income which a SIFT is unable to deduct will be taxed in the SIFT at rates of tax comparable to the combined federal and provincial corporate tax rate. For 2011, the October 31, 2006 Proposals state that the combined tax rate would be 31.5% . As currently drafted, the October 31, 2006 Proposals do not change the tax treatment of distributions that are paid as returns of capital.

Under the PET Trust Indenture, an amount equal to all of the income of PET for each year net of PET's deductions and expenses generally will be payable to its Unitholders by way of cash distributions, subject to the exceptions described below. Income also may be used to finance cash redemptions of Trust Units. Any part of the income may be payable, at the Trustee's option, in the form of Trust Units.

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

Taxation of Unitholders Resident in Canada

Income from Units

This portion of the summary is applicable to a Unitholder who, for purposes of the Tax Act and at all relevant times, is resident in Canada.

Subject to the October 31, 2006 Proposals, income of a Unitholder from the Units will be considered to be income from property for the purposes of the Tax Act. Any loss of the Trust for the purposes of the Tax Act cannot be allocated to and treated as a loss of a Unitholder, and income of a Unitholder from the Units will be considered to become income from property and not resource income (or "resource profits") for purposes of the Tax Act. A Unitholder will generally be required to include in computing income for a particular taxation year of the Unitholder the portion of the net income of the Trust for a taxation year, including taxable dividends and net realized taxable capital gains, that is paid or payable to the Unitholder in that particular taxation year, whether such amount is payable in cash or in Reinvested Units. Pursuant to the October 31, 2006 Proposals, commencing in 2011, taxable distributions from the Trust received by investors and paid from the Trust's after tax income would generally be deemed to be received as taxable dividends from a taxable Canadian corporation. Such dividends will be subject to the gross-up and dividend tax credit provisions in respect of Unitholders who are individuals. Under Proposed Amendments released June 29, 2006, the dividend tax credit applicable to certain "eligible dividends" will increase. Under the October 31, 2006 Proposals, the dividends deemed to be paid by the Trust will be deemed to be "eligible dividends" and would therefore benefit from the enhanced gross-up and dividend tax credit rules of the Tax Act.

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 and be treated as such in the hands of the Unitholder for purposes of the Tax Act. The non-taxable portion of net realized capital gains of the Trust that is paid or payable to a Unitholder in a year will not be included in computing the Unitholder's income for the year and will not reduce the adjusted cost base of the Unitholder's Units. Any other amount in excess of the net income of the Trust that is paid or payable by the Trust to a Unitholder in a year will not generally be included in the Unitholder's income for the year. However, where such an amount becomes payable to a Unitholder, other than as proceeds of disposition of a Unit, the adjusted cost base of the Units held by such Unitholder will generally be reduced by such amount.

A Unitholder that throughout the relevant taxation year is a "Canadian-controlled private corporation", as defined in the Tax Act, may be liable to pay an additional refundable tax of 6 2/3% on certain investment income, including taxable capital gains and certain income from the Trust.

39

Adjusted Cost Base of Units

The cost to a Unitholder of a Unit will generally include all amounts paid by the Unitholder for the Unit. These amounts will be required to be averaged with the adjusted cost base of all other Units held by the Unitholder at that time as capital property in order to determine the adjusted cost base of each Unit. Amounts distributed by the Trust to a Unitholder in respect of a Unit will reduce the Unitholder's adjusted cost base of the Unit to the extent that the amount distributed to the Unitholder is in excess of his portion of the net income or net capital gains of the Trust, determined under the principles discussed above. To the extent that the adjusted cost base to a holder of a Unit would otherwise be less than nil, the negative amount will be deemed to be a capital gain of the Unitholder from the disposition of the Unit in the year in which the negative amount arises and the Unitholder's adjusted cost base will be increased by the amount of such deemed gain.

Disposition of Units

An actual or deemed disposition (other than in a tax deferred transaction) of Units by a Unitholder, whether on a redemption or otherwise, will give rise to a capital gain (or capital loss) equal to the amount by which the proceeds of disposition (excluding any amount payable by the Trust which represents an amount that must otherwise be included in the Unitholder's income as described above) are greater than (or less than) the aggregate of the adjusted cost base of the Units to the Unitholder plus any reasonable costs associated with the disposition. One-half of any capital gain realized by a Unitholder on a disposition of a Unit will be included in the Unitholder's income under the Tax Act for the year of disposition as a taxable capital gain. One-half of any capital loss realized on a disposition of a Unit may be deducted against taxable capital gains realized by the Unitholder in the year of disposition, in the three preceding taxation years or in any subsequent taxation year, to the extent and under the circumstances described in the Tax Act.

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

Redemption of Units

A redemption of Units in consideration for cash or Notes (as defined in the AIF), as the case may be, will be a disposition of such Units for proceeds of disposition equal to the amount of such cash or the fair market value of such Notes, as the case may be, less any portion thereof that is considered to be a distribution out of the income of the Trust. Redeeming Unitholders will consequently realize a capital gain, or sustain a capital loss, depending upon whether such proceeds exceed, or are exceeded by, the adjusted cost base of the Units so redeemed. The receipt of Notes in substitution for Units may result in a change in the income tax characterization of distributions. Holders of Notes generally will be required to include in income interest that is received or receivable or that accrues (depending on the status of the Unitholder as an individual, corporation or trust) on the Notes. The cost to a Unitholder of any property distributed to a Unitholder by the Trust will be deemed to be equal to the fair market value of such property at the time of distribution. Unitholders should consult with their own tax advisors as to the consequences of receiving Notes on a redemption.

Taxation of Unitholders Not Resident in Canada

This portion of the summary is a summary of the tax laws of Canada only, and not the tax law of the foreign jurisdiction applicable to a Unitholder who, for the purposes of the Tax Act and at all relevant times, is not resident in Canada and is not deemed to be resident in Canada, and will not use or hold or be deemed to use or hold the Units in, or in the course of, carrying on business in Canada, and is not an insurer who carries on an insurance business in Canada and elsewhere (a "Non-Resident Holder").

Any distribution of income of the Trust to a Non-Resident will generally be subject to Canadian withholding tax at the rate of 25%, unless such rate is reduced under the provisions of a tax treaty between Canada and the Non-Resident's jurisdiction of residence. A Unitholder resident in the United States who is entitled to claim the benefit of the Canada-US Tax Convention will be entitled to have the rate of withholding reduced to 15% of the amount of any income distributed. The Trust is required to maintain a special "TCP gains balance" account to which it will add its capital gains from dispositions after March 22, 2004 of "taxable Canadian property" (as defined in the Tax Act) and from which it will deduct its capital losses from dispositions of such

40

property and the amount of all "TCP gains distributions" (as defined in the Tax Act) made by it in previous taxation years. If the Trust pays an amount to a Non-Resident, makes a designation to treat that amount as a taxable capital gain and the total of all amounts designated by the Trust in a taxation year to Non-Residents and to partnerships other than "Canadian partnerships" (as defined in the Tax Act) exceeds 5% of all amounts so designated by the Trust in a taxation year to all Unitholders, such portion of that amount as does not exceed the Non-Resident's pro-rata portion of the Trust's "TCP gains balance" account (as defined in the Tax Act) for the taxation year effectively will be subject to the same Canadian withholding tax as described above for distributions of income (other than net realized capital gains).

All other amounts distributed by the Trust to a Non-Resident other than amounts described above, where more than 50% of the fair market value of a Unit is attributable to, inter alia, real property situated in Canada or a "Canadian resource property" (as defined in the Tax Act) will be subject to a special Canadian tax of 15% of the amounts of such distributions as an income tax on the deemed capital gain. This tax will be withheld from such distributions by the Trust. A Non-Resident will not be required to report such distribution in a Canadian tax return and such distribution will not reduce the adjusted cost base of the Non-Resident's Unit. If a Non-Resident realizes a capital loss on the disposition of a Unit in a particular taxation year and files a special tax return on or before the Non-Resident's filing due date for such taxation year, the Non-Resident will have a "Canadian property mutual fund loss" (as defined in the Tax Act) equal to the lesser of such loss and the sum of all distributions previously received on such Unit that were subject to 15% tax. The Non-Resident's tax liability for such taxation year shall be computed by reducing any deemed capital gain for the taxation year by the aggregate of such loss and any unused "Canadian property mutual fund losses" (as defined in the Tax Act) from previous taxation years arising from the disposition of a Unit or a share of the capital stock of a mutual fund corporation or a unit of another mutual fund trust. In certain circumstances, the Non-Resident may be entitled to receive a refund of all or a portion of such tax. A Canadian property mutual fund loss and unused Canadian mutual fund losses generally may be carried back up to three years and forward indefinitely and deducted against similar distributions received in such years.

Pursuant to the October 31, 2006 Proposals, amounts in respect of the Trust's income payable to Non-Resident Holders that are not deductible to the Trust will be treated as a taxable dividend from a taxable Canadian corporation. Such dividends will be subject to Canadian withholding tax at a rate of 25%, unless such rate is reduced under the provisions of a convention between Canada and the Non-Resident Holder's jurisdiction of residence. A Non-Resident Holder resident in the United States who is entitled to claim the benefit of the Canada-US Tax Convention generally will be entitled to have the rate of withholding reduced to 15% of the amount of such dividend. Although the October 31, 2006 Proposals may not increase the tax payable by NonResident Holders in respect of dividends deemed to be paid by the Trust, it is expected that the imposition of tax at the Trust level under the October 31, 2006 Proposals will materially reduce the amount of cash available for distributions to Unitholders.

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

Interest paid or credited on Notes or Redemption Notes to a Non Resident Unitholder who receives such notes on a redemption of Units will be subject to Canadian withholding tax at a rate of 25%, unless such rate is reduced under the provisions of an applicable tax treaty. A Unitholder resident in the United States who is entitled to claim the benefit of the Canada-US Tax Convention generally will be entitled to have the rate of withholding reduced to 10% of the amount of such interest.

ELIGIBILITY FOR INVESTMENT

Provided the Trust qualifies as a mutual fund trust and the Securities are listed on the TSX, the Securities will be qualified investments under the Tax Act for trusts governed by registered retirement savings plans, registered retirement income funds, deferred profit sharing plans ("DPSPs") (except, in the case of the Debentures, a DPSP to which the Trust has made a contribution) and registered education savings plans (collectively, the "Plans"). If the Trust ceases to qualify as a mutual fund trust, the Securities will cease to be qualified investments for Plans. Adverse tax consequences may apply to a Plan, or an annuitant thereunder, if the Plan acquires or holds property that is not a qualified investment for the Plan.

41

Where a Plan receives Notes as a result of a redemption of Units, such Notes may not be qualified investments for the Plan under the Tax Act depending upon the circumstances at the time, and this could give rise to adverse consequences to the Plan or the annuitant thereunder. Accordingly, Plans that own Units should consult their own advisors before deciding to exercise the redemption rights thereunder.

RISK FACTORS

An investment in the Securities is subject to certain risks. Investors should carefully consider the risks described under "Risk Factors" in the AIF and the additional risk factors set forth below.

Income Tax Matters

The October 31, 2006 Proposals, as contained in Bill C-52 which has received Second Reading in the Canadian House of Commons, propose to apply a tax on publicly traded mutual fund trusts at rates of tax comparable to the combined federal and provincial corporate tax and to treat such distributions as dividends to the Unitholders. Existing trusts will have a four-year transition period and, subject to the qualification below, will not be subject to the new rules until January 1, 2011. However, assuming the October 31, 2006 Proposals are ultimately enacted in their current form as contained in Bill C-52, the implementation of such legislation would be expected to result in adverse tax consequences to the Trust and certain Unitholders (including most particularly Unitholders that are tax deferred or non-residents of Canada) and may impact cash distributions from the Trust.

In light of the foregoing, management of the Administrator believes that the October 31, 2006 Proposals have reduced and may further reduce the value of the Trust Units, which would be expected to increase the cost to the Trust of raising capital in the public capital markets. In addition management of the Administrator believes that the October 31, 2006 Proposals are expected to: (a) substantially eliminate the competitive advantage that the Trust and other Canadian energy trusts enjoy relative to their corporate peers in raising capital in a tax-efficient manner, and (b) place the Trust and other Canadian energy trusts at a competitive disadvantage relative to industry competitors, including U.S. master limited partnerships, which will continue to not be subject to entity level taxation. The October 31, 2006 Proposals are also expected to make the Trust Units less attractive as an acquisition currency. As a result, it may become more difficult for the Trust to compete effectively for acquisition opportunities. There can be no assurance that the Trust will be able to reorganize its legal and tax structure to substantially mitigate the expected impact of the October 31, 2006 Proposals.

Further, the October 31, 2006 Proposals provide that, while there is no intention to prevent "normal growth" during the transitional period, any "undue expansion" could result in the transition period being "revisited", presumably with the loss of the benefit to the Trust of that transitional period. As a result, the adverse tax consequences resulting from the October 31, 2006 Proposals could be realized sooner than January 1, 2011. On December 15, 2006, the Department of Finance issued guidelines with respect to what is meant by "normal growth" in this context, which guidelines, as amended from time to time, are incorporated by reference into the legislative provisions contained in Bill C-52. Specifically, the Department of Finance stated that "normal growth" would include equity growth within certain "safe harbour" limits, measured by reference to a SIFT's market capitalization as of the end of trading on October 31, 2006 (which would include only the market value of the SIFT's issued and outstanding publicly-traded Trust Units, and not any convertible debt, options or other interests convertible into or exchangeable for Trust Units). Those safe harbour limits are 40% for the period from November 1, 2006 to December 31, 2007, and 20% each for calendar 2008, 2009 and 2010. Moreover, these limits are cumulative, so that any unused limit for a period carries over into the subsequent period. Additional details of the Department of Finance's guidelines include the following:

(a)	new equity for these purposes includes units and debt that is convertible into units (and may include other substitutes for equity if attempts are made to develop those);
(b)	replacing debt that was outstanding as of October 31, 2006 with new equity, whether by a conversion into Trust Units of convertible debentures or otherwise, will not be considered growth for these purposes and will therefore not affect the safe harbour;
(c)	the exchange, for Trust Units, of exchangeable partnership units or exchangeable shares that were outstanding on October 31, 2006 will not be considered growth for those purposes and will therefore not affect the safe harbour where the issuance of the Trust Units is made in satisfaction of the exercise of the exchange right by a person other than the SIFT; and

42

(d)      the merger of two or more SIFTs, each of which was publicly-traded on October 31, 2006, or a reorganization of such a SIFT, will not be considered growth to the extent that there is no net addition to equity as a result of the merger or reorganization.

The Trust's market capitalization as of the close of trading on October 31, 2006, having regard only to its issued and outstanding publicly-traded Trust Units, was approximately $1.5 billion, which means the Trust's "safe harbour" equity growth amount for the period ending December 31, 2007 is approximately $600 million, and for each of calendar 2008, 2009 and 2010 is an additional approximately $300 million (in any case, not including equity (including convertible debentures) issued to replace debt that was outstanding on October 31, 2006).

While these guidelines are such that it is unlikely they alone would affect the Trust's ability to raise the capital required to maintain and grow its existing operations in the ordinary course during the transition period, they could adversely affect the cost of raising capital and the Trust's ability to undertake more significant acquisitions.

The Federal government confirmed that it intends to proceed with the implementation of the October 31, 2006 Proposals in a statement contained in materials released in conjunction with the March 19, 2007 Federal budget, and Bill C-52 has received Second Reading in the Canadian House of Commons. See "Recent Developments – Proposed Federal Tax Changes". It is not known at this time when the October 31, 2006 Proposals will be enacted by Parliament or whether the October 31, 2006 Proposals will be enacted in the form currently proposed in Bill C-52.

