As filed with the Securities and Exchange Commission on November 6, 2002

Registration No.: 333-98233

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Amendment No. 1
to
Form F-1

REGISTRATION STATEMENT UNDER THE SECURITIES ACT OF 1933

PARAMOUNT ENERGY TRUST

(Exact name of Registrant as specified in its charter)

Alberta, Canada	1311	N/A
(State or other jurisdiction of incorporation or organization)	(Primary Standard Industrial Classification Code Number)	(I.R.S. Employer Identification No.)

500, 630 – 4th Avenue S.W., Calgary, Alberta, T2P 0J9
(403) 269-4400

(Address, including zip code, and telephone number, including area code, of Registrant’s principal executive offices)

John K. Whelan, Esq.
Carter, Ledyard & Milburn
2 Wall Street, New York, New York 10005
(212) 238-8810

(Name, address, including zip code, and telephone number, including area code, of agent for service)

Copy to:

Susan L. Riddell Rose	Kurtis T. Kulman, Esq.	Kevin Keogh, Esq.
Paramount Energy Operating Corp.	Gowling Lafleur Henderson LLP	White & Case LLP
500, 630 – 4th Avenue S.W.	1400 Scotia Centre	1155 Avenue of the Americas
Calgary, Alberta T2P 0J9	700 – 2nd Street S.W.	New York, NY 10036-2787
Canada	Calgary, Alberta T2P 4V5	(212) 819-8200
(403) 269-4444	Canada
	(403) 298-1000

Approximate date of commencement of proposed sale to the public... as soon as practicable after this Registration Statement becomes effective.

If any of the securities being registered on this Form are to be offered on a delayed or continuous basis pursuant to Rule 415 under the Securities Act, check the following box. [X]

If this Form is filed to register additional securities for an offering pursuant to Rule 462(b) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering. [  ]

If this Form is a post-effective amendment filed pursuant to Rule 462(c) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering. [  ]

If this Form is a post-effective amendment filed pursuant to Rule 462(d) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering. [  ]

If delivery of the prospectus is expected to be made pursuant to Rule 434, please check the following box. [  ]

The registrant hereby amends this registration statement on such date or dates as may be necessary to delay its effective date until the registrant shall file a further amendment which specifically states that this registration statement shall thereafter become effective in accordance with section 8(a) of the Securities Act of 1933 or until the registration statement shall become effective on such date as the Commission, acting pursuant to said section 8(a), may determine.

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The information in this Prospectus is not complete and may be changed. These securities may not be sold until the registration statement filed with the Securities and Exchange Commission and every state is effective. These securities shall not be sold nor shall offers to buy be accepted prior to the time the prospectus is delivered in final form. Under no circumstances shall this preliminary prospectus constitute an offer to sell or the solicitation of an offer to buy nor shall there be any sale of these securities in any state in which such offer, solicitation, or sale is unlawful prior to registration or qualification under the securities laws of any such state.

PRELIMINARY PROSPECTUS dated November 6, 2002 (Subject to Completion)

39,639,068 Trust Units

29,729,301 Rights to Purchase Trust Units

         This is our initial public offering. We have applied for listing of our Trust Units and Rights on the Toronto Stock Exchange (the “TSX”). At the date of this Prospectus, there was no public market for the Trust Units or the Rights. The TSX has conditionally approved the listing of these securities subject to our fulfilling all of the requirements of the TSX on or before January 30, 2003, including distribution of these securities to a minimum number of public security holders.

         Investing in the Trust Units involves significant risks. These risks are described under the caption “Risk Factors” beginning on page 19.

         This prospectus relates to the distribution by Paramount Resources Ltd. (“PRL”) as a dividend (the “Dividend”) to the holders of its common shares of approximately 9,909,767 units of beneficial interest (“Trust Units”) of Paramount Energy Trust (“PET”). It also relates to the distribution by PET, shortly thereafter, to holders of Trust Units of rights to purchase Trust Units (the “Rights”) and the offer and sale of the Trust Units issuable upon the exercise of the Rights (the “Rights Offering”).

         If none of the Rights is exercised, there will be no proceeds to PET. The following table sets forth certain information assuming that all of the Rights are exercised.

	Per Unit	Total
Exercise Price of Rights	CDN$5.05	CDN$150,132,970
Proceeds to PET(1)	CDN$5.016	CDN$149,132,970
Soliciting Dealer Fees(2)	CDN$0.05	CDN$750,000

(1)  After deducting expenses payable by PET estimated at CDN$1,000,000 but before payment of Soliciting Dealers’ fees estimated at CDN$750,000. In addition, PET has agreed to indemnify the Dealer Managers against certain liabilities including liabilities under the Securities Act of 1933, as amended (the “Securities Act”), and applicable Canadian securities legislation. See “Plan of Distribution, page 84.” (2)  We have entered into a dealer manager agreement (the “Dealer Manager Agreement”) with BMO Nesbitt Burns Inc., CIBC World Markets Inc. and FirstEnergy Capital Corp. (the “Dealer Managers”) under which they will form a soliciting dealer group (the “Soliciting Dealer Group”) to solicit subscriptions for Trust Units. We will pay to a member of the Soliciting Dealer Group a subscription fee of $0.05 per Trust Unit for each Trust Unit PET issues to a holder of Rights (a “Rightsholder”) who identifies that member in the subscription form. We will not pay less than $90 or more than $1,500 in respect of subscriptions on behalf of any one Rightsholder nor will we pay for the exercise of less than 1,500 Rights by any one Rightsholder or for the exercise of Rights beneficially owned, directly or indirectly, or over which control or direction is exercised by Paramount Oil & Gas Ltd. (“POG”) or any directors or officers of Paramount Resources Ltd. (“PRL”) or Paramount Energy Operating Corp. (the “Administrator”). The total discount and commission with respect to the exercise of Rights by a Rightsholder will not exceed 1% of the proceeds received by us. We estimate that the maximum possible fees payable in respect of the exercise of Rights will be $750,000 based upon the foregoing. See “Plan of Distribution”, page 84.

         NEITHER THE SECURITIES AND EXCHANGE COMMISSION NOR ANY STATE SECURITIES COMMISSION HAS APPROVED OR DISAPPROVED OF THE SECURITIES OFFERED HEREBY, OR DETERMINED IF THIS PROSPECTUS IS TRUTHFUL OR COMPLETE. ANY REPRESENTATION TO THE CONTRARY IS A CRIMINAL OFFENSE. IN MAKING AN INVESTMENT DECISION INVESTORS MUST RELY ON THEIR OWN EXAMINATION OF THE ISSUER AND THE TERMS OF THE OFFERING, INCLUDING THE MERITS AND RISKS INVOLVED.

         Residents of Alaska, Arizona, the District of Columbia, New Mexico and North Dakota should review the pages immediately following this cover page for important information relating to our offering of securities in your jurisdiction.

CIBC World Markets Corp. BMO Nesbitt Burns Corp. FirstEnergy Capital (USA) Corp.

Prospectus dated •, 2002

         The financial statements included herein have been prepared in accordance with Canadian generally accepted accounting principles. A reconciliation to United States generally accepted accounting principles appears in note 6 to the Paramount Resources Ltd. — Northeast Alberta Properties Financial Statements.

         Owning PET Trust Units may subject you to tax consequences both in the United States and in Canada. See “Certain Tax Considerations.” This Prospectus may not describe these tax consequences fully. You should consult your own tax advisor with respect to your own particular circumstances.

         Rights may be exercised only by persons who are residents of Canada or the United States, excluding residents of the State of Florida, and any Rights that are not exercised before 4:30 p.m. (Calgary time) on •, 2002 will be void and will have no value. This prospectus is prepared for the use of United States residents only. See “Important Notice to Persons in Canada”, page 3.          In connection with the offering, and in accordance with applicable laws, the Dealer Managers may effect transactions which stabilize or maintain the market price of the Trust Units at levels other than those which might otherwise prevail on the open market. Such transactions, if commenced, may be discontinued at any time. For a description of these activities, see “Plan of Distribution”, page 85.

         You should rely only on the information contained in this prospectus. We have not authorized anyone to provide you with different information. We are not making an offer of these securities in any jurisdiction where the offer is not permitted. You should not assume that the information in this prospectus is accurate as of any date other than the date on the front of this prospectus.

         Unless the context otherwise requires, all references in this Prospectus to PET, as well as the terms “we”, “us”, and “our”, refer to Paramount Energy Trust (“PET”) and its wholly-owned subsidiaries Paramount Operating Trust (“POT”) and Paramount Energy Operating Corp. (the “Administrator”), collectively.

For Residents of Alaska

REGISTRATION OF THE SECURITIES FOR SALE IN ALASKA IS DEPENDENT ON COMPLIANCE WITH THE ALASKA SECURITIES ACT (AS 45.55). THEREFORE, THERE CAN BE NO ASSURANCE THAT THE SECURITIES WILL BE REGISTERED FOR SALE IN ALASKA.

For Residents of Arizona

THE ISSUER HAS NOT BEEN IN THE BUSINESS PROVIDED IN THE PROSPECTUS FOR AT LEAST THREE YEARS.

THE VALUE OF THE SECURITY OFFERED IS MATERIALLY DEPENDENT ON THE FULFILLMENT OR ACCOMPLISHMENT OF A FUTURE CONDITION, PROMOTION, OR DEVELOPMENT INSTEAD OF THE ISSUER’S PRESENT TANGIBLE ASSETS OR CONDITIONS.

THESE SECURITIES ARE ISSUED AS PART OF A PROJECT OR PLAN FOR THE SALE, DEVELOPMENT, OR EXPLORATION OF ANY INTEREST IN UNIMPROVED OR UNDEVELOPED LAND, OIL GAS, OR OTHER MINERAL RIGHT. THIS INVESTMENT INVOLVES A HIGH DEGREE OF RISK. YOU SHOULD PURCHASE THESE SECURITIES ONLY IF YOU CAN AFFORD A COMPLETE LOSS OF YOUR INVESTMENT.

For Residents of the District of Columbia

THESE SECURITIES ARE OFFERED FOR SALE IN THE DISTRICT OF COLUMBIA PURSUANT TO REGISTRATION WITH THE DISTRICT OF COLUMBIA DEPARTMENT OF INSURANCE AND SECURITIES REGULATION, BUT REGISTRATION IS PERMISSIVE ONLY AND DOES NOT

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CONSTITUTE A FINDING THAT THIS PROSPECTUS IS TRUE, COMPLETE, AND NOT MISLEADING, NOR HAS THE DEPARTMENT OF INSURANCE AND SECURITIES REGULATION PASSED IN ANY WAY UPON THE MERITS OF, RECOMMENDED, OR GIVEN APPROVAL TO THESE SECURITIES. ANY REPRESENTATION TO THE CONTRARY IS A CRIMINAL OFFENSE.

For Residents of New Mexico

THESE SECURITIES HAVE NOT BEEN APPROVED OR DISAPPROVED BY THE SECURITIES AND EXCHANGE COMMISSION OR THE SECURITIES DIVISION OF THE NEW MEXICO DEPARTMENT OF REGULATION AND LICENSING, NOR HAS THE SECURITIES AND EXCHANGE COMMISSION OR THE SECURITIES DIVISION PASSED UPON THE ACCURACY OR ADEQUACY OF THIS PROSPECTUS. ANY REPRESENTATION TO THE CONTRARY IS A CRIMINAL OFFENSE.

For Residents of North Dakota

A REGISTRATION STATEMENT RELATING TO THESE SECURITIES HAS BEEN FILED BUT HAS NOT YET BECOME EFFECTIVE. INFORMATION CONTAINED HEREIN IS SUBJECT TO COMPLETION OR AMENDMENT. THESE SECURITIES MAY NOT BE SOLD NOR MAY OFFERS TO BUY BE ACCEPTED PRIOR TO THE TIME THE REGISTRATION STATEMENT BECOMES EFFECTIVE. THIS PROSPECTUS SHALL NOT CONSTITUTE AN OFFER TO SELL OR THE SOLICITATION OF AN OFFER TO BUY NOR SHALL THERE BE ANY SALE OF THESE SECURITIES IN ANY STATE IN WHICH SUCH OFFER, SOLICITATION, OR SALE WOULD BE UNLAWFUL PRIOR TO REGISTRATION OR APPROVAL UNDER THE SECURITIES LAWS OF ANY SUCH STATE.

EXCHANGE RATE TABLE

         Except as otherwise indicated, all dollar amounts set forth in this prospectus are expressed in Canadian dollars. The following tables set forth (i) the rates of exchange for Canadian dollars, expressed in United States dollars, in effect at the end of each of the periods indicated; (ii) the average of exchange rates in effect on the last day of each month during such periods; (iii) the high and low exchange rates during each such periods; and (iv) the high and low exchange rates for each of the previous six months, in each case based on the noon buying rate in New York City for cable transfers in Canadian dollars as certified for customs purposes by the Federal Reserve Bank of New York.

	For the 6 months ended		Year ended December 31,
	June 30, 2002		2001		2000		1999		1998		1997
Rate at end of period	$	0.6583	$	0.6279	$	0.6669	$	0.6925	$	0.6504	$	0.6999
Average rate during period		0.6378		0.6444		0.6725		0.6745		0.6714		0.7197
High		0.6619		0.6697		0.6969		0.6925		0.7105		0.7487
Low		0.6200		0.6241		0.6410		0.6535		0.6341		0.6945

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	Previous Six Months (2002)
	October		September		August		July		June		May
High	$	0.6407	$	0.6433	$	0.6442	$	0.6603	$	0.6619	$	0.6547
Low		0.6272		0.6304		0.6265		0.6297		0.6452		0.6366

On November 4, 2002 the noon buying rate for $1.00 Canadian was $0.6426 United States.

IMPORTANT NOTICE TO PERSONS IN CANADA

         We have prepared this prospectus only for the distribution of our securities in the United States. We are qualifying the distribution of these securities under the securities legislation of each of the provinces and territories in Canada by way of a separate prospectus which complies with the requirements of that securities legislation (the “Canadian Prospectus”) for delivery to persons in Canada. This U.S. prospectus includes certain information that may not be included in the Canadian Prospectus. If you are in Canada, you cannot rely on this prospectus and you should contact Computershare Trust Company of Canada at 100 University Avenue, 9th Floor, Toronto, Ontario, M5J 2Y1, telephone (416) 981-9633, toll free 1-800-564-6253, to request that a copy of the Canadian Prospectus be delivered to you.

ENFORCEABILITY OF CIVIL LIABILITIES

         Your ability to enforce civil liabilities under the United States federal securities laws may be affected adversely by the fact that we, PRL and the Dealer Managers are organized under and governed by the laws of Canada, that all of our directors and officers as well as certain of those of PRL reside outside the United States, that the Dealer Managers and the experts named in this prospectus are residents of Canada, and that all or substantially all of our and PRL’s assets are, and the assets of such persons may be, located outside the United States. As a result, you may not be able to:

• effect service of process upon us, PRL or such persons within the United States; or

• enforce against us, PRL or such persons in Canadian courts judgments obtained in United States courts based solely upon the civil liability provisions of such United States federal securities laws; or

• bring an original action in Canada against us, PRL or such persons, to enforce liabilities based solely upon the United States federal securities laws.

See “Risk Factors”, page 28.

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TABLE OF CONTENTS

FORM F-1/A

FORM OF INITIAL ASSETS PURCHASE AGREEMENT

FORM OF TAKE-UP AGREEMENT

FORM OF PROMISSORY NOTE

FORM OF GUARANTEE

FORM OF GUARANTEE

OPINION OF GOWLING LAFLEUR HENDERSON LLP

OPINION OF FELESKY FLYNN LLP

OPINION OF STIKEMAN ELLIOTT

OPINION OF CARTER, LEDYARD & MILBURN

EMPLOYMENT AGREEMENT

FIRST AMENDING AGREEMENT

EMPLOYMENT AGREEMENT

EMPLOYMENT AGREEMENT

EMPLOYMENT AGREEMENT

EMPLOYMENT AGREEMENT

CONSENT OF KPMG LLP

AWARENESS LETTER OF KPMG LLP

CONSENT OF MCDANIEL & ASSOCIATES LTD.