Possible Failure to Realize Anticipated Benefits of Acquisitions

Since October 2003, the Trust has completed a number of acquisitions and is proposing to complete the Acquisition to strengthen its position in the oil and natural gas industry and to create the opportunity to realize certain benefits including, among other things, potential cost savings. Achieving the benefits of these and future acquisitions the Trust may complete depends in part on successfully consolidating functions and integrating operations, procedures and personnel in a timely and efficient manner, as well as the Trust's and the Administrator's ability to realize the anticipated growth opportunities and synergies from combining the acquired businesses and operations with those of the Trust. The integration of acquired businesses requires the dedication of substantial management effort, time and resources which may divert management's focus and resources from other strategic opportunities and from operational matters during this process. The integration process may result in the loss of key employees and the disruption of ongoing business, customer and employee relationships that may adversely affect the Trust's ability to achieve the anticipated benefits of these and future acquisitions.

Potential Undisclosed Liabilities Associated with the Acquisition

In connection with the Acquisition, there may be liabilities that the Trust failed to discover or was unable to quantify in its due diligence, which it conducted prior to the execution of the Share Purchase Agreement and Teaming Agreement, and the Trust may not be indemnified for some or all of these liabilities. In addition, although the Sellers and PrivateCo have reviewed the disclosure in this short form prospectus relating to the Acquisition, the Acquired Assets and the terms of the Share Purchase Agreement and Teaming Agreement, they have not certified that such disclosure represents full, true and plain disclosure and that the disclosure does not contain a misrepresentation. The Sellers will have no liability to purchasers of Subscription Receipts and Debentures pursuant to this Offering if the disclosure relating to the Acquisition, the terms of the Share Purchase Agreement, Teaming Agreement or the Acquired Assets contains a misrepresentation.

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 and the Debentures will mature on the Initial Maturity Date.

43

Operational and Reserves Risks Relating to the Acquired Assets

The risk factors set forth in the 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 Acquired Assets that the Trust is acquiring pursuant to the Acquisition. In particular, the reserve and recovery information contained in the Ryder Scott Report in respect of the Acquired Assets 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. See "Information Concerning PrivateCo, AcquisitionCo, BCo and the Acquired Assets –Significant Factors or Uncertainties".

Post – Closing Default under the Teaming Agreement

The Trust and Baytex have jointly and severally guaranteed the obligations of AcquisitionCo under the Share Purchase Agreement. If AcquisitionCo fails to meet its obligations under the Share Purchase Agreement, the Trust may be liable for the payment and performance of those obligations. Although POT has received equivalent indemnities from Baytex Energy under the Teaming Agreement, which are guaranteed by Baytex, the ability of the Trust and POT to receive the benefit of such indemnities will be dependent on the financial condition of Baytex and Baytex Energy.

AcquisitionCo Default under the Share Purchase Agreement caused by Baytex Energy or POT

Pursuant to the Teaming Agreement, POT and Baytex Energy have agreed to fund their pro rata share of the Purchase Price (as adjusted) payable by AcquisitionCo to the Sellers, subject to certain additional adjustments between them related to the net working capital amount. If either of Baytex Energy or POT fail to perform any of their obligations under the Teaming Agreement resulting in a default by AcquisitionCo of its obligations under the Share Purchase Agreement and the Sellers terminate the Share Purchase Agreement prior to closing of the Acquisition, the party that caused the default will be liable to the non-defaulting party for the non-defaulting party's share of any damages and will reimburse the other party for its pro rata share of the AcquisitionCo Deposit (plus interest thereon). If the non-defaulting party is able to cure the default, it is entitled to complete the transactions contemplated by the Share Purchase Agreement for its own account and the defaulting party will assign its pro rata share of the AcquisitionCo Deposit to the curing party and will be liable for its share of any damages. As a result, if POT is the non-defaulting party, it could elect not to proceed with the Acquisition or it could proceed and acquire all of the Vendor Assets.

Seller's Limited Obligations in Respect of Claims Under the Share Purchase Agreement

The Seller's obligations in respect of claims under the Share Purchase Agreement relating to a breach of representation or warranty of the Sellers are subject to a minimum threshold of $1,000,000 per claim, provided that the aggregate amount of all such claims is at least 5% of the Purchase Price, with an aggregate cap of 25% of the Purchase Price (approximately 48% of the proceeds of the Offering). Other Sellers' obligations in respect of claims under the Share Purchase Agreement are not subject to any minimum amount or threshold before claims can be made. The Sellers have agreed to indemnify AcquisitionCo for certain environmental matters in certain limited circumstances. These indemnities are subject to the same minimum thresholds and aggregate cap that apply to the Seller's obligations relating to a breach of a representation or warranty of the Sellers. See "Recent Developments – The Acquisition – Closing Conditions, Deposit and Liability Arrangements under the Share Purchase Agreement".

Market for Securities

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

Prior Ranking Indebtedness; Absence of Covenant Protection

The Debentures will be subordinate to all Senior Indebtedness and to any indebtedness of creditors of the Trust. The Debentures will also be effectively subordinate to claims of creditors of the Trust's subsidiaries except to the extent the Trust is a creditor of such subsidiaries ranking at least pari passu with such other creditors.

44

The Indenture will not limit the ability of the Trust to incur additional debt or liabilities (including Senior Indebtedness) or to make distributions. The Indenture does not contain any provision specifically intended to protect holders of the Debentures in the event of a future leveraged transaction involving the Trust. However, the Trust Indenture, among other things, restricts the Trust's level of indebtedness, provides operating investment guidelines, mandates the making of distributions and specifies the nature of its business.

Possible Dilutive Effects on Holders of Trust Units

The Trust may determine to redeem outstanding Debentures for Trust Units or to repay outstanding principal amounts thereunder at maturity of the Debentures by issuing additional Trust Units. Accordingly, holders of Trust Units may suffer dilution. See "Details of the Offering – Debentures – Payment upon Redemption or Maturity".

MATERIAL CONTRACTS

The material contracts entered into or to be entered into by the Trust in connection with the Offering and the Acquisition are as follows:

1.	the Subscription Receipt Agreement referred to under "Details of the Offering – Subscription Receipts";
2.	the Indenture referred to under "Details of the Offering – Debentures";
3.	the Underwriting Agreement referred to under "Plan of Distribution";
4.	the Share Purchase Agreement referred to under "Recent Developments – The Acquisition"; and
5.	the Teaming Agreement referred to under "Recent Developments – The Acquisition".

Copies of each of the foregoing agreements (in draft form prior to closing in the case of the Subscription Receipt Agreement and the Indenture and in redacted form in the case of the Share Purchase Agreement) may be inspected during regular business hours at the offices of the Administrator, at 500, 700 – 2nd Street S.W., Calgary, Alberta, T2P 2W1 during the period of distribution of the Subscription Receipts and the Debentures and following the completion of distribution of the Subscription Receipts and the Debentures will be available on SEDAR at www.sedar.com.

AUDITORS, TRANSFER AGENT AND REGISTRAR

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

The auditors of the Canadian exploration & production operations of the Sellers are Deloitte & Touche LLP, Chartered Accountants, Suite 3000, 700 – 2^nd Street S.W., Calgary, Alberta T2P 0S7.

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

STATUTORY AND CONTRACTUAL RIGHTS OF RESCISSION AND STATUTORY RIGHTS OF WITHDRAWAL

Securities legislation in certain of the provinces of Canada provides purchasers with the right to withdraw from an agreement to purchase securities. This right may be exercised within two business days after receipt or deemed receipt of a prospectus and any amendment and, in the case of the Subscription Receipts, irrespective of the determination at a later date of the purchase price of the Subscription Receipts distributed. In several of the provinces, securities legislation further provides a purchaser with remedies for rescission or, in some jurisdictions, damages if the prospectus and any amendment contains a misrepresentation or is not delivered to the purchaser, provided that the remedies for rescission or damages are exercised by the purchaser within the time limit prescribed by the securities legislation of the purchaser's province. The purchaser should refer to any applicable provisions

45

of the securities legislation of the province in which the purchaser resides for the particulars of these rights or consult with a legal advisor.

Under the Subscription Receipt Agreement, each original purchaser 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.

46

AUDITORS' CONSENTS

Consent of KPMG LLP

We have read the short form prospectus of Paramount Energy Trust (the "Trust") dated June 12, 2007 relating to the qualification for distribution of 20,450,000 subscription receipts at a price of $12.25 per subscription receipt, each representing the right to receive one trust unit of the Trust, and $75,000,000 principal amount of 6.50% convertible extendible unsecured subordinated debentures of the Trust. We have complied with Canadian generally accepted standards for an auditor's involvement with offering documents.

We consent to the use, through incorporation by reference in the above mentioned short form prospectus, of our report to the unitholders of the Trust on the consolidated balance sheets of the Trust as at December 31, 2006 and 2005 and the consolidated statements of earnings (loss) and deficit and cash flows for each of the years then ended. Our report is dated March 6, 2007.

(signed) "KPMG LLP"

Chartered Accountants

Calgary, Canada
June 12, 2007

Consent of Deloitte & Touche LLP

We have read the short form prospectus of Paramount Energy Trust (the "Trust") dated June 12, 2007 relating to the qualification for distribution of 20,450,000 subscription receipts at a price of $12.25 per subscription receipt, each representing the right to receive one trust unit of the Trust, and $75,000,000 principal amount of 6.50% convertible extendible unsecured subordinated debentures 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 Dominion Resources, Inc. (the "Corporation") on the combined balance sheets of the Canadian Exploration and Production Operations of the Corporation as of December 31, 2006 and 2005 and the combined statements of income, common shareholders' equity and comprehensive income and cash flows for the years then ended. Our report is dated May 25, 2007.

We also consent to the use in the above-mentioned short form prospectus of our report to the directors of the Corporation on the schedule of revenue, royalty income, royalties and operating expenses of the Birchwavy Properties for each of the years in the two year period ended December 31, 2006. Our report is dated May 18, 2007.

(signed) "Deloitte & Touche LLP"

Chartered Accountants

Calgary, Canada
June 12, 2007

F-1

FINANCIAL STATEMENTS

UNAUDITED PROFORMA COMBINED FINANCIAL STATEMENTS

Paramount Energy Trust
Pro Forma Combined Balance Sheet 
As at March 31, 2007

		Paramount
		Energy					Pro Forma				Pro Forma
		Trust			PrivateCo		Adjustments		Notes		Combined
(Cdn$ thousands, unaudited)									(Note 3)
Assets
Current assets
Cash and cash equivalents	$	-		$	19,724	$	(7,456	)	(c)	$	12,268
Accounts receivable		45,732			44,278		(16,737	)	(c)		73,273
Future income taxes		-			3,396		(3,396	)	(e)		-
Financial instruments		8,692			300		(300	)	(b)		8,692
Other		-			8,948		(5,724	)	(b)(c)		3,224
		54,424			76,646		(33,613	)			97,457
Property, plant and equipment		720,474			621,751		(186,716	)	(c)(e)		1,155,509
Goodwill		29,129			-		-				29,129
Other assets		3,000			5,117		(5,117	)	(b)		3,000
	$	807,027		$	703,514	$	(225,446	)		$	1,285,095
Liabilities
Current Liabilities
Accounts payable and accrued liabilities	$	67,989		$	65,144	$	(24,625	)	(c)	$	108,508
Distributions payable		12,090			-		-				12,090
Financial instruments		-			7,020		(7,020	)	(b)		-
Bank and other debt		245,124			70,000		17,727		(a)(b)(c)(d)		332,851
		325,203			142,164		(13,918	)			453,449
Gas over bitumen royalty adjustments		49,459			-		-				49,459
Asset retirement obligations		112,708			44,392		(4,057	)	(e)		153,043
Convertible debentures		152,706			-		69,200		(d)		221,906
Financial instruments		1,736			-		-				1,736
Non-controlling interest		1,951			-		-				1,951
Future income taxes		-			145,719		(145,719	)	(g)		-
Other		-			11,130		(11,130	)	(b)		-
Unitholders' equity
Unitholders' capital		823,780			-		237,487		(d)		1,061,267
Common stock		-			85		(85	)	(f)		-
Other paid-in capital		-			97,141		(97,141	)	(f)		-
Equity component of
convertible debentures		4,527			-		2,800		(d)		7,327
Contributed surplus		4,904			-		-				4,904
Retained earnings (deficit)		(669,947	)		207,433		(207,433	)	(f)		(669,947	)
Accumulated other comprehensive income		-			55,450		(55,450	)	(f)		-
		163,264			360,109		(119,822	)			403,551
	$	807,027		$	703,514	$	(225,446	)		$	1,285,095

See Accompanying Notes

1

Paramount Energy Trust
Pro Forma Combined Statement of Earnings (Loss) 
Three Months Ended March 31, 2007
(unaudited)

		Paramount						West
		Energy						Central/			Pro Forma				Pro Forma
		Trust			PrivateCo			Lindbergh			Adjustments		Notes		Combined
(Cdn$ thousands except
per unit amounts)													(Note 4)
Revenue
Oil and natural gas	$	99,693		$	44,919		$	(18,543	)	$	5,402		(a)	$	131,471
Royalties		(14,687	)		-			-			(5,402	)	(a)		(20,089	)
Realized gain (loss) on
financial instruments		14,291			-			-			-				14,291
Unrealized gain (loss) on
financial instruments		(48,493	)		-			-			-				(48,493	)
Gas over bitumen revenue		875			-			-			-				875
		51,679			44,919			(18,543	)		-				78,055
Expenses
Operating		25,389			21,253			(6,318	)		(5,769	)	(a)(d)		34,555
Transportation		2,686			-			-			512		(a)		3,198
Exploration		5,155			-			-			956		(b)		6,111
General and administrative		4,754			-			-			1,303		(e)		6,057
Interest and other		3,144			(360	)		-			734		(f)		3,518
Interest on convertible debentures		3,049			-			-			1,509		(f)		4,558
Depletion, depreciation
and accretion		46,751			15,060			-			(2,302	)	(c)		59,509
		90,928			35,953			(6,318	)		(3,057	)			117,506
Earnings (loss) before
income taxes		(39,249	)		8,966			(12,225	)		3,057				(39,451	)
Current tax		-			-			-			-				-
Future income tax		-			2,880			-			(2,880	)	(g)		-
		-			2,880			-			(2,880	)			-
Net earnings (loss) before
non-controlling interest		(39,249	)		6,086			(12,225	)		5,937				(39,451	)
Non-controlling interest		(12	)		-			-			-				(12	)
Net earnings (loss)	$	(39,261	)	$	6,086		$	(12,225	)	$	5,937			$	(39,463	)
Net earnings (loss) per trust unit
(Note 4(h))
Basic	$	(0.46	)											$	(0.37	)
Diluted	$	(0.46	)											$	(0.37	)

See Accompanying Notes

2

Paramount Energy Trust
Pro Forma Combined Statement of Earnings (Loss) 
Year Ended December 31, 2006
(unaudited)

		Paramount						West
		Energy						Central/			Pro Forma				Pro Forma
		Trust			PrivateCo			Lindbergh			Adjustments		Notes		Combined
(Cdn$ thousands except
per unit amounts)													(Note 4)
Revenue
Oil and natural gas	$	401,635		$	151,758		$	(54,578	)	$	17,962		(a)	$	516,777
Royalties		(65,976	)		-			-			(17,962	)	(a)		(83,938	)
Realized gain (loss) on
financial instruments		19,211			-			-			-				19,211
Unrealized gain (loss) on
financial instruments		24,917			-			-			-				24,917
Gas over bitumen revenue		14,887			-			-			-				14,887
		394,674			151,758			(54,578	)		-				491,854
Expenses
Operating		83,973			70,828			(19,650	)		(17,248	)	(a)(d)		117,903
Transportation		11,870			-			-			2,107		(a)		13,977
Exploration		16,345			-			-			2,463		(b)		18,808
General and administrative		19,972			-			-			4,829		(e)		24,801
Interest and other		11,710			(882	)		-			3,296		(f)		14,124
Interest on convertible
debentures		10,423			-			-			6,035		(f)		16,458
Writedown of property, plant
and equipment		58,727			-			-			-				58,727
Depletion, depreciation
and accretion		199,239			54,605			-			(11,713	)	(c)		242,131
		412,259			124,551			(19,650	)		(10,231	)			506,929
Earnings (loss) before
income taxes		(17,585	)		27,207			(34,928	)		10,231				(15,075	)
Current tax		1,295			5,753			-			(5,753	)	(g)		1,295
Future income tax		-			(10,280	)		-			10,280		(g)		-
		1,295			(4,527	)		-			4,527				1,295
Net earnings (loss) before
non-controlling interest		(18,880	)		31,734			(34,928	)		5,704				(16,370	)
Non-controlling interest		30			-			-			-				30
Net earnings (loss)	$	(18,850	)	$	31,734		$	(34,928	)	$	5,704			$	(16,340	)
Net earnings (loss) per trust
unit (Note 4(h))
Basic	$	(0.22	)											$	(0.16	)
Diluted	$	(0.22	)											$	(0.16	)