TABLE OF CONTENTS

	Page
Exchange Rate Table		3
Important Notice to Persons in Canada		4
Enforceability of Civil Liabilities		4
Certain Oil and Gas Terms		6
Certain Conventions that apply to this Prospectus		6
Cautionary Statement Regarding Forward-Looking Statements		7
Prospectus Summary		8
Risk Factors		20
Formation of Trust Structure and Structuring Transactions		29
Plan of Operations		36
Trends		37
Future Development		38
Selected Financial Data and Financial and Production Information		39
Selected Pro Forma Financial and Production Information		40
Management’s Discussion and Analysis and Liquidity and Capital Resources		41
Use of Proceeds		56
PET’s Consolidated Capitalization		57
Prior Issuance of PET Units		58
Initial Business and Properties of POT		58
Details of the Dividend		64
Bank Financing and Guarantees		65
Details of the Rights Offering		66
How to Exercise the Rights		71
Business and Properties Relating to the Additional Assets		73
Plan of Distribution		85
Description of the Trust Units and Special Voting Units		86
The PET Trust Indenture		91
The POT Trust Indenture		98
The POT Royalty Agreement		100
The Administrator		102
Unit Incentive Plan		108
Distribution Reinvestment and Optional Unit Purchase Plan		109
Principal Holders of Securities		109
Government Regulations		111
Certain Canadian Federal Income Tax Considerations		113
Certain United States Federal Income Tax Considerations		116
Relationship Between PET, POT and PRL and the Dealer Managers and Financial Advisor		122
Promoter		123
Experts		123
Conflicts of Interest		123
Interests of Insiders and Others in Material Transactions		124
Legal Proceedings		124
Auditors, Registrar and Transfer Agent		124
Legal matters		124
Where You Can Find More Information		125
Index to Consolidated Financial Statements		F-1
Index To Paramount Resources Ltd. — Northeast Alberta Properties Financial Statements		F-1
Index to Pro Forma Financial Statements		F-1
Fairness Opinion		A-1

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CERTAIN OIL AND GAS TERMS

         In this prospectus, the abbreviations set forth below have the following meanings:

“bcf”	1,000,000,000 cubic feet	“Mmbtu”	1,000,000 British Thermal Units
“mcf”	1,000 cubic feet	“mmcf”	1,000,000 cubic feet
“mcf/d”	1,000 cubic feet per day	“mmcf/d”	1,000,000 cubic feet per day
“GJ”	Gigajoule

Note: For the purposes of this prospectus, 6 mcf of natural gas and 1 barrel of natural gas liquids each equal 1 barrel of oil, such conversion not being based on either price or energy content.

CERTAIN CONVENTIONS THAT APPLY TO THIS PROSPECTUS

         In this prospectus, the capitalized terms set forth below have the following meanings:

“business day” means a day, other than a Saturday, Sunday or statutory holiday in the Province of Alberta or any other day on which banks in Calgary, Alberta are not open for business;

“CCRA” means the Canada Customs and Revenue Agency;

“Canadian GAAP” means Canadian generally accepted accounting principles;

“Dealer Manager Agreement” means the dealer manager agreement entered into among PET, POT, PRL and the Administrator and the Dealer Managers dated August 8, 2002 under which the Dealer Managers have agreed to organize a soliciting dealer group, the members of which will solicit the exercise of Rights pursuant to the Rights Offering;

“Dealer Managers” means BMO Nesbitt Burns Inc., CIBC World Markets Inc. and FirstEnergy Capital Corp.;

“McDaniel Report” means the independent engineering evaluation conducted by McDaniel & Associates Consultants Ltd., independent oil and gas reservoir engineers of Calgary, Alberta, of the Initial Assets and Additional Assets, set out in a report dated October 15, 2002 based on constant pricing as at July 1, 2002.

“Royalties” means, collectively, all royalties payable by any entity to PET, including the POT Royalty;

“Royalty Rate” means royalties paid to mineral owners, expressed as a percentage of revenues;

“Soliciting Dealer Group” means the soliciting dealer group formed by the Dealer Managers to solicit subscriptions for Trust Units under the Rights Offering;

“Transfer Agent” means Computershare Trust Company of Canada in its capacity as registrar and transfer agent of the Trust Units;

“Trust Structuring” means the series of transactions pursuant to which; (i) PRL will convey the Initial Assets to POT pursuant to the Sale Agreement; (ii) PRL and POT will enter into the Take-Up Agreement; (iii) the POT Royalty will be granted by POT to PET; and (iv) all Trust Units to be held by PRL and later distributed by PRL to PRL Shareholders pursuant to the Dividend will be issued by PET to PRL, all as further described in “Formation of Trust Structure and Structuring Transactions”;

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

“U.S. GAAP” means United States generally accepted accounting principles;

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“$” and “Cdn$” mean Canadian dollars, “U.S.$” means U.S. dollars and “M$” and “$000” means thousands of Canadian dollars.

         In this prospectus, unless otherwise noted, all dollar amounts are expressed in Canadian currency.

CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS

         This prospectus includes “forward-looking statements” which generally relate to future events or our future performance. In some cases, you can identify forward-looking statements by terminology such as “may”, “will”, “should”, “expect”, “plan”, “anticipate”, “believe”, “estimate”, “predict”, “potential” or the negative of these terms or other comparable terminology. All statements (other than statements of historical fact) included in this prospectus that address activities, events or developments that we expect or anticipate will or may occur in the future, including such matters as changes in commodity prices, future capital expenditures, the proposed acquisitions by us of certain assets from PRL as detailed in this prospectus, business strategies and measures to implement our operations, our plans and references to our future success and other such matters are forward-looking statements. These statements are only predictions. Actual events or results may differ materially. These statements are based upon certain assumptions and analyses we made based on our management’s experience and perception of historical trends, current conditions and expected future developments, as well as other factors we believe are appropriate in the circumstances. Whether or not actual results and developments will conform with our expectations and predictions, however, is subject to a number of risks and uncertainties, including the special considerations discussed in this prospectus, general economic, market or business conditions and the presence or lack of business opportunities. See “Risk Factors”, page 20. Consequently, all the forward-looking statements made in this prospectus are qualified by these cautionary statements, and there can be no assurance that the actual results or developments we anticipate will be realized or, even if substantially realized, that they will result in the expected consequences to, or have the expected effects on, our businesses or operations. We are under no duty to update any of the forward-looking statements after the date of this prospectus to conform such statements to actual results or to a change in our expectations.

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PROSPECTUS SUMMARY

         This is only a summary and does not contain all information that may be important to you. You should read this entire prospectus, including “Risk Factors”, which begin on page 20, before making an investment decision about our Trust Units. For a discussion of industry terms, see “Certain Oil and Gas Terms ” on page 6. For capitalized terms not otherwise defined in this summary or elsewhere herein see “Certain Conventions that apply to this Prospectus” on page 6.

Risk Factors

         An investment in the Trust Units is subject to a number of risks. As the Trust Units do not represent a traditional investment in the oil and natural gas industry, you should carefully consider all of the information set forth in this prospectus. The Trust Units are subject to risk factors typical to an investment in the oil and natural gas industry such as shut-in of production, management’s success in developing additional reserves, marketability of production, title defects, environmental concerns, reserve figures being estimates, availability of replacement reserves, availability of additional financing, operating risks, potential for write-downs and competition. In addition, a Trust Unit is unlike a traditional share equity interest in that it does not afford its owner the same statutory rights nor the same kind of limited liability applicable to holders of common shares. You should also be aware that if for any reason we are unable to use the proceeds of the Rights Offering to acquire an interest in the Additional Assets, you will need to rely on our ability to identify and acquire other oil and natural gas reserves. Moreover, since production from the Initial Assets and Additional Assets is entirely natural gas, the value of your Trust Units will be more subject to price fluctuations in natural gas pricing than investments in energy companies that are more diversified. See “Risk Factors”, page 20.