See Accompanying Notes

3

PARAMOUNT ENERGY TRUST
Notes to Pro Forma Combined Financial Statements 
(unaudited, dollar amounts in Cdn$ thousands except as noted)

1.	BASIS OF PRESENTATION
	The accompanying pro forma combined financial statements (the "Pro Forma Statements") of Paramount Energy Trust ("PET" or the "Trust") have been prepared for inclusion in the short form prospectus of the Trust dated June 4, 2007. The Pro Forma Statements give effect to the proposed indirect acquisition by the Trust of certain petroleum and natural gas properties and related assets in east central Alberta by way of the indirect acquisition of all of the issued and outstanding shares (the "PrivateCo Shares") of a privately-owned oil and gas company ("PrivateCo") and certain other transactions pursuant to the Share Purchase Agreement and Teaming Agreement as described in more detail under the "Recent Developments – The Acquisition", and the subsequent sale of certain assets of PrivateCo ("West Central/Lindbergh Assets") to an unrelated third party, resulting in PET retaining PrivateCo's assets in central Alberta ("Birchwavy Assets"). The Pro Forma Statements also give effect to the current proposed offering.
	The Pro Forma Statements have been prepared from and should be read in conjunction with the unaudited interim consolidated financial statements of PET as of March 31, 2007 and for the three months then ended, and the audited consolidated financial statements of PET as at December 31, 2006 and for the year then ended.
	In the opinion of management of PET, these Pro Forma Statements include all material adjustments necessary for fair presentation in accordance with Canadian generally accepted accounting principles ("Canadian GAAP"). The accounting policies used in the preparation of the Pro Forma Statements are in accordance with those disclosed in the 2006 audited consolidated financial statements of PET, including the application of successful efforts accounting for petroleum and natural gas operations.
	The Pro Forma Statements are not necessarily indicative of the results of operations that would have occurred on a combined basis for the three months ended March 31, 2007, the year ended December 31, 2006 or for future periods.
	On May 29, 2007 PET agreed to purchase all of the issued and outstanding common shares of PrivateCo for an aggregate purchase price of $630 million plus an amount equal to the working capital balance of PrivateCo as at May 31, 2007, and to concurrently sell the West Central/Lindbergh Assets to a third party for proceeds of $238 million plus a proportionate share of the working capital balance referred to above. The effective date of the transaction is June 1, 2007, and all working capital balances arising between the effective date and the closing date of the transaction accrue to the benefit of the purchasers.

4

	On May 29, 2007, the Trust also announced that it had entered into a bought deal financing (the "Offering") agreement with a syndicate of underwriters to issue 20,450,000 subscription receipts ("Subscription Receipts") at $12.25 per Subscription Receipt and a principal amount of $75 million of Convertible Extendible Subordinated Debentures (the "Debentures"). Each Subscription Receipt entitles the holder to receive, without payment of additional consideration, one Trust Unit upon closing of the acquisition of PrivateCo. The Debentures will have a face value of $1,000, a coupon of 6.5%, have an initial maturity date of August 31, 2007 and a final maturity date of July 30, 2012 and will be convertible into Trust Units of PET at a price of $14.20 per Trust Unit. The Debentures will pay interest semi-annually on June 30 and December 31.
	The unaudited pro forma combined balance sheet as at March 31, 2007 has been prepared from the unaudited consolidated balance sheet of the Trust and the unaudited balance sheet of PrivateCo as at March 31, 2007. The unaudited pro forma combined statement of earnings (loss) for the three months ended March 31, 2007 has been prepared from the unaudited consolidated statement of earnings of the Trust for the three months ended March 31, 2007, the unaudited statement of earnings of PrivateCo for the three months ended March 31, 2007 and the unaudited statement of operating income for the West Central/Lindbergh Assets for the three months ended March 31, 2007. The unaudited pro forma combined statement of earnings (loss) for the year ended December 31, 2006 has been prepared from the audited consolidated statement of earnings of the Trust for the year ended December 31, 2006, the audited statement of earnings of PrivateCo for the year ended December 31, 2006 and the audited statement of operating income for the West Central/Lindbergh Assets for the year ended December 31, 2006.
2.	ACQUISITION OF PRIVATECO
	On May 29, 2007 PET entered into an agreement to acquire PrivateCo and to concurrently sell the West Central/Lindbergh Assets to a third party. The transaction has been accounted for using the purchase method with the allocation of the purchase price, less proceeds on disposition, as follows:

Net Assets Acquired and Liabilities Assumed
Cash and cash equivalents	$	12,268
Accounts receivable		27,541
Other current assets		3,225
Accounts payable and accrued liabilities		(40,520	)
Property, plant and equipment		435,035
Asset retirement obligations		(40,335	)
	$	397,214
Consideration
Purchase Price	$	394,314
Acquisition Costs		2,900
	$	397,214

The above represents Management's preliminary assessment of the net assets acquired and liabilities assumed. The allocation of the purchase price will be finalized after the fair values of the assets and liabilities have been definitively determined. Accordingly, the above allocation is subject to change.

5

3.	PRO FORMA COMBINED BALANCE SHEET
	The unaudited pro forma combined balance sheet gives effect to the transactions and assumptions as if they had occurred at March 31, 2007:

(a)	Acquisition of PrivateCo for cash consideration of $630.0 million plus a working capital adjustment of $4.0 million and estimated acquisition costs of $2.9 million, funded initially through an increase in bank and other debt.
(b)	Elimination of current bank debt of $70 million, financial instrument assets and liabilities, other long-term liabilities and a portion of other current assets of PrivateCo as these are not included in the assets being acquired.
(c)	Decrease in net debt, property, plant and equipment, cash and cash equivalents, accounts receivable, other current assets and accounts payable and accrued liabilities to reflect the disposition of a portion of the net assets of PrivateCo to a third party for proceeds of $238.2 million plus a working capital adjustment of $1.5 million.
(d)	Increase in Unitholders' capital of $237.5 million, increase in convertible debentures of $69.2 million, increase in equity portion of convertible debentures of $2.8 million and a corresponding decrease in bank and other debt of $309.5 million as a result of the net proceeds from the current offering.
(e)	Adjustments to property, plant and equipment and asset retirement obligations as a result of the allocation from the purchase price equation (see Note 2).
(f)	Equity of PrivateCo has been eliminated as a result of the business combination.
(g)	Future income taxes have been eliminated as the PrivateCo assets will be included in the flow- through structure of the Trust. The flow-through nature of the PET's structure may change as a result of certain proposals announced by the federal government on October 31, 2006 (the "October 31 Proposals"). Please refer to PET's disclosure on the October 31 Proposals in management's discussion and analysis for the three months ended March 31, 2007.

4.	PRO FORMA COMBINED STATEMENTS OF EARNINGS
	The unaudited pro forma combined statements of earnings for the three months ended March 31, 2007 and the year ended December 31, 2006 give effect to the proposed transactions and assumptions as if they had taken place on January 1, 2007 and January 1, 2006 respectively:
	(a)	Royalties have been reclassified from oil and natural gas revenues and transportation expenses reclassifed from operating expenses on PrivateCo's statement of earnings, to conform to the Trust's financial statement presentation.
	(b)	Geological and geophysical costs related to PrivateCo, less geological and geophysical costs associated with the West Central/Lindbergh Assets have been expensed as exploration costs pursuant to successful efforts accounting.
	(c)	Depletion, depreciation and accretion have been calculated on a combined basis incorporating the fair value of PrivateCo assets net of the sale of the West Central/Lindbergh Assets.

6

(d)	Operating costs on PrivateCo's statement of earnings have been adjusted to reflect actual operating costs excluding general and administrative expenses from the statement of operating income for the Birchwavy Assets.
(e)	General and administrative expenses of PrivateCo have been reclassified from operating costs and then estimated using a rate equal to PET's cash general and administrative expenses per unit of production for 2006.
(f)	Interest and other expense on PrivateCo's statement of earnings has been eliminated, as PrivateCo's current bank debt is not included in the assets being acquired. Interest and other expense and interest on convertible debentures have been increased as a result of the increase in bank debt due to the above noted transactions and the increase in convertible debentures related to the current offering.
(g)	Current and future income taxes have been eliminated as earnings from the PrivateCo assets will be included in the flow-through structure of the Trust. The flow-through nature of the PET's structure may change as a result of the October 31 Proposals. Please refer to PET's disclosure on the October 31 Proposals in management's discussion and analysis for the three months ended March 31, 2007.
(h)	The calculation of earnings per Trust Unit is based on the weighted average Trust Units outstanding for the period and gives effect to the issuance of the 20,450,000 Trust Units expected to be issued pursuant to the current offering.

Weighted Average Pro
Forma Trust Units	Three Months Ended	Year Ended
Outstanding	March 31, 2007	December 31, 2006
Basic	106,266,029	104,389,566
Diluted	106,266,029	104,389,566

7

5.	TRANSLATION OF FINANCIAL STATEMENTS
	The financial statements of PrivateCo were prepared in US dollars and using accounting principles generally accepted in the United States ("US GAAP"). The following schedules translate the PrivateCo financial statements from US dollar, US GAAP to Canadian dollar, Canadian GAAP.

PrivateCo Canadian Exploration and Production Operations
Combined Balance Sheet
March 31, 2007
($ thousands, unaudited)
			GAAP				Canadian			Canadian		Classification
	US GAAP		Adjustments				GAAP	Exchange		GAAP	for Pro Forma
	($US)		($US)				($US)	Rate		($CDN)		Statements
Assets								(i)
Current assets
Cash and cash equivalents	$	17,083	$	-		$	17,083	1.1546	$	19,724	$	19,724
Customer receivables		19,507		-			19,507	1.1546		22,523		44,278
Receivables from affiliates		1,395		-			1,395	1.1546		1,611		(ii)
Other receivables		17,447		-			17,447	1.1546		20,144		(ii)
Materials inventory		5,863		-			5,863	1.1546		6,769		(ii)
Derivative assets		260		-			260	1.1546		300		300
Deferred income taxes		2,941		-			2,941	1.1546		3,396		3,396
Other		7,750		-			7,750	1.1546		8,948		8,948
		72,246		-			72,246			83,415		76,646
Property, plant and equipment		533,100		(464	)		532,636	1.1546		614,982		621,751
Deferred charges		4,432		-			4,432	1.1546		5,117		5,117
	$	609,778	$	(464	)	$	609,314		$	703,514	$	703,514
Liabilities
Current Liabilities
Short-term debt	$	60,627	$	-		$	60,627	1.1546	$	70,000	$	70,000
Accounts payable		7,060		-			7,060	1.1546		8,151		65,144
Accrued interest, payroll
and taxes		2,657		(749	)		1,908	1.1546		2,204		(ii)
Derivative liabilities		6,080		-			6,080	1.1546		7,020		7,020
Other		47,453		-			47,453	1.1546		54,789		(ii)
		123,877		(749	)		123,128			142,164		142,164
Deferred income taxes		125,034		1,173			126,207	1.1546		145,719		145,719
Asset retirement obligations		38,448		-			38,448	1.1546		44,392		44,392
Other		9,640		-			9,640	1.1546		11,130		11,130
Shareholders' equity
Common stock		74		-			74	1.1546		85		85
Additional paid-in capital		84,134		-			84,134	1.1546		97,141		97,141
Retained earnings		180,546		(888	)		179,658	1.1546		207,433		207,433
Accumulated other
comprehensive income		48,025		-			48,025	1.1546		55,450		55,450
		312,779		(888	)		311,891			360,109		360,109
	$	609,778	$	(464	)	$	609,314		$	703,514	$	703,514

(i)	CDN$/US$ exchange rate at close of business on March 31, 2007.
(ii)	In order to conform with PET's presentation in the Pro Forma Statements, receivables from affiliates and other receivables are included with customer receivables, materials inventory is included with property, plant and equipment, and accrued interest, payroll and taxes and other current liabilities are included with accounts payable.

8

PrivateCo Canadian Exploration and Production Operations
Combined Statement of Income
Three Months Ended March 31, 2007
($ thousands, unaudited)
		US		GAAP		Canadian					Canadian			Classification
		GAAP		Adjustments			GAAP		Exchange		GAAP		for Pro Forma
		($US)		($US)			($US)		Rate		($CDN)			Statements
									(i)
Operating revenue
Gas and oil production	$	36,795		$	-	$	36,795		1.1716	$	43,109		$	44,919
Extracted products		1,545			-		1,545		1.1716		1,810			(ii)
Other revenue		2,611			-		2,611		1.1716		3,059			(ii)
		40,951			-		40,951				47,978			44,919
Operating expenses
Operations and maintenance		19,606			-		19,606		1.1716		22,970			21,253
Depreciation, depletion and
amortization – oil and gas		12,756			-		12,756		1.1716		14,945			15,060
Depreciation, depletion and
amortization – non-oil and gas		98			-		98		1.1716		115			(ii)
Other taxes		1,145			-		1,145		1.1716		1,342			(ii)
		33,605			-		33,605				39,372			36,313
Income from operations		7,346			-		7,346				8,606			8,606
Other income		654			-		654		1.1716		766			(ii)
Interest and related charges		(347	)		-		(347	)	1.1716		(406	)		360
		7,653			-		7,653				8,966			8,966
Income tax expense		2,458			-		2,458		1.1716		2,880			2,880
Net income	$	5,195		$	-	$	5,195			$	6,086		$	6,086

(i)	Average CDN$/US$ exchange rate for the three months ended March 31, 2007.
(ii)	In order to conform with PET's presentation in the Pro Forma Statements, extracted products revenue is included with gas and oil production revenue, other revenue and other taxes are included with operations and maintenance expense and other income is included with interest and related charges.

9

PrivateCo Canadian Exploration and Production Operations
Combined Statement of Income
Year Ended December 31, 2006
($ thousands, unaudited)
		US		GAAP				Canadian				Canadian			Classification
		GAAP		Adjustments				GAAP		Exchange		GAAP		for Pro Forma
		($US)		($US)				($US)		Rate		($CDN)			Statements
										(i)
Operating revenue
Gas and oil production	$	125,920		$	-		$	125,920		1.1341	$	142,806		$	151,758
Extracted products		7,894			-			7,894		1.1341		8,952			(ii)
Other revenue		10,652			-			10,652		1.1341		12,080			(ii)
		144,466			-			144,466				163,838			151,758
Operating expenses
Operations and maintenance		66,188			-			66,188		1.1341		75,063			70,828
Depreciation, depletion and
amortization – oil and gas		47,734			-			47,734		1.1341		54,135			54,605
Depreciation, depletion and
amortization – non-oil and gas		414			-			414		1.1341		470			(ii)
Other taxes		6,917			-			6,917		1.1341		7,845			(ii)
		121,253			-			121,253				137,513			125,433
Income from operations		23,213			-			23,213				26,325			26,325
Other income		1,894			-			1,894		1.1341		2,148			(ii)
Interest and related charges		(1,116	)		-			(1,116	)	1.1341		(1,266	)		882
		23,991			-			23,991				27,207			27,207
Income tax expense (benefit)		(1,899	)		(2,092	)		(3,991	)	1.1341		(4,527	)		(4,527	)
Net income	$	25,890		$	2,092		$	27,982			$	31,734		$	31,734

(i)	Average CDN$/US$ exchange rate for the year ended December 31, 2006.
(ii)	In order to conform with PET's presentation in the Pro Forma Statements, extracted products revenue is included with gas and oil production revenue, other revenue and other taxes are included with operations and maintenance expense and other income is included with interest and related charges.

10

Income Taxes

Differences may exist between US GAAP and Canadian GAAP in the accounting for investment tax credits. Under US GAAP, PrivateCo had recognized a deferred tax asset for tax credit carryforwards related to research and experimental development expenditures incurred prior to January 1, 2005. In 2006, PrivateCo recognized a reduction in the deferred tax asset, reflecting the utilization of the credits to reduce taxes payable. For Canadian tax purposes, PrivateCo recognizes investment tax credits as deferred credits when the expenditures are made and their realization is reasonably assured. The deferred credits are reported as a reduction to property, plant and equipment and are being amortized into income on a straight-line basis over 5-year periods.

In addition, there may be differences between U.S. GAAP and Canadian GAAP in the basis for measurement of income tax assets and liabilities. Under U.S. GAAP, income tax assets and liabilities are measured based on enacted tax rates and laws; under Canadian GAAP, income tax assets and liabilities are measured based on tax rates that are expected to apply when the assets are realized or the liabilities are settled, taking into account "substantively enacted" tax rates and laws.

Depreciation, Depletion and Amortization ("DD&A")

Under U.S. GAAP, DD&A calculated under full cost accounting is measured using reserves based on constant prices in effect at year-end, while under Canadian GAAP full cost DD&A is calculated using forecasted prices. PrivateCo had recorded adjustments to DD&A expense and accumulated depreciation, depletion and amortization to reflect this difference in accounting principles.

However, as PET follows successful efforts accounting, DD&A is recorded using reserves based on constant prices in effect at year-end, in accordance with US Financial Accounting Standard No. 19. As such, the effect of this US-Canadian GAAP difference in accounting principles, net of the related income tax effects, have been excluded from these translated financial statements.

11

FINANCIAL STATEMENTS OF PRIVATECO

Dominion Resources, Inc.
Canadian Exploration & Production Operations

Combined Financial Statements for the Years Ended December 31, 
2006 and 2005

Dominion Resources, Inc.
Canadian Exploration & Production Operations
Index
	Page
Financial Information	Number
Auditors’ Report	3
Combined Statements of Income for the years ended December 31, 2006 and 2005	4
Combined Balance Sheets at December 31, 2006 and 2005	5
Combined Statements of Common Shareholders’ Equity and Comprehensive Income at December 31, 2006
and 2005	6
Combined Statements of Cash Flows for the years ended December 31, 2006 and 2005	7
Notes to Combined Financial Statements	8
Supplementary Data	19

2

Auditors’ Report

To the Board of Directors of
Dominion Resources, Inc.

We have audited the combined balance sheets of the Canadian Exploration & Production Operations of Dominion Resources, Inc. (the “Canadian Operations”) as of December 31, 2006 and 2005 and the combined statements of income, common shareholders’ equity and comprehensive income, and cash flows for the years then ended. These financial statements are the responsibility of the Canadian Operations’ management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with auditing standards generally accepted in Canada and the United States of America. Those standards require that we plan and perform an audit to obtain reasonable assurance about 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. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, these combined financial statements present fairly, in all material respects, the financial position of the Canadian Operations as of December 31, 2006 and 2005 and the results of its operations and its cash flows for the years then ended in accordance with generally accepted accounting principles in the United States of America.

The Canadian Operations are not required to have, nor were we engaged to perform, an audit of internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Canadian Operations’ internal control over financial reporting. Accordingly, we express no such opinion.

Chartered Accountants Calgary, Canada May 25, 2007

3

Dominion Resources, Inc.
Canadian Exploration & Production Operations
Combined Statements of Income(1)
Year Ended December 31,		2006			2005
(thousands)
Operating Revenue
Gas and oil production	$	125,920		$	126,536
Extracted products		7,894			3,844
Other revenue		10,652			3,397
Total operating revenue		144,466			133,777
Operating Expenses
Operations and maintenance		66,188			48,679
Depreciation, depletion and amortization – oil and gas properties		47,734			36,848
Depreciation, depletion and amortization – non-oil and gas properties		414			252
Other taxes		6,917			3,571
Total operating expenses		121,253			89,350
Income from operations		23,213			44,427
Other income		1,894			6,143
Interest and related charges		1,116			21,567
Income before income taxes		23,991			29,003
Income tax expense (benefit)		(1,899	)		6,471
Net Income	$	25,890		$	22,532

(1)	All amounts shown in United States (U.S.) dollars.
	The accompanying notes are an integral part of our Combined Financial Statements.

4

Dominion Resources, Inc.
Canadian Exploration & Production Operations
Combined Balance Sheets(1)
At December 31,		2006			2005
(thousands)
ASSETS
Current Assets
Cash and cash equivalents	$	30,741		$	19,221
Customer receivables (less allowance for doubtful accounts of $64 at both dates)		24,812			14,806
Receivables from affiliates		1,394			1,459
Other receivables		15,825			7,824
Materials and supplies inventory		4,168			1,519
Derivative assets		2,402			167,765
Deferred income taxes		888			15,028
Other		5,288			2,186
Total current assets		85,518			229,808
Property, Plant and Equipment
Property, plant and equipment		702,726			630,450
Accumulated depreciation, depletion and amortization		(186,316	)		(141,303	)
Total property, plant and equipment, net(2)		516,410			489,147
Deferred Charges and Other Assets		2,566			373
Total assets	$	604,494		$	719,328
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current Liabilities
Short-term debt	$	72,936		$	30,095
Accrued liabilities		46,978			42,889
Accounts payable		2,006			2,758
Accrued interest, payroll and taxes		5,327			1,559
Derivative liabilities		272			207,864
Total current liabilities		127,519			285,165
Other Liabilities
Deferred income taxes		120,848			125,753
Asset retirement obligations		38,130			37,555
Other		4,406			3,099
Total other liabilities		163,384			166,407
Total liabilities		290,903			451,572
Commitments and Contingencies (see Note 11)
Common Shareholders’ Equity
Common stock, no par value, 74 shares authorized and outstanding		74			74
Additional paid-in capital		84,134			84,134
Retained earnings		175,351			149,461
Accumulated other comprehensive income		54,032			34,087
Total shareholders’ equity		313,591			267,756
Total liabilities and shareholders’ equity	$	604,494		$	719,328

(1)	All amounts shown in U.S. dollars, except shares.
(2)	At cost based on full cost method for oil and gas properties ($59,346 and $57,958 excluded from amortization at December 31, 2006 and 2005, respectively)
	The accompanying notes are an integral part of our Combined Financial Statements.

5

Dominion Resources, Inc.
Canadian Exploration & Production Operations
Combined Statements of Common Shareholders’ Equity and Comprehensive Income(1)
	Common Stock
									Accumulated
					Additional				Other
					Paid-in		Retained		Comprehensive
	Shares		Amount		Capital		Earnings		Income (Loss)			Total
(thousands)
Balance at December 31, 2004	74	$	74	$	84,134	$	126,929	$	46,152		$	257,289
Comprehensive income:
Net income							22,532					22,532
Net deferred derivative losses—hedging activities, net of
$14,595 tax benefit									(27,929	)		(27,929	)
Foreign currency translation adjustments									10,299			10,299
Amounts reclassified to net income:
Net derivative losses—hedging activities, net of $3,074
tax benefit									5,709			5,709
Foreign currency translation adjustments									(144	)		(144	)
Total comprehensive income							22,532		(12,065	)		10,467
Balance at December 31, 2005	74		74		84,134		149,461		34,087			267,756
Comprehensive income:
Net income							25,890					25,890
Net deferred derivative gains—hedging activities, net of
$9,138 tax expense									16,657			16,657
Foreign currency translation adjustments									(2,123	)		(2,123	)
Amounts reclassified to net income:
Net derivative losses—hedging activities, net of $2,882
tax benefit									5,617			5,617
Foreign currency translation adjustments									(206	)		(206	)
Total comprehensive income							25,890		19,945			45,835
Balance at December 31, 2006	74	$	74	$	84,134	$	175,351	$	54,032	(2)	$	313,591

(1)	All amounts shown in U.S. dollars, except shares.
(2)	Includes $55 million of foreign currency translation adjustments and $1 million of losses related to the effective portion of cash flow hedges.
	The accompanying notes are an integral part of our Combined Financial Statements.

6

Dominion Resources, Inc.
Canadian Exploration & Production Operations
Combined Statements of Cash Flows(1)
Year Ended December 31,		2006			2005
(thousands)
Operating Activities
Net income	$	25,890		$	22,532
Adjustments to reconcile net income to net cash from operating activities:
Depreciation, depletion and amortization		48,148			37,100
Deferred income taxes		(4,344	)		6,395
Changes in:
Accounts receivable		(17,942	)		579
Inventories		(2,649	)		787
Accounts payable		365			(16,127	)
Accrued interest, payroll and taxes		3,768			(3,361	)
Other operating assets and liabilities		(8,029	)		21,263
Net cash provided by operating activities		45,207			69,168
Investing Activities
Additions to gas and oil properties		(106,545	)		(88,669	)
Proceeds from sales of gas and oil properties		30,463			157,726
Purchases of securities		---			(196,541	)
Proceeds from sales of securities		---			194,842
Net cash provided by (used in) investing activities		(76,082	)		67,358
Financing Activities
Issuance (repayment) of short-term debt, net		42,841			30,095
Repayment of long-term debt		---			(442,728	)
Net cash provided by (used in) financing activities		42,841			(412,633	)
Effect of exchange rate change on cash		(446	)		(30,720	)
Increase (decrease) in cash and cash equivalents		11,520			(306,827	)
Cash and cash equivalents at beginning of year		19,221			326,048
Cash and cash equivalents at end of year	$	30,741		$	19,221
Supplemental Cash Flow Information:
Cash paid during the year for(2):
Interest and related charges, excluding capitalized amounts	$	1,116		$	11,441

(1)	All amounts shown in U.S. dollars.
(2)	Cash paid for income taxes was not material for the years ended December 31, 2006 and 2005.
	The accompanying notes are an integral part of our Combined Financial Statements.

7

Dominion Resources, Inc.
Canadian Exploration & Production Operations

Notes to the Combined Financial Statements Note 1. Nature of Operations

The Canadian Exploration and Production (E&P) operations of Dominion Resources, Inc. (Dominion) include natural gas and oil exploration, development and production operations.

The terms “Company,” “we,” “our” and “us” are used throughout this report and, depending on the context of their use, may represent one or more of Dominion’s Canadian E&P legal entities or the entirety of Dominion’s Canadian E&P legal entities and their consolidated subsidiaries.

Note 2. Significant Accounting Policies General

We make certain estimates and assumptions in preparing our Combined Financial Statements in accordance with accounting principles generally accepted in the United States of America (U.S.) (GAAP). These estimates and assumptions affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses for the periods presented. Actual results may differ from those estimates.

Our Combined Financial Statements and the accompanying notes are presented in U.S. dollars, except certain disclosures related to credit agreements and litigation which are presented in Canadian dollars ($CAD), and include the accounts of Dominion Energy Canada Limited (DECL), Dominion Canada Finance Company (DCFC), Domcan NS1 ULC (Domcan) and their subsidiaries, all of which are under common control and ownership.

All significant intercompany profits, accounts, and transactions have been eliminated in the combination, except applicable equity transactions and accounts.

Operating Revenue

The primary types of sales and service activities reported as operating revenue include:

• Gas and oil production revenue is recognized based on actual volumes of gas and oil sold to purchasers. Sales require delivery of the product to the purchaser, passage of title and probability of collection of purchaser amounts owed. Gas and oil production revenue includes sales of Company produced natural gas, oil and condensate. Gas and oil production revenue is reported net of royalties;

• Extracted products revenue is recognized based on actual volumes of natural gas liquids sold to purchasers. Sales require delivery of the product to the purchaser, passage of title and probability of collection of purchaser amounts owed.
  Extracted products revenue is reported net of royalties; and

• Other revenue consists primarily of miscellaneous service revenue from gas and oil processing and handling, as well as buy/sell arrangements associated with volumes transported on the Alliance pipeline.

Income Taxes

Deferred income tax assets and liabilities are provided, representing future effects on income taxes for temporary differences between the bases of assets and liabilities for financial reporting and tax purposes. We establish a valuation allowance when it is more likely than not that all or a portion of a deferred tax asset will not be realized.

Cash and Cash Equivalents

Current banking arrangements generally do not require checks to be funded until actually presented for payment. At December 31, 2006 and 2005, accounts payable included $3.6 million and $1.5 million, respectively, of checks outstanding but not yet presented for payment. For purposes of our Combined Statements of Cash Flows, we consider cash and cash equivalents to include cash on hand, cash in banks and temporary investments purchased with a remaining maturity of three months or less.

Gas Imbalances

Natural gas imbalances occur when the actual amount of natural gas delivered from or received by a pipeline system or storage facility differs from the contractual amount of natural gas delivered or received. We value these imbalances due to or from shippers and operators at an appropriate sales price at period-end.

8

Dominion Resources, Inc.
Canadian Exploration & Production Operations

Notes to the Combined Financial Statements, Continued

Derivative Instruments

We use derivative instruments such as futures, swaps, forwards and options to manage the commodity and financial market risks of our business operations.

Statement of Financial Accounting Standards (SFAS) No. 133, Accounting for Derivative Instruments and Hedging Activities, requires all derivatives, except those for which an exception applies, to be reported on our Combined Balance Sheets at fair value. Derivative contracts representing unrealized gain positions and purchased options are reported as derivative assets. Derivative contracts representing unrealized losses and options sold are reported as derivative liabilities. One of the exceptions to fair value accounting—normal purchases and normal sales—may be elected when the contract satisfies certain criteria, including a requirement that physical delivery of the underlying commodity is probable. Expenses and revenues resulting from deliveries under normal purchase contracts and normal sales contracts, respectively, are included in earnings at the time of contract performance.

We also hold certain derivative instruments that are not held for trading purposes and are not designated as hedges for accounting purposes. However, to the extent we do not hold offsetting positions for such derivatives, we believe these instruments represent economic hedges that mitigate exposure to fluctuations in commodity prices and interest rates.

Statement of Income Presentation:

• Derivatives Held for Trading Purposes: All changes in fair value, including amounts realized upon settlement, are presented in other revenues on a net basis.

• Financially-Settled Derivatives—Not Held for Trading Purposes and Not Designated as Hedging Instruments: All unrealized changes in fair value and settlements are presented in operations and maintenance expense on a net basis.

• Physically-Settled Derivatives—Not Held for Trading Purposes and Not Designated as Hedging Instruments: All unrealized changes in fair value and settlements for physical derivative sales contracts are presented in revenues, while all unrealized changes in fair value and settlements for physical derivative purchase contracts are presented in expenses.

We recognize revenue or expense from all non-derivative energy-related contracts on a gross basis at the time of contract performance, settlement or termination.

Derivative Instruments Designated as Cash Flow Hedging Instruments

We designate a substantial portion of our derivative instruments as cash flow hedges for accounting purposes. The cash flow hedging strategies are primarily used to hedge the variable price risk associated with the sale of natural gas and oil. For all derivatives designated as cash flow hedges, the relationship between the hedging instrument and the hedged item is formally documented, as well as the risk management objective and strategy for using the hedging instrument. For transactions in which we are hedging the variability of cash flows, changes in the fair value of the derivative are reported in accumulated other comprehensive income (AOCI), to the extent effective at offsetting changes in the hedged item, until earnings are affected by the hedged item. We assess whether the hedging relationship between the derivative and the hedged item is highly effective at offsetting changes in cash flows, both at the inception of the hedging relationship and on an ongoing basis. Any change in fair value of the derivative that is not effective at offsetting changes in the cash flows of the hedged item is recognized currently in earnings. Also, we may elect to exclude certain gains or losses on hedging instruments from the measurement of hedge effectiveness, such as gains or losses attributable to changes in the time value of options, thus requiring that such changes be recorded currently in earnings. We discontinue hedge accounting prospectively for derivatives that have ceased to be highly effective hedges or for which the forecasted transaction is determined to be no longer probable. We reclassify any derivative gains or losses reported in AOCI to earnings when the forecasted item is included in earnings, if it should occur, or earlier, if it becomes probable that the forecasted transaction will not occur.