The Issuer

         We were formed at the instigation of Paramount Resources Ltd. (“PRL”), a Canadian public company, whose common shares are listed on the TSX, to own and develop certain oil and natural gas properties. We consist of three entities: Paramount Energy Trust (“PET”), an Alberta unincorporated trust which finances the operations of Paramount Operating Trust (“POT”), also an Alberta unincorporated trust of which PET is the sole beneficiary and which is an operating oil and natural gas entity, and Paramount Energy Operating Corp. (the “Administrator”), an Alberta corporation which is a wholly-owned subsidiary of PET, that provides certain operational, executive and financial services and governance functions for PET and is the trustee of POT. Unlike many conventional royalty trusts, we will not have an external management company. The day-to-day running of our business will be carried out by the Administrator, rather than a third party, as is the case in many conventional royalty trusts. We will therefore not incur management fees and expenses that would be charged by an external management company. Much like a traditional oil and gas corporation, only costs incurred by or on behalf of the Administrator to operate our business will ultimately be borne by the holders of Trust Units (the “Unitholders”). See the diagram on page 36.

Headquarters

         Our principal executive offices are located at 500, 630 – 4th Avenue S.W., Calgary, Alberta, T2P 0J9, telephone: (403) 269-4400.

The Business

         PRL is a Canadian oil and gas exploration and production company incorporated in 1978. PRL’s management decided, after consulting with its financial advisors, that the value of PRL to the holders of the common shares of PRL (the “PRL Shareholders”) may be enhanced if its operations were divided into two separate publicly traded vehicles. To that end, PET was created to hold through POT, certain mature natural gas assets in northeastern Alberta, most of which PRL has owned and operated for several years. Trust Units initially held by PRL will be paid as the Dividend, transferring ownership of PET to the PRL Shareholders. Immediately after the Dividend, the PRL Shareholders will own:

• Common shares of PRL (the “PRL Common Shares”), a growth-oriented petroleum and natural gas exploration and production company; and

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• Trust Units of PET, an income-oriented royalty and income trust.

The Trust Structuring

         Through a series of transactions (the “Trust Structuring”), PRL will convey to POT the entire right, title and interest of PRL in the oil and natural gas properties and related assets provided for under the terms of an agreement to be entered into effective July 1, 2002, between PRL and POT (the “Sale Agreement”) and as described under “Initial Business and Properties of POT — Principal Property — Legend, Alberta” (the “Initial Assets”). We will receive all the benefits of and assume all risks on the Initial Assets, and revenues and expenses associated with the Initial Assets will accrue to POT for POT’s account, as of July 1, 2002. See “Initial Business and Properties of POT — Principal Property — Legend, Alberta”. PRL and POT will also execute an agreement (the “Take-Up Agreement”) which will, subject to certain terms and conditions, entitle and obligate POT to acquire from PRL, up to 100% of PRL’s interest in the oil and natural gas properties and related assets provided for under the terms of the Take-Up Agreement (the “Additional Assets”) and described under “Business and Properties Relating to the Additional Assets - Additional Assets”. We will receive all the benefits of and assume all risks on the Additional Assets POT acquires, and revenues and expenses associated with the interest in the Additional Assets POT acquires will accrue to POT for POT’s account, as of July 1, 2002. The closing of such acquisition is subject to certain terms and conditions. See “Business and Properties Relating to the Additional Assets — Additional Assets”, page 73.          Under an agreement to be entered into between PET and POT (the “POT Royalty Agreement”), POT will grant the POT Royalty (as defined below) to PET with respect to the Initial Assets, the Additional Assets (to the extent POT acquires them) and all other petroleum and natural gas properties POT may acquire from time to time. Pursuant to the POT Royalty Agreement, PET will receive 99% of POT’s net revenue from its petroleum and natural gas properties from time to time, less permitted deductions with respect to debt payments, capital expenditures and certain other amounts (the “POT Royalty”). As part of the above transactions PET will issue Trust Units to PRL which PRL will then distribute to PRL Shareholders by way of a dividend (the “Dividend”). After the Dividend, PET will commence the issuance and distribution of the Rights (the “Rights Offering”). See “Formation of Trust Structure and Structuring Transactions”, page 29.

THE TRUST UNITS

Trust Units:	Each Trust Unit is transferable, entitles the Unitholder to participate equally in distributions of PET, is not subject to future calls or assessments, and entitles the Unitholder to certain rights of redemption and to one vote at all meetings of Unitholders. See “Description of the Trust Units and Special Voting Units”, page 86.
Distribution Policy of PET:	PET intends to make cash distributions on the 15th day of each month (or the next business day if the 15th is not a business day) to Unitholders of record as at the close of business on the last day of the immediately preceding month. Cash distributions will generally be comprised of royalty and interest income PET receives from POT with respect to the immediately preceding month less expenses and any other amounts it must withhold or pay to third parties. Cash distributions may also include other distributable amounts such as the net proceeds from the sale of the POT Royalty attributable to any of the Initial Assets, Additional Assets or other petroleum or natural gas properties. See “Formation of Trust Structure and Structuring Transactions — PET, POT and the Administrator”, page 32 and “The POT Royalty Agreement”, page 100.
	We expect to make an initial distribution of distributable income of PET for the period from •, 2002 to •, 2002 to Unitholders of record on •, 2003 and we expect to pay the cash distribution on •, 2003. Cash flow from the Initial Assets and the acquired portion of the Additional Assets prior to •, 2002 will not be distributed to Unitholders but will be used to fund certain of our expenses, to fund the acquisition of a further interest in the Additional Assets, if necessary, and for

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working capital purposes. See “Management’s Discussion and Analysis and Liquidity and Capital Resources — Liquidity and Capital Resources”, page 53.

THE DIVIDEND

The Dividend:	PRL will distribute as a dividend-in-kind on outstanding PRL Common Shares of record at 4:30 p.m. (Calgary time) on • , 2002, (the “Dividend Record Date”) all of the Trust Units held by PRL at that time (the “Dividend Units”) (the “Dividend”). There are currently 59,458,600 PRL Common Shares outstanding, which would entitle PRL Shareholders to receive one Dividend Unit for every 6 PRL Common Shares held by them. We anticipate there will be up to 784,000 vested stock options of PRL outstanding at the Dividend Record Date entitling holders thereof to acquire up to an additional 784,000 PRL Common Shares. In the event that any or all of those options are exercised on or prior to the Dividend Record Date, the number of PRL Common Shares necessary to receive one Dividend Unit will increase from 6 to a maximum of 6.079 PRL Common Shares. We and PRL propose to issue a press release on the Dividend Record Date giving notice of what this ratio will be. Except as otherwise indicated in this prospectus we have assumed one Dividend Unit will be issued for each 6 PRL Common Shares. No fractional Trust Units will be distributed. After the Dividend Units are distributed, PRL will not own any Trust Units. PRL has advised that Dividend Units distributed to PRL Shareholders who are not residents of Canada will be withheld and a portion thereof sold to fund certain Canadian withholding tax obligations applicable to the Dividend. Any remaining Dividend Units will then be delivered to such persons. See “Formation of Trust Structure and Structuring Transactions”, page 29 and “Details of the Dividend”, page 64.
Dividend Record Date:	4:30 p.m. Calgary time on •, 2002.
Listing of Units:	There is currently no market through which the Trust Units may be sold. An application has been made to the TSX for the approval of the listing of the Dividend Units. The TSX has conditionally approved the listing of these securities subject to our fulfilling all of the requirements of the TSX on or before January 30, 2003, including distribution of the Dividend Units to a minimum number of public security holders.