Statement of Income Presentation—Gains and losses on derivatives designated as hedges, when recognized, are included in operating revenue in our Combined Statements of Income. Specific line item classification is determined based on the nature of the risk underlying individual hedge strategies. The portion of gains or losses on hedging instruments determined to be ineffective and the portion of gains or losses on hedging instruments excluded from the measurement of the hedging relationship’s effectiveness, such as gains or losses attributable to changes in the time value of options, are included in operations and maintenance expense.

9

Dominion Resources, Inc.
Canadian Exploration & Production Operations

Notes to the Combined Financial Statements, Continued

Valuation Methods

Fair value is based on actively-quoted market prices, if available. In the absence of actively-quoted market prices, we seek indicative price information from external sources, including broker quotes and industry publications. If pricing information from external sources is not available, we must estimate prices based on available historical and near-term future price information and certain statistical methods, including regression analysis.

For options and contracts with option-like characteristics where pricing information is not available from external sources, we generally use a modified Black-Scholes Model that considers time value, the volatility of the underlying commodities and other relevant assumptions when estimating fair value. We use other option models under special circumstances, including a Spread Approximation Model, when contracts include different commodities or commodity locations and a Swing Option Model, when contracts allow either the buyer or seller the ability to exercise within a range of quantities. For contracts with unique characteristics, we estimate fair value using a discounted cash flow approach deemed appropriate in the circumstances and applied consistently from period to period. If pricing information is not available from external sources, judgment is required to develop the estimates of fair value. For individual contracts, the use of different valuation models or assumptions could have a material effect on the contract’s estimated fair value.

Foreign Currency Translation

Our functional currency is the Canadian dollar. Assets and liabilities are translated into U.S. dollars using current exchange rates in effect at the balance sheet date. Revenues and expenses are translated using average monthly exchange rates. The resulting translation adjustments are recorded as accumulated other comprehensive income (loss) in the accompanying Combined Statements of Common Shareholders’ Equity and Comprehensive Income, net of related income taxes.

Property, Plant and Equipment

Property, plant and equipment, including additions and replacements, is recorded at original cost, including labor, materials, asset retirement costs and other direct and indirect costs including capitalized interest. The cost of repairs and maintenance, including minor additions and replacements, is charged to expense as incurred. In 2006 and 2005, we capitalized interest costs of $2.2 million and $2.4 million, respectively.

We follow the full cost method of accounting for gas and oil exploration and production activities prescribed by the U.S. Securities and Exchange Commission (SEC). Under the full cost method, all direct costs of property acquisition, exploration and development activities are capitalized. These capitalized costs are subject to a quarterly ceiling test. Under the ceiling test, amounts capitalized are limited to the present value of estimated future net revenues to be derived from the anticipated production of proved gas and oil reserves, assuming period-end pricing adjusted for cash flow hedges in place. If net capitalized costs exceed the ceiling test at the end of any quarterly period, then a permanent write-down of the assets must be recognized in that period. Approximately 7% of our anticipated production is hedged by qualifying cash flow hedges, for which hedge-adjusted prices were used to calculate estimated future net revenue. Whether period-end market prices or hedge-adjusted prices were used for the portion of production that is hedged, there was no ceiling test impairment as of December 31, 2006.

Depletion of gas and oil producing properties is computed using the units-of-production method. Under the full cost method, the depletable base of costs subject to depletion also includes estimated future costs to be incurred in developing proved gas and oil reserves, as well as capitalized asset retirement costs, net of projected salvage values. The costs of investments in unproved properties, including associated exploration-related costs, are initially excluded from the depletable base. Until the properties are evaluated, a ratable portion of the capitalized costs is periodically reclassified to the depletable base, determined on a property-by-property basis, over terms of underlying leases. Once a property has been evaluated, any remaining capitalized costs are then transferred to the depletable base. In addition, gains or losses on the sale or other disposition of gas and oil properties are not recognized, unless the gain or loss would significantly alter the relationship between capitalized costs and proved reserves of natural gas and oil attributable to a cost center. In 2006, we commenced service on a significant expansion to our Pembina battery and downstream infrastructure. The useful life of the facilities exceeds the estimated useful life of the reserves for which they were constructed. As a result, the cost of this infrastructure has been segregated from the net book value being depleted by the units-of-production method, and is being depreciated on a straight-line basis over 20 years.

10

Dominion Resources, Inc.
Canadian Exploration & Production Operations

Notes to the Combined Financial Statements, Continued

Impairment of Long-Lived and Intangible Assets

We perform an evaluation for impairment whenever events or changes in circumstances indicate that the carrying amount of long-lived assets or intangible assets with finite lives may not be recoverable. These assets are written down to fair value if the sum of the expected future undiscounted cash flows is less than the carrying amounts.

Asset Retirement Obligations

We recognize asset retirement obligations (AROs) at fair value as incurred or when sufficient information becomes available to determine a reasonable estimate of the fair value of the retirement activities to be performed. These amounts are capitalized as costs of the related tangible long-lived assets. Since relevant market information is not available, we estimate fair value using discounted cash flow analyses. We report the accretion of the AROs due to the passage of time in operations and maintenance expense.

Note 3. Recently Issued Accounting Standards

FIN 48

In July 2006, the Financial Accounting Standards Board (FASB) issued Interpretation No. 48, Accounting for Uncertainty in Income Taxes (FIN 48). Considering the uncertainty and judgment involved in the determination and filing of income taxes, FIN 48 establishes standards for measurement and recognition in financial statements of positions taken by an entity in its income tax returns. Positions taken by an entity in its income tax returns that are recognized in its financial statements must satisfy a more-likely-than-not recognition threshold, assuming that the position will be examined by taxing authorities with full knowledge of all relevant information.

FIN 48 requires disclosures about positions taken by an entity in its tax returns that are not recognized in its financial statements, reasonably possible significant changes in the amount of unrecognized tax benefits that could occur in the next twelve months and descriptions of open tax years by major jurisdiction.

We adopted the provisions of FIN 48 on January 1, 2007. The cumulative effect of this change in accounting principle had no impact on the beginning balance of our retained earnings.

SFAS No. 157

In September 2006, the FASB issued SFAS No. 157, Fair Value Measurements (SFAS No. 157), which defines fair value, establishes a framework for measuring fair value and expands disclosures related to fair value measurements. SFAS No. 157 clarifies that fair value should be based on assumptions that market participants would use when pricing an asset or liability and establishes a fair value hierarchy of three levels that prioritizes the information used to develop those assumptions. The fair value hierarchy gives the highest priority to quoted prices in active markets and the lowest priority to unobservable data. SFAS No. 157 requires fair value measurements to be separately disclosed by level within the fair value hierarchy. The provisions of SFAS No. 157 will become effective for us beginning January 1, 2008. Generally, the provisions of this statement are to be applied prospectively. Certain situations, however, require retrospective application as of the beginning of the year of adoption through the recognition of a cumulative effect of accounting change. Such retrospective application is required for financial instruments, including derivatives and certain hybrid instruments with limitations on initial gains or losses under Emerging Issues Task Force (EITF) Issue 02-3, Issues Involved in Accounting for Derivative Contracts Held for Trading Purposes and Contracts Involved in Energy Trading and Risk Management Activities, and SFAS No. 155, Accounting for Certain Hybrid Financial Instruments. We are currently evaluating the impact that SFAS No. 157 will have on our results of operations and financial condition.

SFAS No. 159

In February 2007, the FASB issued SFAS No. 159, The Fair Value Option for Financial Assets and Financial Liabilities

(SFAS No. 159). SFAS No. 159 provides an entity with the option, at specified election dates, to measure certain financial assets and liabilities and other items at fair value, with changes in fair value recognized in earnings as those changes occur. SFAS No. 159 also establishes presentation and disclosure requirements that include displaying the fair value of those assets and liabilities for which the entity elected the fair value option on the face of the balance sheet and providing management’s reasons for electing the fair value option for each eligible item. The provisions of SFAS No. 159 will become effective for us beginning January 1, 2008. We are currently evaluating the impact that SFAS No. 159 may have on our results of operations and financial condition.

11

Dominion Resources, Inc.
Canadian Exploration & Production Operations

Notes to the Combined Financial Statements, Continued

Note 4. Income Taxes

Income from continuing operations before provision for income taxes (pre-tax income), classified by source of income, and the details of income tax expense for continuing operations were as follows:

Year Ended December 31,		2006			2005
(thousands)
Income from continuing operations before income tax expense:
Canadian	$	23,991		$	29,003
Foreign		---			---
Total		23,991			29,003
Income tax expense:
Current
Canadian		2,445			76
Foreign		---			---
Total current		2,445			76
Deferred
Canadian		(4,344	)		6,395
Foreign		---			---
Total deferred		(4,344	)		6,395
Total income tax expense (benefit)	$	(1,899	)	$	6,471

For continuing operations, the statutory Canadian income tax rate reconciles to our effective income tax rates as follows:

Year Ended December 31,		2006			2005
(amounts in thousands)
Income from continuing operations before income taxes	$	23,991		$	29,003
Canadian statutory rate		34.5	%		38.8	%
Provision for income taxes computed at the statutory rate	$	8,277		$	11,253
Add/(Deduct) the tax effect of:
Attributed Canadian royalty income		---			(4,906	)
Changes in tax rates		(13,664	)		(2,987	)
Non-deductible crown payments		2,832			3,091
Resource allowance		654			(998	)
Other		2			1,018
Provision for (recovery of) income taxes	$	(1,899	)	$	6,471

12

Dominion Resources, Inc.
Canadian Exploration & Production Operations

Notes to the Combined Financial Statements, Continued

Deferred income taxes reflect the net tax effects of temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts used for income tax purposes. Our net deferred income taxes consist of the following:

At December 31,		2006		2005
(thousands)
Deferred income tax assets:
Accumulated other comprehensive income	$	1,358	$	12,564
Attributed royalty income		4,169		10,147
Other		2,474		11,118
Total deferred income tax assets		8,001		33,829
Deferred income tax liabilities:
Depreciation method and plant basis differences	$	104,721	$	114,162
Partnership basis differences		21,881		30,392
Accumulated other comprehensive income		815		---
Total deferred income tax liabilities		127,417		144,554
Total net deferred income tax liabilities	$	119,416	$	110,725

Other

At December 31, 2006, we had investment tax credits of $757 thousand that that will expire if unutilized during the period 2015 through 2016, the benefit of which has been recognized.

Note 5. Hedge Accounting Activities

We are exposed to the impact of market fluctuations in the price of natural gas and oil in our business operations. We use derivative instruments to manage our exposure to these risks and designate certain derivative instruments as cash flow hedges for accounting purposes as allowed by SFAS No. 133. For the years ended December 31, 2006 and 2005, we recognized no ineffectiveness in net income.

The following table presents selected information related to cash flow hedges included in AOCI in our Combined Balance Sheet at December 31, 2006:

					Portion Expected
					to be Reclassified
					to Earnings
					during the Next
		AOCI			12 Months	Maximum
		After Tax			After Tax	Term
(thousands)
Natural gas	$	(1,059	)	$	1,588	36 months

The amounts that will be reclassified from AOCI to earnings will generally be offset by the recognition of the hedged transactions (e.g., anticipated sales) in earnings, thereby achieving the realization of prices contemplated by the underlying risk management strategies and will vary from the expected amounts presented above as a result of changes in market prices.

Note 6. Investment Securities

We did not own any investments in debt or equity securities at December 31, 2006 or 2005. However, during 2005, we purchased and subsequently sold a debt security that was classified as available for sale. For the year ended December 31, 2005, total proceeds received and gross realized gains from the sale were $195 million and $1.2 million, respectively. In determining the realized gain, the cost of the security was determined on a specific identification basis.

13

Dominion Resources, Inc.
Canadian Exploration & Production Operations
Notes to the Combined Financial Statements, Continued
Note 7. Property, Plant and Equipment
Major classes of property, plant and equipment and their respective balances are:
At December 31,		2006		2005
(thousands)
Exploration and production properties being amortized:
Proved	$	633,067	$	563,757
Unproved		1,112		---
Unproved exploration and production properties not being amortized		59,346		57,958
Other		9,201		8,735
Total property, plant and equipment	$	702,726	$	630,450

Costs of unproved properties capitalized under the full cost method of accounting that were excluded from amortization at December 31, 2006 and the years in which such excluded costs were incurred, are as follows:

		Total		2006		2005		Years Prior
(thousands)
Property acquisition costs	$	29,159	$	2,644	$	5,379	$	21,136
Exploration costs		25,366		14,534		4,682		6,150
Capitalized interest		4,821		739		966		3,116
Total	$	59,346	$	17,917	$	11,027	$	30,402

There were no significant properties under development, as defined by the SEC, excluded from amortization at December 31, 2006. As gas and oil reserves are proved through drilling or as properties are deemed to be impaired, excluded costs and any related reserves are transferred on an ongoing, well-by-well basis into the amortization calculation.

Amortization rates for capitalized costs under the full cost method of accounting were $2.19 and $1.82 per million cubic feet equivalent for the years ended December 31, 2006 and 2005, respectively.

Sale of E&P Assets

In December 2004, we sold the majority of our natural gas and oil assets in British Columbia, Canada for $476 million. Net cash proceeds from the sales were $470 million. We received $314 million in December 2004 and $156 million in January 2005.

Note 8. Asset Retirement Obligations

Our AROs are primarily associated with the dismantlement and removal of gas and oil wells. These obligations result from certain safety and environmental activities we are required to perform when any pipeline or well is abandoned. The changes to our AROs during 2005 and 2006 were as follows:

At December 31,		2006			2005
(thousands)
Asset retirement obligations at beginning of year	$	37,555		$	33,753
Obligations incurred during the period		3,142			1,090
Obligations settled during the period		(5,139	)		(1,296	)
Accretion expense		2,660			1,943
Other		(88	)		2,065
Asset retirement obligations at end of year	$	38,130		$	37,555

Note 9. Short-Term Debt and Credit Agreements

As of December 31, 2006, our short-term financing was supported by a $CAD 75 million syndicated debt facility that terminated in April 2007, and was not renewed. The syndicated debt facility also had a $CAD 5 million operating capacity feature, which acted as overdraft protection and supported our letter of credit issuances. At December 31, 2006, outstanding banker’s acceptances supported by the syndicated debt facility were $CAD 60 million, with a weighted average interest rate of 5.45% and remaining capacity available under the facility was $CAD 15 million. At December 31, 2006, outstanding

14

Dominion Resources, Inc.
Canadian Exploration & Production Operations

Notes to the Combined Financial Statements, Continued

letters of credit supported by the syndicated debt facility’s operating capacity feature totaled $CAD 1.05 million and remaining capacity available under the feature was $CAD 3.95 million.

In addition, in July 2006, we entered into a $CAD 25 million bi-lateral facility with the Bank of Nova Scotia that was scheduled to terminate in July 2007. In April 2007, this facility was amended and the limit was increased to $CAD 125 million. The amended facility is now scheduled to terminate in December 2007. At December 31, 2006, outstanding banker’s acceptances supported by the facility totaled $CAD 25 million with a weighted average interest rate of 5.41% .

At December 31, 2005, outstanding banker’s acceptances supported by previous facilities totaled $CAD 35 million, with a weighted average interest rate of 4.24% . At December 31, 2005, outstanding letters of credit supported by previous facilities totaled $CAD 1.5 million.

Note 10. Employee Benefit Plans

DECL provides a Group Registered Retirement Savings Plan (RSP) for its employees. The objective of the RSP is to assist employees in reaching their goals for long-term financial security by providing a convenient and tax effective way to save for retirement. Dominion makes a standard contribution and matches up to an additional 8% of the employee’s contribution. Once employees reach the maximum RSP contribution limit of 2% of each employee’s annual compensation, their excess contributions are directed to a Dominion-sponsored employee savings plan. It is the employee’s responsibility to determine his or her contribution level and manage decisions within both the RSP and the Dominion-sponsored plan. Our share of contributions for the years ending December 31, 2006 and 2005 was $1 million and $825 thousand, respectively.

Note 11. Commitments and Contingencies

As the result of issues generated in the ordinary course of business, we are involved in legal, tax and regulatory proceedings before various courts, regulatory commissions and governmental agencies, some of which involve substantial amounts of money. We believe that the final disposition of these proceedings will not have a material effect on our financial position, liquidity or results of operations.

Lease Commitments

We lease facilities and equipment under operating leases. Future minimum lease payments under noncancelable operating leases that have initial or remaining lease terms in excess of one year as of December 31, 2006 are as follows:

	2007		2008		2009		2010		2011	Thereafter		Total
	(thousands)
$	1,115	$	1,213	$	1,246	$	1,246	$	311	$ ---	$	5,131

Rental expense totaled $2.1 million and $1.9 million for 2006 and 2005, respectively, the majority of which is reflected in operations and maintenance expense.

Environmental Matters

We are subject to costs resulting from a steadily increasing number of environmental laws and regulations designed to protect human health and the environment. These laws and regulations can result in increased capital, operating and other costs as a result of compliance, remediation, containment and monitoring obligations.

As a result of the 2005 changes to the “Alberta Environment Upstream Oil and Gas Reclamation and Remediation Program”, we are implementing an approach to achieving reclamation certification of active and abandoned wells. Newly abandoned wells are incorporated into the reclamation program while continuing with the remediation and surface reclamation of certain of our existing abandoned wells and a small number of active sites. While completing the surface reclamation of the well sites that satisfy Alberta’s remediation criteria, we are actively moving toward reducing the liability and achieving closure on certain operated well sites that have subsurface contamination. The assessment, remediation and reclamation program developed for these sites is scheduled to take place over the next 5 years at an average annual cost of approximately $2.7 million.

Litigation

In January 2002, we filed a Statement of Claim against Enron Canada Corporation (ECC) seeking recovery for gas delivered to ECC in the amount of $CAD 1.2 million, a declaration that we properly terminated our gas supply contract with ECC in

15

Dominion Resources, Inc.
Canadian Exploration & Production Operations

Notes to the Combined Financial Statements, Continued

December 2001, and that no amounts are due ECC as a consequence of such termination. In March 2002, ECC filed a Statement of Defense and counterclaim denying our allegations, contesting our termination of the gas supply contract and asserting that ECC is entitled to recover approximately $CAD 15.6 million from us as a consequence of such termination. In early May 2007, we settled the case by making a cash payment to ECC and waiving a claim to an account payable from ECC. This settlement has been recorded in accrued liabilities.

In March 2003, DECL was named as a defendant in a lawsuit filed in the Alberta Court of Queen's Bench in the Judicial District of Calgary by Signalta Resources Limited (Signalta). Signalta alleges that DECL wrongfully drilled on lands contributed by DECL’s predecessor to the West Viking Gas Unit in 1975. The claim is for $7 million, and we have established a trust for this claim which contained $2.3 million at December 31, 2006. The trial was concluded in July 2006 and judgment is expected in the second quarter of 2007. No liability has been recorded in our Combined Financial Statements related to this matter.

Indemnifications

As part of commercial contract negotiations in the normal course of business, we may sometimes agree to make payments to compensate or indemnify other parties for possible future unfavorable financial consequences resulting from specified events. The specified events may involve an adverse judgment in a lawsuit or the imposition of additional taxes due to a change in tax law or interpretation of the tax law. We are unable to develop an estimate of the maximum potential amount of future payments under these contracts because events that would obligate us have not yet occurred or, if any such event has occurred, we have not been notified of its occurrence. However, at December 31, 2006, we believe future payments, if any, that could ultimately become payable under these contract provisions, would not have a material impact on our results of operations, cash flows or financial position.

Note 12. Credit Risk

Credit risk is our risk of financial loss if counterparties fail to perform their contractual obligations. In order to minimize overall credit risk, we maintain credit policies, including the evaluation of counterparty financial condition, collateral requirements and the use of standardized agreements that facilitate the netting of cash flows associated with a single counterparty. In addition, counterparties may make available collateral, including letters of credit or cash held as margin deposits, as a result of exceeding agreed-upon credit limits, or may be required to prepay the transaction.

We maintain a provision for credit losses based on factors surrounding the credit risk of our customers, historical trends and other information. We believe, based on our credit policies and our December 31, 2006 provision for credit losses, that it is unlikely that a material adverse effect on our financial position, results of operations or cash flows would occur as a result of counterparty nonperformance.

We sell natural gas and enter into contracts with various companies in the energy industry for purchases and sales of extracted products, including natural gas and oil. These transactions principally occur in Canada’s Alberta province. We do not believe that this geographic concentration contributes significantly to our overall exposure to credit risk.

Our exposure to potential credit risk results primarily from our sales of gas and oil production and extracted products, including our hedging activities. Our gross credit exposure for each counterparty is calculated as outstanding receivables plus any unrealized on or off-balance sheet exposure, taking into account contractual netting rights. Gross credit exposure is calculated prior to the application of collateral. At December 31, 2006, our gross credit exposure totaled $41 million. Of this amount, investment grade counterparties represented 51%. We held no collateral for these transactions at December 31, 2006.

Note 13. Related-Party Transactions

We engage in related-party transactions primarily with affiliates. Our accounts receivable and payable balances with affiliates are settled based on contractual terms or on a monthly basis, depending on the nature of the underlying transactions. Dominion Resources Services, Inc. (DRS) provides certain administrative and technical services to us. In addition, certain U.S. ex-patriot personnel on staff with Dominion’s Canadian entities participate in certain Dominion benefit plans.

16

Dominion Resources, Inc.
Canadian Exploration & Production Operations
Notes to the Combined Financial Statements, Continued
Presented below are significant affiliated transactions recorded in operating expenses:
		2006		2005
(thousands)
Services provided by DRS	$	609	$	1,335

Note 14. Reconciliation to Generally Accepted Accounting Principles in Canada (Canadian GAAP)

The combined financial statements, prepared in accordance with U.S. GAAP, conform to Canadian GAAP, in all material respects, except:

Combined statements of income

The application of Canadian GAAP would have the following effects on net income as reported:

Years Ended December 31,		2006			2005
(thousands)
Net income as reported in accordance with U.S. GAAP	$	25,890		$	22,532
Adjustments:
Depreciation, depletion and amortization		(5,237	)		(3,776	)
Income taxes		3,768			1,753
Total adjustments		(1,469	)		(2,023	)
Net income under Canadian GAAP		24,421			20,509

Full Cost Depreciation, Depletion and Amortization

Full cost depreciation, depletion and amortization (DD&A) is recorded in accordance with Accounting Guideline 16, Oil and Gas Accounting – Full Cost, prescribed by the Canadian Institute of Chartered Accountants (CICA) for Canadian GAAP purposes and Rule 4-10, Financial Accounting and Reporting for Oil and Gas Producing Activities Pursuant to the Federal Securities Laws and the Energy Policy and Conservation Act of 1975, of Regulation S-X prescribed by the SEC for U.S. GAAP purposes. DD&A is based on units-of-production under both accounting principles. However, under U.S. GAAP, DD&A is calculated using constant prices in effect at year-end, while under Canadian GAAP DD&A is calculated using forecasted prices. The adjustments to DD&A shown in the table above, as well as the difference in Accumulated depreciation, depletion and amortization shown in the table below reflect this difference in accounting principles.

Income Taxes

Differences may exist between U.S. GAAP and Canadian GAAP in the accounting for investment tax credits. Under U.S. GAAP, as of January 1, 2005, DECL had recognized a deferred tax asset for tax credit carryforwards related to research and experimental development expenditures incurred prior to January 1, 2005. In 2006, DECL recognized a reduction in the deferred tax asset, reflecting the utilization of the credits to reduce taxes payable. For Canadian tax purposes, DECL recognizes investment tax credits as deferred credits when the expenditures are made and their realization is reasonably assured. The deferred credits are reported as a reduction to property, plant and equipment and are being amortized into income on a straight-line basis over 5-year periods.

In addition, there may be differences between U.S. GAAP and Canadian GAAP in the basis for measurement of income tax assets and liabilities. Under U.S. GAAP, income tax assets and liabilities are measured based on enacted tax rates and laws; under Canadian GAAP, income tax assets and liabilities are measured based on tax rates that are expected to apply when the assets are realized or the liabilities are settled, taking into account "substantively enacted" tax rates and laws.

Income taxes are being provided for those adjustments that have been identified to reconcile the financial statements prepared in accordance with U.S. GAAP to those prepared in accordance with Canadian GAAP.

17

Dominion Resources, Inc.
Canadian Exploration & Production Operations

Notes to the Combined Financial Statements, Continued

Combined balance sheets

The application of Canadian GAAP would have the following effects on balance sheet items as reported:

		U.S.			Canadian			Difference
(thousands)		GAAP			GAAP
As of December 31, 2006
Property, plant and equipment	$	702,726		$	702,262		$	464
Accumulated depreciation, depletion and amortization		(186,316	)		(224,916	)		38,600
Total property, plant and equipment, net		516,410			477,346			39,064
Accrued interest, payroll and taxes		5,327			4,578			749
Deferred income taxes – Non-current liabilities		120,848			106,953			13,895
Shareholders’ equity		313,591			289,171			24,420
As of December 31, 2005
Property, plant and equipment	$	630,450		$	629,536		$	914
Accumulated depreciation, depletion and amortization		(141,303	)		(174,874	)		33,571
Total property, plant and equipment, net		489,147			454,662			34,485
Prepaid income taxes		---			3,213			(3,213	)
Deferred income taxes – Non-current liabilities		125,753			118,256			7,497
Shareholders’ equity		267,756			243,981			23,775

New accounting standards

In January 2005, the CICA issued Section 1530, “Comprehensive Income”, Section 3251, “Equity”, Section 3855, “Financial Instruments – Recognition and Measurement” and Section 3865, “Hedges”. These standards were early adopted under Canadian GAAP on January 1, 2005 and resulted in increased consistency between U.S. and Canadian GAAP. As a result of adopting these standards, the following accounting policies apply:

• Derivative Financial Instruments – We use derivative financial instruments to mitigate our exposure to fluctuations in commodity prices. We designate a substantial portion of our derivative instruments as cash flow hedges for accounting purposes. For transactions in which we are hedging the variability of cash flows, changes in the fair value of the derivative are reported in AOCI, to the extent effective at offsetting changes in the hedged item, until earnings are affected by the hedged item. We also hold certain derivative financial instruments that are classified as not held for trading purposes and recorded on the combined balance sheet at fair value. Changes in the fair value of these financial instruments are recognized in net income in the combined statements of income in the period in which they occur.

• Embedded Derivatives - Embedded derivatives are derivatives embedded in a host contract. They are recorded separately from the host contract when their economic characteristics and risks are not clearly and closely related to those of the host contract, the terms of the embedded derivative are the same as those of a freestanding derivative and the combined contract is not recorded at fair value. As of January 1, 2005, we did not have any embedded derivatives to record under the new guidelines.

• Comprehensive Income - Comprehensive income consists of net earnings and other comprehensive income and represents the change in shareholders’ equity, resulting from transactions and events from sources other than our shareholders. These transactions and events include changes in the currency translation adjustment and the effective portion of the change in fair value of any designated cash flow hedges.

The adoption increased total assets and liabilities by $37.0 million and $40.6 million, respectively, and reduced shareholders’ equity by $3.6 million at January 1, 2005 for Canadian GAAP purposes. The new Canadian standards increase harmonization with U.S. GAAP and will have no impact on our Combined Financial Statements as we report under U.S. GAAP, which includes similar requirements.

Note 15. Subsequent Event

In May 2007, we reached an agreement to pay approximately $27 million to divest our interest in a pipeline capacity contract. We expect this transaction to close in June 2007.

18

Dominion Resources, Inc.
Canadian Exploration & Production Operations

Supplementary Data - Unaudited

Gas and Oil Producing Activities
Capitalized Costs
The aggregate amounts of costs capitalized for gas and oil producing activities, and related aggregate amounts of
accumulated depletion follow:
At December 31,		2006		2005
(thousands)
Capitalized costs:
Proved properties	$	633,067	$	563,757
Unproved properties		60,458		57,958
		693,525		621,715
Accumulated depletion on proved properties		183,504		138,696
Net capitalized costs	$	510,021	$	483,019
Total Costs Incurred
The following costs were incurred in gas and oil producing activities:
Year Ended December 31,		2006		2005
(thousands)
Acquisition costs for unproved properties	$	6,137	$	14,039
Exploration costs		16,057		5,025
Development costs(1)		86,357		79,210
Total	$	108,551	$	98,274

(1)      Development costs incurred for proved undeveloped reserves were $1.3 million and $150 thousand for 2006 and 2005, respectively.

Results of Operations

We caution that the following standardized disclosures required by the FASB do not represent our results of operations based on our historical financial statements. In addition to requiring different determinations of revenue and costs, the disclosures exclude the impact of interest expense and corporate overhead.

Year Ended December 31,		2006		2005
(thousands)
Sales to nonaffiliated companies (net of royalties)	$	133,814	$	130,380
Less:
Production (lifting) costs		42,234		37,587
Depreciation, depletion and amortization		50,394		38,790
Income tax expense		14,205		19,236
Results of operations	$	26,981	$	34,767

19

Company-Owned Reserves

Estimated net quantities of proved gas and oil (including condensate) reserves at December 31, 2006 and 2005, and changes in the reserves during those years, are shown in the two schedules that follow:

	2006		2005
Proved developed and undeveloped reserves—Gas
(bcf)
At January 1	106		96
Changes in reserves:
Extensions, discoveries and other additions	38		23
Revisions of previous estimates	51		2
Production	(16	)	(15	)
Sales of gas in place	(4	)	---
At December 31	175		106
Proved developed reserves—Gas
(bcf)
At January 1	101		94
At December 31	132		101
Proved developed and undeveloped reserves—Oil
(thousands of barrels)
At January 1	19,096		20,055
Changes in reserves:
Extensions, discoveries and other additions	695		1,282
Revisions of previous estimates	(2,619	)	(1,380	)
Production	(1,024	)	(861	)
Sales of oil in place	(738	)	---
At December 31	15,410		19,096
Proved developed reserves—Oil
(thousands of barrels)
At January 1	7,154		11,840
At December 31	7,061		7,154

Standardized Measure of Discounted Future Net Cash Flows and Changes Therein

The following tabulation has been prepared in accordance with the FASB’s rules for disclosure of a standardized measure of discounted future net cash flows relating to proved gas and oil reserve quantities that we own:

		2006		2005
(thousands)
Future cash inflows(1)	$	1,722,027	$	1,891,753
Less:
Future development costs(2)		173,805		101,572
Future production costs		485,194		409,505
Future income tax expense		330,490		491,797
Future cash flows		732,538		888,879
Less annual discount (10% a year)		314,946		355,876
Standardized measure of discounted future net cash flows	$	417,592	$	533,003

(1)	Amounts exclude the effect of derivative instruments designated as hedges of future sales of production at year-end.
(2)	Estimated future development costs, excluding abandonment, for proved undeveloped reserves are estimated to be $68 million, $26 million and $27 million for 2007, 2008 and 2009, respectively.