THE RIGHTS OFFERING

The Rights Offering:	PET will issue, to the holders of Trust Units on the Rights Record Date, Rights to subscribe for additional Trust Units on the basis of three (3) Rights for each Trust Unit held. See “Details of the Rights Offering — Issue of Rights and Rights Certificates”, page 67.
Rights Record Date:	4:30 p.m. Calgary time on •, 2002 (the “Rights Record Date”)
Issue:	Rights to subscribe for up to 29,729,301 Trust Units.
Rights Expiry Time:	4:30 p.m. Calgary time on •, 2002 (the “Rights Expiry Time”)
Listing of Rights	There is currently no market through which the Rights may be sold. An application has been made to the TSX for the approval of the listing of the Rights and the Trust Units issuable on the exercise thereof. The TSX has conditionally approved the listing of these securities subject to our fulfilling all of the requirements of the TSX on or before January 30, 2003, including distribution of the Dividend Units to a minimum number of public security holders.
Rights Exercise Price:	$5.05 per Trust Unit (the “Rights Exercise Price”)

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Issue of Rights:	Each Right will entitle the holder thereof (the “Rightsholder”) to purchase one Trust Unit for the Rights Exercise Price at any time prior to the Rights Expiry Time (the “Initial Subscription Privilege”). See “Details of the Rights Offering — Issue of Rights and Rights Certificates”, page 67.
Eligible Persons:	Only persons resident in Canada or the United States, excluding residents of the State of Florida, may exercise the Rights. See “Details of the Rights Offering — Ineligible Persons”, page 68.
Gross Proceeds from the Rights Offering:	Up to $150,132,970.
Expenses of the Rights Offering:	PET estimates that its expenses relating to the Rights Offering will be $1,000,000 which will be paid out of general funds and not out of the proceeds of the Rights Offering.
Expiry of Rights:	You must exercise your Rights before the Rights Expiry Time or they will expire. See “Details of the Rights Offering — Issue of Rights and Rights Certificates”, page 67.
Additional Subscription Privilege:	If all of the Rights are not exercised under the Initial Subscription Privilege, each Rightsholder that has exercised all of its Rights may subscribe for additional Trust Units (the “Additional Subscription Privilege”). See “Details of the Rights Offering — Additional Subscription Privilege”, page 67.
Principal Unitholders:	Upon payment of the Dividend, the directors and senior officers of the Administrator will, as a group, beneficially own or exercise control or direction over, directly or indirectly, 4,840,859 Trust Units (48.85% of the then issued and outstanding Trust Units). None of these individuals have control or direction over greater than 10% of the PRL Common Shares except Clayton H. Riddell, the Chairman and Chief Executive Officer of the Administrator who, directly, and indirectly through Paramount Oil & Gas Ltd. (“POG”) and its subsidiaries, Treherne Resources Ltd. (“Treherne”) and 409790 Alberta Ltd. (“409790”), exercises control and direction over 28,943,770 PRL Common Shares (48.68% of the issued and outstanding PRL Common Shares) and will, immediately after payment of the Dividend, exercise control and direction over 4,823,961 Trust Units (48.68% of the issued and outstanding Trust Units). S.L. Riddell Rose, the President, Chief Operating Officer and a director of the Administrator, is also a shareholder of POG. Assuming no exercise of outstanding PRL stock options occurs, upon payment of the Dividend, Mr. Riddell and his immediate family, including their spouses (the “C.H. Riddell Family”) will beneficially own or exercise control or direction over, directly or indirectly, 4,931,787 Trust Units (49.77% of the issued and outstanding Trust Units). PRL, C.H. Riddell, POG, Treherne and 409790 have entered into a Rights exercise agreement (“Rights Exercise Agreement”) with PRL’s lenders which obligates POG, Treherne and 409790 to exercise all Rights held by or on behalf of them thereby subscribing for all Trust Units available to them under the Initial Subscription Privilege of the Rights Offering. POG and its subsidiaries are required to provide evidence to PRL’s lenders of their financial ability to subscribe for such Trust Units. Under the terms of the Rights Exercise Agreement, POG, Treherne and 409790 represent that they have in place available bank financing which, when combined with an amount of $33,000,000 owing by PRL to POG, and other funds available to POG, Treherne and 409790, will be sufficient to allow these parties to acquire all of the Trust Units that will be available to them under the Initial Subscription Privilege for the Rights that they will receive. The funding of amounts under their credit arrangements are conditional upon a number of things, including the provision by POG, Treherne and 409790 to their lenders of sufficient collateral. In the event

11

	that POG, Treherne and 409790 are unable to draw down the required amounts under these facilities, or PRL is not in a position to pay to POG the full amount that PRL owes to POG, POG, Treherne and 409790 may not be able to exercise all of their Rights. The C.H. Riddell Family has indicated its intention to fully subscribe under the Initial Subscription Privilege of the Rights Offering, which will result in them holding an aggregate of 19,727,148 Trust Units. Thus, to the extent that other Rightsholders do not exercise their Rights, the C.H. Riddell Family will increase its percentage of ownership of PET. Additionally, the C.H. Riddell Family may acquire additional Trust Units by exercising their Additional Subscription Privilege or through the exercise of outstanding options in PRL held by them, which would further increase their percentage of ownership of PET.
	As at October 16, 2002, Fidelity Management & Research Company and Fidelity Management Trust Company (collectively “Fidelity”) are the beneficial owners of 5,352,000 PRL Common Shares (representing approximately 9.0% of the issued and outstanding PRL Common Shares) in accounts and funds managed by them. Fidelity will, upon payment of the Dividend, hold 892,000 Trust Units. We have not been advised of its intentions respecting its exercise of Rights. See “Details of the Rights Offering — Intentions of Insiders and Others to Exercise Rights”, page 69 , “Formation of the Trust Structure and Structuring Transactions — PET, POT and the Administrator”, page 32 and “Principal Holders of Securities”, page 109.
Decrease in Percentage Ownership:	Any Unitholder who does not exercise its Rights will experience a decrease in its percentage of ownership of PET. See “Details of the Rights Offering — Decrease in Percentage Ownership”, page 70.
No Standby Commitment:	There is no standby commitment to purchase Trust Units under the Rights Offering.
Use of Proceeds:	We will use the gross proceeds from the Rights Offering, along with available bank financing, to repay the $30,000,000 we will owe to PRL arising from the acquisition of the Initial Assets and to acquire all or a portion of PRL’s interest in the Additional Assets. If the Rights Offering is fully subscribed, and our lenders advance the full amount under our proposed credit facility, we will acquire 100% of PRL’s interest in the Additional Assets. If the Rights Offering is not fully subscribed or our lenders do not loan to us our requested loan under the proposed credit facility, we will acquire only a portion of PRL’s interest in the Additional Assets and PRL will continue to own its remaining undivided interest in the Additional Assets. In the event that we are unable, for whatever reason, to complete our purchase of any interest in the Additional Assets, we will not return the proceeds from the exercise of your Rights. In those circumstances we will utilize the criteria referred to under “Plan of Operations — Acquisitions” in order to select and acquire other suitable assets. See “Business and Properties Relating to the Additional Assets — The Take-Up Agreement”, page 73, “Bank Financing and Guarantees”, page 65 and “Risk Factors”, page 20.

CERTAIN CANADIAN FEDERAL AND U.S. FEDERAL INCOME TAX CONSIDERATIONS

Certain Canadian Federal and U.S. Federal Income Tax Considerations: Generally, Canadian income tax will be withheld at the rate of 15% of the value of the Dividend Units otherwise receivable by United States shareholders. In order to comply with this requirement, all of the Dividend Units to which such a shareholder is entitled will initially be withheld, and a sufficient number of such Dividend Units will be sold on the TSX to obtain net proceeds adequate to satisfy the withholding tax. See “Details of the Dividend — Withholding of Tax”, page 64 and “Certain Canadian Federal Income Tax Considerations”, page 113. Generally,

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subject to certain assumptions, and except to the extent gain is recognized on a sale of Dividend Units to satisfy Canadian withholding tax, both the Dividend and the Rights Offering should be free of United States federal income tax to United States shareholders of PRL. See “Certain U.S. Federal Income Tax Considerations”, page 113.