In the foregoing determination of future cash inflows, sales prices for gas and oil were based on contractual arrangements or market prices at year end. Future costs of developing and producing the proved gas and oil reserves reported at the end of each year shown were based on costs determined at each such year end, assuming the continuation of existing economic conditions. Future income taxes were computed by applying the appropriate year-end or future statutory tax rate to future pretax net cash flows, less the tax basis of the properties involved, and giving effect to tax deductions, permanent differences and tax credits.

It is not intended that the FASB’s standardized measure of discounted future net cash flows represent the fair market value of our proved reserves. We caution that the disclosures shown are based on estimates of proved reserve quantities and future

20

production schedules which are inherently imprecise and subject to revision, and the 10% discount rate is arbitrary. In addition, costs and prices as of the measurement date are used in the determinations, and no value may be assigned to probable or possible reserves.

The following tabulation is a summary of changes between the total standardized measure of discounted future net cash flows at the beginning and end of each year:

		2006			2005
(thousands)
Standardized measure of discounted future net cash flows at January 1	$	533,003		$	264,631
Changes in the year resulting from:
Sales and transfers of gas and oil produced during the year, less production costs		(100,079	)		(101,589	)
Prices and production and development costs related to future production		(298,166	)		476,386
Extensions, discoveries and other additions, less production and development costs		123,654			151,789
Previously estimated development costs related to future production		1,372			150
Revisions of previous quantity estimates		67,610			(3,021	)
Accretion of discount		82,790			39,490
Income taxes		106,499			(164,629	)
Other purchases and sales of proved reserves in place		(30,463	)		---
Other (principally timing of production)		(68,628	)		(130,204	)
Standardized measure of discounted future net cash flows at December 31	$	417,592		$	533,003

21

Dominion Resources, Inc. 
Canadian Exploration & Production Operations

Combined Financial Statements for the Three 
Months Ended March 31, 2007 and 2006

Dominion Resources, Inc.
Canadian Exploration & Production Operations
Index
	Page
Financial Information	Number
Combined Statements of Income – Three Months Ended March 31, 2007 and 2006	3
Combined Balance Sheets – March 31, 2007 and December 31, 2006	4
Combined Statements of Cash Flows – Three Months Ended March 31, 2007 and 2006	5
Notes to Combined Financial Statements	6

2

Dominion Resources, Inc.
Canadian Exploration & Production Operations
Unaudited
Combined Statements of Income(1)
Three Months Ended March 31,		2007		2006
(thousands)
Operating Revenue
Gas and oil production	$	36,795	$	32,796
Extracted products		1,545		1,576
Other revenue		2,611		885
Total operating revenue		40,951		35,257
Operating Expenses
Operations and maintenance		19,606		12,507
Depreciation, depletion and amortization – oil and gas properties		12,756		12,456
Depreciation, depletion and amortization – non-oil and gas properties		98		95
Other taxes		1,145		2,615
Total operating expenses		33,605		27,673
Income from operations		7,346		7,584
Other income		654		313
Interest and related charges		347		197
Income before income taxes		7,653		7,700
Income tax expense(2)		2,458		3,784
Net Income	$	5,195	$	3,916

(1)	All amounts shown in United States (U.S.) dollars.
(2)	The effective tax rate decreased from March 31, 2006 to March 31, 2007 by 16.9% resulting primarily from a decrease in statutory rates and change in laws.
The accompanying notes are an integral part of our Combined Financial Statements.

3

Dominion Resources, Inc.
Canadian Exploration & Production Operations
Unaudited
Combined Balance Sheets(1)
		March 31,			December 31,
		2007			2006	(2)
(thousands)
ASSETS
Current Assets
Cash and cash equivalents	$	17,083		$	30,741
Customer receivables (less allowance for doubtful accounts of $64 at both dates)		19,507			24,812
Receivables from affiliates		1,395			1,394
Other receivables		17,447			15,825
Materials and supplies inventory		5,863			4,168
Derivative assets		260			2,402
Deferred income taxes		2,941			888
Other		7,750			5,288
Total current assets		72,246			85,518
Property, Plant and Equipment
Property, plant and equipment		734,139			702,726
Accumulated depreciation, depletion and amortization		(201,039	)		(186,316	)
Total property, plant and equipment, net(3)		533,100			516,410
Deferred Charges and Other Assets		4,432			2,566
Total assets	$	609,778		$	604,494
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current Liabilities
Short-term debt	$	60,627		$	72,936
Accrued liabilities		47,453			46,978
Accounts payable		7,060			2,006
Accrued interest, payroll and taxes		2,657			5,327
Derivative liabilities		6,080			272
Total current liabilities		123,877			127,519
Other Liabilities
Deferred income taxes		125,034			120,848
Asset retirement obligations		38,448			38,130
Other		9,640			4,406
Total other liabilities		173,122			163,384
Total liabilities		296,999			290,903
Commitments and Contingencies (see Note 8)
Common Shareholders’ Equity
Common stock, no par value, 74 shares authorized and outstanding		74			74
Additional paid-in capital		84,134			84,134
Retained earnings		180,546			175,351
Accumulated other comprehensive income		48,025			54,032
Total shareholders’ equity		312,779			313,591
Total liabilities and shareholders’ equity	$	609,778		$	604,494

(1)	All amounts shown in U.S. dollars, except shares.
(2)	The Combined Balance Sheet at December 31, 2006 has been derived from the audited Combined Financial Statements at that date.
(3)	At cost based on full cost method for oil and gas properties ($49,916 and $59,346 excluded from amortization at March 31, 2007 and December 31, 2006, respectively)
	The accompanying notes are an integral part of our Combined Financial Statements.

4

Dominion Resources, Inc.
Canadian Exploration & Production Operations
Unaudited
Combined Statements of Cash Flows(1)
Three Months Ended March 31,		2007			2006
(thousands)
Operating Activities
Net income	$	5,195		$	3,916
Adjustments to reconcile net income to net cash from operating activities:
Depreciation, depletion and amortization		12,854			12,550
Deferred income taxes		2,458			3,776
Changes in:
Accounts receivable		3,682			(7,150	)
Inventories		(1,695	)		(1,050	)
Accounts payable		5,731			7,620
Accrued interest, payroll and taxes		(2,671	)		(1,056	)
Margin deposit assets and liabilities		(3,260	)		---
Other operating assets and liabilities		6,578			(12,365	)
Net cash provided by operating activities		28,872			6,241
Investing Activities
Additions to gas and oil properties		(27,634	)		(31,802	)
Net cash used in investing activities		(27,634	)		(31,802	)
Financing Activities
Issuance (repayment) of short-term debt, net		(12,309	)		16,994
Net cash provided by (used in) financing activities		(12,309	)		16,994
Effect of exchange rate change on cash		(2,587	)		2,395
Decrease in cash and cash equivalents		(13,658	)		(6,172	)
Cash and cash equivalents at beginning of year		30,741			19,221
Cash and cash equivalents at end of year	$	17,083		$	13,049

(1)	All amounts shown in U.S. dollars.
	The accompanying notes are an integral part of our Combined Financial Statements.

5

Dominion Resources, Inc.
Canadian Exploration & Production Operations
Unaudited

Notes to the Combined Financial Statements

Note 1. Nature of Operations

The Canadian Exploration and Production (E&P) operations of Dominion Resources, Inc. (Dominion) include natural gas and oil exploration, development and production operations.

The terms “Company,” “we,” “our” and “us” are used throughout this report and, depending on the context of their use, may represent one or more of Dominion’s Canadian E&P legal entities or the entirety of Dominion’s Canadian E&P legal entities and their consolidated subsidiaries.

Note 2. Significant Accounting Policies

As permitted by the rules and regulations of the Securities and Exchange Commission (SEC), our accompanying unaudited Combined Financial Statements contain certain condensed financial information and exclude certain footnote disclosures normally included in annual audited combined financial statements prepared in accordance with accounting principles generally accepted in the United States of America (GAAP). These unaudited Combined Financial Statements should be read in conjunction with our audited annual Combined Financial Statements and Notes for the year ended December 31, 2006.

In our opinion, the accompanying unaudited Combined Financial Statements contain all adjustments, including normal recurring accruals, necessary to present fairly our financial position as of March 31, 2007, and our results of operations and cash flows for the three months ended March 31, 2007 and 2006.

We make certain estimates and assumptions in preparing our Combined Financial Statements in accordance with GAAP. These estimates and assumptions affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses for the periods presented. Actual results may differ from those estimates.

Our Combined Financial Statements and the accompanying notes are presented in U.S. dollars, except certain disclosures related to credit agreements and litigation which are presented in Canadian dollars ($CAD), and include the accounts of Dominion Energy Canada Limited (DECL), Dominion Canada Finance Company (DCFC), Domcan NS1 ULC (Domcan) and their subsidiaries, all of which are under common control and ownership.

The results of operations for interim periods are not necessarily indicative of the results expected for the full year. Information for quarterly periods is affected by seasonal variations in sales and other factors.

All significant intercompany profits, accounts, and transactions have been eliminated in the combination, except applicable equity transactions and accounts.

Note 3. Newly Adopted Accounting Standards

FIN 48

We adopted the provisions of Financial Accounting Standards Board (FASB) Interpretation No. 48, Accounting for Uncertainty in Income Taxes (FIN 48) as of January 1, 2007. We concluded that all tax positions could be sustained and as a result, there was no impact on the financial statements upon adoption.

Unrecognized tax benefits represent those tax benefits related to tax positions that have been taken or are expected to be taken in tax returns, including refund claims, that are not recognized in the financial statements because, in accordance with FIN 48, management has either measured the tax benefit at an amount less than the benefit claimed, or expected to be claimed, or concluded that it is not more-likely-than-not that the tax position will be ultimately sustained. As of January 1, 2007 and through March 31, 2007, we had no unrecognized tax benefits.

When incurred, we recognize estimated interest payable on underpayments of income taxes in interest expense and estimated penalties in other income. As of January 1, 2007, we had accrued no amounts for interest and penalties.

We file federal income tax returns in Canada and provincial income tax returns in Alberta. Income tax returns for 2002 and subsequent years remain subject to examination. In the fourth quarter of 2006, the Canadian Revenue Authority (CRA) began an audit of our claim for $889 thousand of investment tax credits related to research and experimental expenditures in fiscal years ending in 2005. Based on the findings of prior year CRA audits, including a review of our planned research and

6

Dominion Resources, Inc.
Canadian Exploration & Production Operations

Notes to the Combined Financial Statements, Continued

experimental projects for subsequent years, we had, through March 31, 2007, concluded, based on prior assessments for sustainable similar projects, that it was highly certain that our project expenditures would continue to qualify for the credit. However, in April 2007, the CRA notified us that it was challenging the eligibility of our expenditures. Under FIN 48, we must evaluate the impact of this development on the recognition of the investment tax credits in the preparation of our financial statements for the quarter ending June 30, 2007.

Note 4. Recently Issued Accounting Standards

SFAS No. 157

In September 2006, the FASB issued Statement of Financial Accounting Standards (SFAS) No. 157, Fair Value Measurements (SFAS No. 157), which defines fair value, establishes a framework for measuring fair value and expands disclosures related to fair value measurements. SFAS No. 157 clarifies that fair value should be based on assumptions that market participants would use when pricing an asset or liability and establishes a fair value hierarchy of three levels that prioritizes the information used to develop those assumptions. The fair value hierarchy gives the highest priority to quoted prices in active markets and the lowest priority to unobservable data. SFAS No. 157 requires fair value measurements to be separately disclosed by level within the fair value hierarchy. The provisions of SFAS No. 157 will become effective for us beginning January 1, 2008. Generally, the provisions of this statement are to be applied prospectively. Certain situations, however, require retrospective application as of the beginning of the year of adoption through the recognition of a cumulative effect of accounting change. Such retrospective application is required for financial instruments, including derivatives and certain hybrid instruments with limitations on initial gains or losses under Emerging Issues Task Force (EITF) Issue 02-3,

Issues Involved in Accounting for Derivative Contracts Held for Trading Purposes and Contracts Involved in Energy Trading and Risk Management Activities, and SFAS No. 155, Accounting for Certain Hybrid Financial Instruments. We are currently evaluating the impact that SFAS No. 157 will have on our results of operations and financial condition.

SFAS No. 159

In February 2007, the FASB issued SFAS No. 159, The Fair Value Option for Financial Assets and Financial Liabilities

(SFAS No. 159). SFAS No. 159 provides an entity with the option, at specified election dates, to measure certain financial assets and liabilities and other items at fair value, with changes in fair value recognized in earnings as those changes occur. SFAS No. 159 also establishes presentation and disclosure requirements that include displaying the fair value of those assets and liabilities for which the entity elected the fair value option on the face of the balance sheet and providing management’s reasons for electing the fair value option for each eligible item. The provisions of SFAS No. 159 will become effective for us beginning January 1, 2008. Early adoption is permitted provided that an election is also made to apply the provisions of SFAS No. 157. We are currently evaluating the impact that SFAS No. 159 may have on our results of operations and financial condition.

Note 5. Hedge Accounting Activities

We are exposed to the impact of market fluctuations in the price of natural gas and oil in our business operations. We use derivative instruments to manage our exposure to these risks and designate certain derivative instruments as cash flow hedges for accounting purposes as allowed by SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities. For the three months ended March 31, 2007 and 2006, no hedge ineffectiveness was recognized in net income.

7

Dominion Resources, Inc.
Canadian Exploration & Production Operations

Notes to the Combined Financial Statements, Continued

The following table presents selected information related to cash flow hedges included in accumulated other comprehensive income (AOCI) in our Combined Balance Sheet at March 31, 2007:

					Portion Expected
					to be Reclassified
					to Earnings
					during the Next
		AOCI			12 Months		Maximum
		After Tax			After Tax		Term
(thousands)
Natural gas	$	(10,060	)	$	(3,794	)	33 months

The amounts that will be reclassified from AOCI to earnings will generally be offset by the recognition of the hedged transactions (e.g., anticipated sales) in earnings, thereby achieving the realization of prices contemplated by the underlying risk management strategies and will vary from the expected amounts presented above as a result of changes in market prices.

Note 6. Short-Term Debt and Credit Agreements

As of March 31, 2007, our short-term financing was supported by a $CAD 75 million syndicated debt facility that terminated in April 2007, and was not renewed. The syndicated debt facility also had a $CAD 5 million operating capacity feature, which acted as overdraft protection and supported our letter of credit issuances. At March 31, 2007, outstanding banker’s acceptances supported by the syndicated debt facility were $CAD 45 million, with a weighted average interest rate of 4.35% and remaining capacity available under the facility was $CAD 30 million. At March 31, 2007, outstanding letters of credit supported by the syndicated debt facility’s operating capacity feature totaled $CAD 1.05 million and remaining capacity available under the feature was $CAD 3.95 million.

In addition, in July 2006, we entered into a $CAD 25 million bi-lateral facility with the Bank of Nova Scotia that was scheduled to terminate in July 2007. In April 2007, this facility was amended and the limit was increased to $CAD 125 million. The amended facility is now scheduled to terminate in December 2007. At March 31, 2007 outstanding banker’s acceptances supported by the facility totaled $CAD 25 million with a weighted average interest rate of 4.38% .

Note 7. Employee Benefit Plans

DECL provides a Group Registered Retirement Savings Plan (RSP) for its employees. The objective of the RSP is to assist employees in reaching their goals for long-term financial security by providing a convenient and tax effective way to save for retirement. Dominion makes a standard contribution and matches up to an additional 8% of the employee’s contribution. Once employees reach the maximum RSP contribution limit of 2% of each employee’s annual compensation, their excess contributions are directed to a Dominion-sponsored employee savings plan. It is the employee’s responsibility to determine his or her contribution level and manage decisions within both the RSP and the Dominion-sponsored plan. Our share of contributions for the three months ending March 31, 2007 and 2006 were $289 thousand and $218 thousand, respectively.

Note 8. Commitments and Contingencies

As the result of issues generated in the ordinary course of business, we are involved in legal, tax and regulatory proceedings before various courts, regulatory commissions and governmental agencies, some of which involve substantial amounts of money. We believe that the final disposition of these proceedings will not have a material effect on our financial position, liquidity or results of operations.

Environmental Matters

We are subject to costs resulting from a steadily increasing number of environmental laws and regulations designed to protect human health and the environment. These laws and regulations can result in increased capital, operating and other costs as a result of compliance, remediation, containment and monitoring obligations.

As a result of the 2005 changes to the “Alberta Environment Upstream Oil and Gas Reclamation and Remediation Program”, we are implementing an approach to achieving reclamation certification of active and abandoned wells. Newly abandoned wells are incorporated into the reclamation program while continuing with the remediation and surface reclamation of certain of our existing abandoned wells and a small number of active sites. While completing the surface reclamation of the well

8

Dominion Resources, Inc.
Canadian Exploration & Production Operations

Notes to the Combined Financial Statements, Continued

sites that satisfy Alberta’s remediation criteria, we are actively moving toward reducing the liability and achieving closure on certain operated well sites that have subsurface contamination. The assessment, remediation and reclamation program developed for these sites is scheduled to take place over the next 5 years at an average annual cost of approximately $2.7 million.

Litigation

In January 2002, we filed a Statement of Claim against Enron Canada Corporation (ECC) seeking recovery for gas delivered to ECC in the amount of $CAD 1.2 million, a declaration that we properly terminated our gas supply contract with ECC in December 2001, and that no amounts are due ECC as a consequence of such termination. In March 2002, ECC filed a Statement of Defense and counterclaim denying our allegations, contesting our termination of the gas supply contract and asserting that ECC is entitled to recover approximately $CAD 15.6 million from us as a consequence of such termination. In early May 2007, we settled the case by making a cash payment to ECC and waiving a claim to an account payable from ECC. This settlement has been recorded in accrued liabilities.

In March 2003, DECL was named as a defendant in a lawsuit filed in the Alberta Court of Queen's Bench in the Judicial District of Calgary by Signalta Resources Limited (Signalta). Signalta alleges that DECL wrongfully drilled on lands contributed by DECL’s predecessor to the West Viking Gas Unit in 1975. The claim is for $7 million, and we have established a trust for this claim which contained $2.4 million at March 31, 2007. The trial was concluded in July 2006 and judgment is expected in the second quarter of 2007. No liability has been recorded in our Combined Financial Statements related to this matter.

Indemnifications

As part of commercial contract negotiations in the normal course of business, we may sometimes agree to make payments to compensate or indemnify other parties for possible future unfavorable financial consequences resulting from specified events. The specified events may involve an adverse judgment in a lawsuit or the imposition of additional taxes due to a change in tax law or interpretation of the tax law. We are unable to develop an estimate of the maximum potential amount of future payments under these contracts because events that would obligate us have not yet occurred or, if any such event has occurred, we have not been notified of its occurrence. However, at March 31, 2007, we believe future payments, if any, that could ultimately become payable under these contract provisions, would not have a material impact on our results of operations, cash flows or financial position.

Note 9. Credit Risk

Credit risk is our risk of financial loss if counterparties fail to perform their contractual obligations. In order to minimize overall credit risk, we maintain credit policies, including the evaluation of counterparty financial condition, collateral requirements and the use of standardized agreements that facilitate the netting of cash flows associated with a single counterparty. In addition, counterparties may make available collateral, including letters of credit or cash held as margin deposits, as a result of exceeding agreed-upon credit limits, or may be required to prepay the transaction.

We maintain a provision for credit losses based on factors surrounding the credit risk of our customers, historical trends and other information. We believe, based on our credit policies and our March 31, 2007 provision for credit losses, that it is unlikely that a material adverse effect on our financial position, results of operations or cash flows would occur as a result of counterparty nonperformance.

We sell natural gas and enter into contracts with various companies in the energy industry for purchases and sales of extracted products, including natural gas and oil. These transactions principally occur in Canada’s Alberta province. We do not believe that this geographic concentration contributes significantly to our overall exposure to credit risk.

Our exposure to potential credit risk results primarily from our sales of gas and oil production and extracted products, including our hedging activities. Our gross credit exposure for each counterparty is calculated as outstanding receivables plus any unrealized on or off-balance sheet exposure, taking into account contractual netting rights. Gross credit exposure is calculated prior to the application of collateral. At March 31, 2007, our gross credit exposure totaled $40 million. Of this amount, investment grade counterparties represented 61%. We held no collateral for these transactions at March 31, 2007.

9

Dominion Resources, Inc.
Canadian Exploration & Production Operations

Notes to the Combined Financial Statements, Continued

Note 10. Related-Party Transactions

We engage in related-party transactions primarily with affiliates. Our accounts receivable and payable balances with affiliates are settled based on contractual terms or on a monthly basis, depending on the nature of the underlying transactions. Dominion Resources Services, Inc. (DRS) provides certain administrative and technical services to us. In addition, certain U.S. ex-patriot personnel on staff with Dominion’s Canadian entities participate in certain Dominion benefit plans.

Presented below are significant affiliated transactions recorded in operating expenses:
Three Months Ended March 31,		2007		2006
(thousands)
Services provided by DRS	$	434	$	354

Note 11. Reconciliation to Generally Accepted Accounting Principles in Canada (Canadian GAAP)

The combined financial statements, prepared in accordance with U.S. GAAP, conform to Canadian GAAP, in all material respects, except:

Combined statement of income

The application of Canadian GAAP would have the following effects on net income as reported:

Three Months Ended March 31,		2007			2006
(thousands)
Net income as reported in accordance with U.S. GAAP	$	5,195		$	3,916
Adjustments:
Depreciation, depletion and amortization		(390	)		(903	)
Income taxes		106			243
Total adjustments		(284	)		(660	)
Net income under Canadian GAAP		4,911			3,256

Full Cost Depreciation, Depletion and Amortization

Full cost depreciation, depletion and amortization (DD&A) is recorded in accordance with Accounting Guideline 16, Oil and Gas Accounting – Full Cost, prescribed by the Canadian Institute of Chartered Accountants (CICA) for Canadian GAAP purposes and Rule 4-10, Financial Accounting and Reporting for Oil and Gas Producing Activities Pursuant to the Federal Securities Laws and the Energy Policy and Conservation Act of 1975, of Regulation S-X prescribed by the SEC for U.S. GAAP purposes. DD&A is based on units-of-production under both accounting principles. However, under U.S. GAAP, DD&A is calculated using constant prices in effect at year-end, while under Canadian GAAP DD&A is calculated using forecasted prices. The adjustments to DD&A shown in the table above, as well as the difference in Accumulated depreciation, depletion and amortization shown in the table below reflect this difference in accounting principles.

Income Taxes

Differences may exist between U.S. GAAP and Canadian GAAP in the accounting for investment tax credits. Under U.S. GAAP, as of January 1, 2005, DECL had recognized a deferred tax asset for tax credit carryforwards related to research and experimental development expenditures incurred prior to January 1, 2005. In 2006, DECL recognized a reduction in the deferred tax asset, reflecting the utilization of the credits to reduce taxes payable. For Canadian tax purposes, DECL recognizes investment tax credits as deferred credits when the expenditures are made and their realization is reasonably assured. The deferred credits are reported as a reduction to property, plant and equipment and are being amortized into income on a straight-line basis over 5-year periods.

In addition, there may be differences between U.S. GAAP and Canadian GAAP in the basis for measurement of income tax assets and liabilities. Under U.S. GAAP, income tax assets and liabilities are measured based on enacted tax rates and laws; under Canadian GAAP, income tax assets and liabilities are measured based on tax rates that are expected to apply when the assets are realized or the liabilities are settled, taking into account "substantively enacted" tax rates and laws.

Income taxes are being provided for those adjustments that have been identified to reconcile the financial statements prepared in accordance with U.S. GAAP to those prepared in accordance with Canadian GAAP.

10

Dominion Resources, Inc.
Canadian Exploration & Production Operations

Notes to the Combined Financial Statements, Continued

Combined balance sheets

The application of Canadian GAAP would have the following effects on balance sheet items as reported:

		U.S.			Canadian			Difference
(thousands)		GAAP			GAAP
As of March 31, 2007
Property, plant and equipment	$	734,139		$	733,675		$	464
Accumulated depreciation, depletion and amortization		(201,039	)		(240,396	)		39,357
Total property, plant and equipment, net		533,100			493,279			39,821
Accrued interest, payroll and taxes		2,657			1,908			749
Deferred income taxes – Non-current liabilities		125,034			113,613			11,421
Shareholders’ equity		312,779			285,128			27,651
As of December 31, 2006
Property, plant and equipment	$	702,726		$	702,262		$	464
Accumulated depreciation, depletion and amortization		(186,316	)		(224,916	)		38,600
Total property, plant and equipment, net		516,410			477,346			39,064
Accrued interest, payroll and taxes		5,327			4,578			749
Deferred income taxes – Non-current liabilities		120,848			106,953			13,895
Shareholders’ equity		313,591			289,171			24,420

Note 12. Subsequent Event

In May 2007, we reached an agreement to pay approximately $27 million to divest our interest in a pipeline capacity contract. We expect this transaction to close in June 2007.

11

SCHEDULE OF REVENUE, ROYALTY INCOME, ROYALTIES AND
OPERATING EXPENSES OF THE ACQUIRED ASSETS

Schedule of Revenue, Royalty Income, Royalties and Operating Expenses

BIRCHWAVY PROPERTIES

For the years ended December 31, 2006 and 2005

Deloitte & Touche LLP
3000 Scotia Centre
700 Second Street S.W.
Calgary AB T2P 0S7
Canada

Tel: (403) 267-1700
Fax: (403) 264-2871
www.deloitte.ca

Auditors’ Report

To the Directors of
Dominion Resources, Inc.:

We have audited the schedule of revenue, royalty income, royalties and operating expenses of the Birchwavy Properties for each of the years in the two year period ended December 31, 2006. This financial information is the responsibility of the management of Dominion Resources, Inc. Our responsibility is to express an opinion on this financial information based on our audits.

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

In our opinion, this schedule presents fairly, in all material respects, the revenue, royalty income, royalties and operating expenses of the Birchwavy Properties as described in the notes to the schedule for each of the years in the two year period ended December 31, 2006 in accordance with accounting principles generally accepted in Canada and the United States of America.

Calgary, Alberta
May 18, 2007	Chartered Accountants

BIRCHWAVY PROPERTIES

Schedule of Revenue, Royalty Income, Royalties and Operating Expenses
(Expressed in thousands and in Canadian dollars)

	Three Months Ended
	March 31,				Years Ended December 31,
	2007		2006		2006		2005
	(unaudited)
Production revenue	28,817		32,877		104,901		129,733
Royalty income	2,534		2,818		9,273		10,686
Total revenue	31,351		35,695		114,174		140,419
Royalties	(5,355	)	(6,340	)	(17,902	)	(24,647	)
Operating expenses	(8,335	)	(6,898	)	(28,193	)	(24,888	)
Net operating income	17,661		22,457		68,079		90,884

See accompanying notes.

BIRCHWAVY PROPERTIES

Notes to the Schedule of Revenue, Royalty Income, Royalties and Operating Expenses
For the three month periods ended March 31, 2007 and 2006 and 
the years ended December 31, 2006 and 2005
(Information for the periods ended March 31, 2007 and 2006 is unaudited)

This schedule includes only those revenues, royalties and operating expenses that are directly related to the Birchwavy Properties being offered for sale by Dominion Resources, Inc. and does not include any expenses related to general and administrative costs, interest, income or capital taxes, or any provisions related to depletion, depreciation, asset retirement obligations or any hedging gains or losses.

1.	OIL AND GAS PRODUCTION REVENUE
	Oil and gas production revenue consists primarily of working interest sales of produced natural gas, natural gas liquids, oil and condensate. Revenues are recorded when title to the commodity passes to the purchaser. Revenues do not include any amounts from hedging with financial instruments.
2.	ROYALTY INCOME
	Royalty income consists primarily of royalty interest sales of produced natural gas, natural gas liquids, oil and condensate. Royalty income is recorded in the same period as the related revenue and is calculated in accordance with the terms of the royalty agreement.
3.	ROYALTIES
	Royalties includes crown, freehold and overriding royalties associated with the working interest sales of produced natural gas, natural gas liquids, oil and condensate. Royalties are recorded in the same period as the related revenue and are calculated in accordance with applicable regulations and or terms of royalty agreements.
4.	OPERATING EXPENSES
	Operating expenses include all costs related to the lifting, gathering, transporting and processing of crude oil and natural gas and related products.
5.	DIFFERENCE BETWEEN UNITED STATES AND CANADIAN GENERALLY ACCEPTED ACCOUNTING PRINCIPLES
	This financial information has been prepared in accordance with Canadian generally accepted accounting principles. These principles as they pertain to this financial information are substantially consistent with United States generally accepted accounting principles.

C-1

CERTIFICATE OF THE TRUST

Dated: June 12, 2007

This short form prospectus, together with the documents incorporated herein by reference, constitutes full, true and plain disclosure of all material facts relating to the securities offered by this short form prospectus as required by the securities legislation of each of the Provinces of Canada. For the purpose of the Province of Québec, this simplified prospectus, together with documents incorporated herein by reference and as supplemented by the permanent information record, contains no misrepresentation that is likely to affect the value or the market price of the securities to be distributed.

PARAMOUNT ENERGY TRUST
BY PARAMOUNT ENERGY OPERATING CORP.
(as its agent and attorney in fact)

By:	"Susan L. Riddell-Rose"	By:	"Cameron R. Sebastian"
	Susan Riddell Rose – President and Chief Executive		Cameron R. Sebastian – Vice President,
	Officer		Finance and Chief Financial Officer

ON BEHALF OF THE BOARD OF DIRECTORS OF PARAMOUNT ENERGY OPERATING CORP.

By:	"Clayton H. Riddell"	By:	"John W. Peltier"
	Clayton H. Riddell – Executive Chairman and Director		John W. Peltier – Director

C-2

CERTIFICATE OF THE UNDERWRITERS

Dated: June 12, 2007

To the best of our knowledge, information and belief, this short form prospectus, together with the documents incorporated herein by reference, constitutes full, true and plain disclosure of all material facts relating to the securities offered by this prospectus as required by the securities legislation of each of the Provinces of Canada. For the purpose of the Province of Québec, to our knowledge, this simplified prospectus, together with documents incorporated herein by reference and as supplemented by the permanent information record, contains no misrepresentation that is likely to affect the value or the market price of the securities to be distributed.

BMO NESBITT BURNS INC.

By: "Shane C. Fildes"
Shane C. Fildes

SCOTIA CAPITAL INC.

By: "Brett Undershute"
Brett Undershute

CIBC WORLD MARKETS INC.

By: "Michael W. de Carle"
Michael W. de Carle

TD SECURITIES INC.

By: "Alec W. G. Clark"
Alec W. G. Clark

NATIONAL BANK FINANCIAL INC.

By: "Dion Degrand"
Dion Degrand

RBC DOMINION SECURITIES INC.

By: "Robi Contrada"
Robi Contrada

FIRSTENERGY CAPITAL CORP.

By: "John S. Chambers"
John S. Chambers

GMP SECURITIES L.P.

By: "Sandy L. Edmonstone"
Sandy L. Edmonstone

RAYMOND JAMES LTD.

By: "Edward J. Bereznicki"
Edward J. Bereznicki

BLACKMONT CAPITAL INC.

By: "John Peltier"
John Peltier

CANACCORD CAPITAL	CORMARK SECURITIES	DUNDEE SECURITIES	PETERS & CO. LIMITED
CORPORATION	INC.	CORPORATION
By: "Timothy J. Hart"	By: "Ron A. MacMicken"	By: "Sheldon McDonough"	By: "Cameron Plewes"
Timothy J. Hart	Ron A. MacMicken	Sheldon McDonough	Cameron Plewes