THE SPECIAL COMMITTEE

The Special Committee:	The board of directors of PRL has established a special committee of the board of directors (the “Special Committee”), all of whom are independent of the management of PRL and its largest shareholder, POG. The mandate of the Special Committee is to assess the merits of the transactions described in this prospectus essentially on the terms established by the board of directors of PRL and to consider such other alternative courses of action to carry out the intent and purpose of the transactions as may be appropriate in the circumstances. Specifically, the Special Committee has been granted the authority to assess the transactions with a view to whether or not the transactions are in the best interests of PRL and are fair, from a financial point of view, to the PRL Shareholders and to provide a recommendation to the board of directors of PRL with respect thereto. The Special Committee was not authorized to, and did not, negotiate the terms of the transaction. The Special Committee engaged Scotia Capital Inc. as its financial advisor and also engaged independent legal counsel to assist them in making this determination.
	On August 7, 2002, Scotia Capital Inc. presented to the Special Committee the results of its financial analysis and together with legal counsel to the Special Committee reviewed the material terms of the transaction. A summary of Scotia Capital Inc.’s presentation to the Special Committee is set forth under “Formation of Trust Structure and Structuring Transactions — Decision to Implement and the Special Committee”, page 28. The Special Committee also considered the preliminary prospectus and registration statement prepared in respect of the proposed distribution of the Dividend, the Rights Offering and related transactions. Scotia Capital Inc. presented its views to the Special Committee of the financial aspects of the Dividend, the Rights Offering and related transactions, including its view, as of August 7, 2002, of the fairness of these transactions from a financial point of view to the PRL Shareholders. Scotia Capital Inc. tabled a draft of the form of fairness opinion which Scotia Capital Inc. intends to provide at the time that the final prospectus and registration statement are filed with the appropriate securities regulatory authorities.
	After discussion and receipt of advice from its financial and legal advisors, the Special Committee unanimously determined to recommend to the full board of directors of PRL that the transaction was in the best interests of PRL and the PRL Shareholders, to proceed with the filing of the preliminary prospectus and registration statement with the appropriate securities regulatory authorities and that it approve the steps necessary at this time to implement the transaction. The Special Committee further advised the board of directors that it would present its final recommendations with respect to the transaction at the time of filing the final prospectus in the context of the financial, business and other applicable circumstances then in existence.
	On August 7, 2002, the board of directors of PRL met and received the preliminary report of the Special Committee and unanimously gave its approval to proceed with the transactions referred to in this prospectus and to file the preliminary prospectus and registration statement with the appropriate securities regulatory

13

	authorities.
	See “Formation of Trust Structure and Structuring Transactions — Decision to Implement and the Special Committee”, page 29.
Fairness Opinion:	The Special Committee has received a draft fairness opinion from Scotia Capital Inc. which is attached to this prospectus as Appendix “A”. See “Fairness Opinion”, page A-1.

SUMMARY RESERVE INFORMATION

         The following selected Reserve Information tables are qualified by detailed information contained elsewhere in this prospectus. In particular you should read the notes to the disclosure under the headings “Initial Business and Properties of POT — Natural Gas Reserves — Initial Assets”, page 62 and “Business and Properties Relating to the Additional Assets — Natural Gas Reserves — Additional Assets”, page 82.

Selected Reserve Information for the Initial Assets

         The tables below are a summary as at July 1, 2002, using a constant dollar price of $2.87 per Mmbtu as provided by PRL, being the price received for sales of natural gas by PRL on June 28, 2002, of the natural gas reserves attributable to the Initial Assets and the discounted present value of estimated future net cash flows associated with such reserves as evaluated in the independent engineering evaluation of the Initial Assets and the Additional Assets prepared by McDaniel & Associates Consultants Ltd. (“McDaniel”) dated October 15, 2002, (the “McDaniel Report”), based on constant price assumptions. These reserves are all located in the Province of Alberta, Canada. All evaluations of the present worth of estimated future net revenues in the McDaniel Report are stated after provision for estimated future capital expenditures and operating costs. An allowance for future wellbore abandonment costs was made for all wells in which there is a working interest; however no allowance was made for the abandonment of any surface, wellsites and facilities, for income tax or for Alberta Royalty Tax Credits (“ARTC”) (an Alberta provincial government program under which in certain circumstances tax credits may be provided against royalties on oil and natural, gas production payable to the Province of Alberta). These evaluations do not necessarily represent the fair market value of the reserves.

Natural Gas Reserves and Present Value of Estimated Future Cash Flows
(Based on Constant Price Assumptions)

					Present Value Cash
	Natural Gas				Flow Discounted at 10% (Net)
	Gross(1)		Net(2)
Reserves Categories	mmcf		mmcf		(M$)
Proved Developed Producing		46,647		36,577		44,875
Proved Undeveloped		3,135		2,249		3,198
Total Proved		49,782		38,826		48,073

Notes:

(1)	Gross reserves are defined as the aggregate of the PRL working interest and royalty interest reserves before deductions of royalties payable to others.
(2)	Net reserves are gross reserves less all royalties payable to others.
(3)	Financial matters such as prepayments, take or pay arrangements, general obligations, etc. were not included.

Selected Reserve Information for the Additional Assets

         The tables below are a summary as at July 1, 2002, using a constant dollar price of $2.87 per Mmbtu as provided by PRL, being the price received for sales of natural gas by PRL on June 28, 2002, of the natural gas reserves attributable to PRL’s full interest in the Additional Assets and the discounted present value of estimated future net cash flows associated with such reserves as evaluated in the McDaniel Report, based on constant price assumptions. These reserves are all located in the Province of Alberta, Canada. All evaluations of the present worth

14

of estimated future net revenues in the McDaniel Report are stated after provision for estimated future capital expenditures and operating costs. An allowance for future wellbore abandonment costs was made for all wells in which there is a working interest; however no allowance was made for the abandonment of any surface, wellsites and facilities, for income tax or for ARTC. These evaluations do not necessarily represent the fair market value of the reserves. These evaluations evaluate 100% of PRL’s interest in proved reserves in the Additional Assets. In the event the Rights Offering is not fully subscribed or if, for any reason (including the failure of POG, Treherne and 409790 to acquire all of the Trust Units that will be available to them under the Initial Subscription Privilege for the Rights that they will receive) our lenders do not loan to us our requested loan under the proposed credit facility that we have arranged with them, POT may be unable to acquire 100% of PRL’s interest in the Additional Assets and POT may only be able to acquire a lesser percentage interest or no interest in the Additional Assets. See “Business and Properties Relating to the Additional Assets”, page 73 and “Bank Financing and Guarantees”, page 65.

Natural Gas Reserves and Present Value of Estimated Future Cash Flows
(Based on Constant Price Assumptions)

					Present Value Cash
	Natural Gas				Flow Discounted at 10% (Net)
	Gross(1)		Net(2)
Reserves Categories	mmcf		mmcf		(M$)
Proved Developed Producing		108,887		89,381		104,550
Proved Developed Non-Producing		2,520		2,141		(1,504	)
Total Proved		111,407		91,522		103,045

Notes:

(1)	Gross reserves are defined as the aggregate of the PRL working interest and royalty interest reserves before deductions of royalties payable to others.
(2)	Net reserves are gross reserves less all royalties payable to others.
(3)	Financial matters such as prepayments, take or pay arrangements, general obligations, etc. were not included.

Selected Reserve Information for the Initial Assets and the Additional Assets Combined

         The tables below are a summary as at July 1, 2002 using a constant price of $2.87 per Mmbtu as provided by PRL, being the price received for sales of natural gas by PRL on June 28, 2002, of the natural gas reserves attributable to the Initial Assets and PRL’s full interest in the Additional Assets and the discounted present value of estimated future net cash flows associated with such reserves as evaluated in the McDaniel Report, based on constant price assumptions. These reserves are all located in the Province of Alberta, Canada. All evaluations of the present worth of estimated future net revenues in the McDaniel Report are stated after provision for estimated future capital expenditures and operating costs. An allowance for future wellbore abandonment costs was made for all wells in which there is a working interest; however no allowance was made for the abandonment of any surface, wellsites and facilities, for income tax or for ARTC. These evaluations do not necessarily represent the fair market value of the reserves. These evaluations evaluate 100% of PRL’s interest in proved reserves in the Additional Assets. In the event the Rights Offering is not fully subscribed or if, for any reason (including the failure of POG, Treherne and 409790 to acquire all of the Trust Units that will be available to them under the Initial Subscription Privilege for the Rights that they will receive) our lenders do not loan to us our requested loan under the proposed credit facility that we have arranged with them, POT may be unable to acquire 100% of PRL’s interest in the Additional Assets and POT may only be able to acquire a lesser percentage interest or no interest in the Additional Assets. See “Business and Properties Relating to the Additional Assets”, page 73 and “Bank Financing and Guarantees”, page 65.

15

Natural Gas Reserves and Present Value of Estimated Future Cash Flows
(Based on Constant Price Assumptions)

					Present Value Cash
	Natural Gas				Flow Discounted at 10% (Net)
	Gross(1)		Net(2)
Reserves Categories	mmcf		mmcf		(M$)
Proved Developed Producing		155,534		125,958		149,425
Proved Developed Non-Producing		2,520		2,141		(1,504	)
Proved Undeveloped		3,135		2,249		3,198
Total Proved		161,189		130,348		151,118

Notes:

(1)	Gross reserves are defined as the aggregate of the PRL working interest and royalty interest reserves before deductions of royalties payable to others.
(2)	Net reserves are gross reserves less all royalties payable to others.
(3)	Financial matters such as prepayments, take or pay arrangements, general obligations, etc., were not included.

Selected Financial Data for the PRL Northeast Alberta Properties and Financial and Production Information for the Initial Assets and the Additional Assets Combined

         The following is a summary of certain selected historical financial data and financial and production information and is qualified in its entirety by the detailed provisions contained in the Financial Statements for PRL’s Northeast Alberta Properties on page F-7, for the years ended December 31, 2001, 2000 and 1999 and the unaudited six month interim periods ended June 30, 2002 and 2001 contained elsewhere in this prospectus. Selected information for the unaudited period ended December 31, 1998 and 1997 is also set forth below.

PRL Northeast Alberta Properties Selected Financial Data⁽⁴⁾
(Cdn$000 except as indicated)

	Six Months Ended
	June 30				Year ended
	2002		2001		2001		2000		1999		1998(5)			1997(5)
Canadian GAAP	(unaudited)										(unaudited)
Revenue (Before royalties and hedging)		56,385		174,775		235,641		195,927		131,805		109,944			83,696
Net Earnings		34,896		51,374		67,914		51,825		27,319		(1	)		(1	)
Total assets		281,070				299,853		301,633		261,093		(1	)		(1	)
Net assets (Investment by Paramount Resources Ltd.)		122,030				172,113		195,085		214,497		(1	)		(1	)
US GAAP(2)(3)
Total assets		281,861				304,170		301,633		261,093		(1	)		(1	)
Net assets (Investment by Paramount Resources Ltd.)		129,313				175,070		195,085		214,497		(1	)		(1	)

Notes:

(1)	Certain of the selected financial data has not been provided for 1998 and 1997, as financial statements have not been prepared for the PRL Northeast Alberta Properties on a stand alone basis for those periods. See below for selected financial data on the Initial Assets and Additional Assets.
(2)	The differences between Canadian GAAP and US GAAP are described in the notes to the financial statements of the PRL Northeast Alberta Properties.
(3)	Other than disclosed here, the Canadian GAAP and US GAAP amounts are the same for the items included in the selected financial data.
(4)	The operations of PRL in its northeast Alberta core area as presented in the financial statements for the PRL’s Northeast Alberta Properties presented elsewhere in this prospectus are referred to herein as the Northeast Alberta Properties (“Northeast Alberta Properties”). The Northeast Alberta Properties include the Initial Assets, the Additional Assets and certain properties not to be acquired by PET (the “Excluded Assets”). The Excluded Assets consist of certain exploration properties, gas properties in the Cold Lake Elizabeth area and gas properties shut-in due to the Surmont co-production issue. The Excluded Assets generated $7.4 million of revenue for the year ended December 31, 2001. See “Government Regulations — Regulatory Rulings”, page 111.

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(5) The 1997 and 1998 figures are unaudited and we have not filed a comfort letter with respect to such numbers with any securities regulatory authority.

Selected Financial and Production Information for the Initial Assets and the Additional Assets

	Six Months Ended June 30,
	2002									2001
	Initial			Addl.			Total			Initial			Addl.			Total
	Assets			Assets			Assets			Assets			Assets			Assets
(Cdn$000 except as indicated)
Production (mmcf/d)		18.6			76.7			95.3			15.6			93.7			109.3
Price ($/mcf)	$	3.42		$	3.14		$	3.20		$	6.52		$	8.96		$	8.61
Revenue	$	11,520		$	43,611		$	55,131		$	18,404		$	152,030		$	170,434
Royalties		(2,418	)		(6,948	)		(9,366	)		(5,063	)		(25,827	)		(30,890	)
Operating Costs		(3,220	)		(12,757	)		(15,977	)		(2,733	)		(14,226	)		(16,959	)
Operating Income(2)	$	5,882		$	23,906		$	29,788		$	10,608		$	111,977		$	122,585

	Years Ended December 31,
	2001									2000
	Initial			Addl.			Total			Initial			Addl.			Total
(Cdn$000 except as indicated)	Assets			Assets			Assets			Assets			Assets			Assets
Production (mmcf/d)		17.3			85.4			102.7			14.0			93.4			107.4
Price ($/mcf)	$	4.51		$	6.41		$	6.09		$	4.74		$	4.65		$	4.65
Revenue	$	28,492		$	199,791		$	228,283		$	24,357		$	158,370		$	182,727
Royalties		(8,888	)		(36,873	)		(45,761	)		(6,366	)		(28,825	)		(35,191	)
Operating Costs		(4,628	)		(28,242	)		(32,870	)		(3,318	)		(20,828	)		(24,146	)
Operating Income(2)	$	14,976		$	134,676		$	149,652		$	14,673		$	108,717		$	123,390

	Years Ended December 31,
	1999									1998(1)									1997(1)
	Initial			Addl.			Total			Initial			Addl.			Total			Initial			Addl.			Total
(Cdn $000 except as indicated)	Assets			Assets			Assets			Assets			Assets			Assets			Assets			Assets			Assets
Production (mmcf/d)		14.0			99.0			113.0			14.6			120.9			135.5			9.7			79.1			88.8
Price ($/mcf)	$	2.64		$	2.60		$	2.61		$	1.92		$	1.90		$	1.90		$	2.00		$	1.96		$	1.96
Revenue	$	13,426		$	94,149		$	107,575		$	10,250		$	83,724		$	93,974		$	7,084		$	56,546		$	63,630
Royalties		(2,765	)		(20,008	)		(22,773	)		(1,569	)		(12,212	)		(13,781	)		(1,353	)		(9,097	)		(10,450	)
Operating Costs		(754	)		(17,357	)		(18,111	)		(1,554	)		(18,391	)		(19,945	)		(902	)		(9,867	)		(10,769	)
Operating Income(2)	$	9,907		$	56,784		$	66,691		$	7,127		$	53,121		$	60,248		$	4,829		$	37,582		$	42,411

Note:

(1)	The 1997 and 1998 figures are unaudited and we have not filed a comfort letter with respect to such numbers with any securities regulatory authority.
(2)	For the purposes of the tables immediately above, operating income excludes gains or losses related to hedging which are considered corporate rather than operating activities.

         The information set out above and in the Financial Statements for PRL’s Northeast Alberta Properties for the years ended December 31, 2001, 2000 and 1999 and the unaudited six month interim periods ended June 30, 2002 and 2001 contained elsewhere in this prospectus with respect to the Additional Assets assumes the acquisition by POT of 100% of PRL’s interest in the Additional Assets. See note 3 to the pro forma consolidated financial statements beginning on page F-25 for information on additional potential Rights exercise scenarios. In the event the Rights Offering is not fully subscribed or if, for any reason (including the failure of POG, Treherne and 409790 to acquire all of the Trust Units that will be available to them under the Initial Subscription Privilege for the Rights that they will receive) our lenders do not loan to us our requested loan under the proposed credit facility that we have arranged with them, POT may be unable to acquire 100% of PRL’s interest in the Additional Assets and POT may only be able to acquire a lesser percentage interest or no interest in the Additional Assets. See “Business and Properties Relating to the Additional Assets”, page 73 and “Bank Financing and Guarantees”, page 65.

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Selected Operational Information

Category of Assets		Proved Reserves(1)		Production(2)		Undeveloped Land
Name of Area		(bcf)		(mmcf/d)		(net acres)
Initial Assets
	Legend		49.78		20.8		44,902
Additional Assets
	Bohn Lake		4.67		2.5		533
	Chard		2.45		1.7		6,244
	Chard Southwest		1.23		0.6		5,186
	Clyde		1.72		2.7		14,140
	Cold Lake		9.41		6.2		20,856
	Cold Lake Sonoma		5.54		3.2		14,144
	Corner		17.91		12.9		28,480
	Hoole		0.15		0.2		3,520
	Kettle River		6.92		4.3		—
	Legend East		3.44		3.6		25,600
	Leismer/Leismer South		10.07		9.0		89,240
	Liege East		3.36		2.6		1,836
	Liege North		4.06		3.0		—
	Liege South		4.71		4.7		12,800
	Pony		0.80		0.5		3,040
	Quigley		2.00		3.5		13,760
	Saleski		10.05		4.2		20,566
	Surmont		0.06		0.1		1,280
	Teepee Creek		0.66		1.7		55,040
	Thornbury		11.82		4.8		1,152
	Winefred		10.41		4.7		22,400
TOTALS			161.22		97.5		384,719

Note:

(1)	As at July 1, 2002 per McDaniel Report.
(2)	Averages volume for the month of August 2002.

         The information set out above with respect to the Additional Assets assumes the acquisition by POT of 100% of PRL’s interest in the Additional Assets. In the event the Rights Offering is not fully subscribed or if, for any reason (including the failure of POG, Treherne and 409790 to acquire all of the Trust Units that will be available to them under the Initial Subscription Privilege for the Rights that they will receive) our lenders do not loan to us our requested loan under the proposed credit facility that we have arranged with them, POT may be unable to acquire 100% of PRL’s interest in the Additional Assets and POT may only be able to acquire a lesser percentage interest or no interest in the Additional Assets. See “Business and Properties Relating to the Additional Assets”, page 73 and “Bank Financing and Guarantees”, page 65.

Selected Pro Forma Financial and Production Information

         The following is a summary of certain selected pro forma historical financial and production information and is qualified in its entirety by the detailed provisions of PET’s pro forma financial statements for the six month period ended June 30, 2002, and for the year ended December 31, 2001, contained elsewhere in this prospectus.

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Six Months Ended June 30, 2002
(Cdn$000)

					Additional Assets									Total to PET
		Initial Assets			Rights @ 100%			Rights @ 75%			Rights @ 50%			Rights @ 100%			Rights @ 75%			Rights @ 50%
Revenue:
	Sales of natural gas	$	11,520		$	43,611		$	35,955		$	23,434		$	55,131		$	47,475		$	34,954
	Hedging		—			—			—			—			10,709			9,222			6,790
	Royalties		(2,418	)		(6,948	)		(5,728	)		(3,733	)		(9,366	)		(8,146	)		(6,151	)
			9,102			36,663			30,227			19,701			56,474			48,551			35,593
Expenses:
	Operating		3,220			15,977			10,518			6,855			15,977			13,738			10,075
	General and administrative														2,070			2,070			2,070
	Interest														2,126			1,864			1,437
	Depletion and depreciation														28,816			24,344			17,030
	Site restoration														1,522			1,264			843
															50,511			43,280			31,455
Net Earnings														$	5,963		$	5,271		$	4,138
Net Earnings per Trust Unit
	Basic													$	0.15		$	0.16		$	0.17
	Diluted													$	0.15		$	0.16		$	0.17

Year ended December 31, 2001
(Cdn$000)

					Additional Assets									Total to PET
		Initial Assets			Rights @ 100%			Rights @ 75%			Rights @ 50%			Rights @ 100%			Rights @ 75%			Rights @ 50%
Revenue:
	Sales of natural gas	$	28,492		$	199,791		$	164,719		$	107,356		$	228,283		$	193,211		$	135,848
	Hedging		—			—			—			—			8,838			7,480			5,259
	Royalties		(8,888	)		(36,873	)		(30,400	)		(19,813	)		(45,761	)		(39,288	)		(28,701	)
			19,604			162,918			134,319			87,543			191,360			161,403			112,406
Expenses:
	Operating		4,628			28,242			23,284			15,176			32,870			27,912			19,804
	General and administrative														4,498			4,498			4,498
	Interest														4,250			3,453			2,656
	Depletion and depreciation														63,478			53,435			37,008
	Site restoration														3,398			2,820			1,874
															108,494			92,118			65,840
Net Earnings														$	82,866		$	69,285		$	46,566
Net Earnings per Trust Unit
	Basic													$	2.09		$	2.15		$	1.88
	Diluted													$	2.09		$	2.15		$	1.88

         The information set out above and in PET’s pro forma statements for the six month period ended June 30, 2002 and for the year ended December 31, 2001 contained elsewhere in this prospectus with respect to the Additional Assets assumes the acquisition by POT of 100% of PRL’s interest in the Additional Assets. See note 3 to the pro forma consolidated financial statements beginning on page F-25 for information on additional potential Rights exercise scenarios. In the event the Rights Offering is not fully subscribed or if, for any reason (including the failure of POG, Treherne and 409790 to acquire all of the Trust Units that will be available to them under the Initial Subscription Privilege for the Rights that they will receive) our lenders do not loan to us our requested loan under the proposed credit facility that we have arranged with them, POT may be unable to acquire 100% of PRL’s interest in the Additional Assets and POT may only be able to acquire a lesser percentage interest or no interest in the Additional Assets. See “Business and Properties Relating to the Additional Assets”, page 73 and “Bank Financing and Guarantees”, page 65.

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RISK FACTORS

         You should carefully consider the risks described below before making an investment decision. You should also refer to the other information included in this prospectus, including our financial statements and the related notes.

Our reserves will be depleted over time and we may be unable to develop or acquire additional reserves.

         Royalty trusts, structured as we are, have certain unique attributes that differentiate them from other oil and natural gas industry participants. The primary source of distributable income to you will be from POT’s oil and natural gas properties which, absent commodity price increases or cost effective acquisition and development activities, will decline over time in a manner consistent with declining production from typical oil, natural gas and natural gas liquids reserves. POT will not be reinvesting cash flow in the same manner and to the same extent as traditional, non-trust industry participants. Accordingly, absent capital injections, POT’s production levels and reserves will decline over time.

         POT’s future oil and natural gas reserves and production, and therefore its cash flows, will be highly dependent on our success in exploiting its reserve base and acquiring additional reserves; especially given that as production declines in mature areas such as those areas comprising the Initial Assets and Additional Assets, the unit production costs increase. Without reserve additions through acquisition or development activities, POT’s reserves and production will decline over time as these reserves are exploited.

         To the extent that external sources of capital, including the proceeds of any issuance of additional Trust Units, become limited or unavailable, POT’s ability to make the necessary capital investments to maintain or expand its oil and natural gas reserves will be impaired. If POT uses production revenue to finance capital expenditures or property acquisitions, the level of distributable income to you will be reduced. See “Management’s Discussion and Analysis and Liquidity and Capital Resources, page 53.

Our reserve data regarding the Initial Assets and Additional Assets are estimates and actual production, revenues and expenditures may differ from such estimates resulting in the actual net value of reserves being lower.

         Estimates of our oil and natural gas reserves depend in large part upon the reliability of available geological and engineering data. Geological and engineering data are used to determine the probability that a reservoir of oil and natural gas exists at a particular location, and whether, and the extent to which, oil and natural gas are recoverable from a reservoir. The reliability of reserve estimates depends on:

• whether the prevailing tax rules and other government regulations, contracts and oil, natural gas and other prices, will remain the same as on the date estimates are made;

• the production performance of our reservoirs;

• extensive engineering judgments;

• the price at which recovered oil and natural gas can be sold;

• the costs associated with recovering oil and natural gas;

• the prevailing environmental conditions associated with drilling and production sites;

• the availability of enhanced recovery techniques; and

• the ability to transport oil and natural gas to markets.

         A change in any one or more of these factors could result in known quantities of oil and natural gas previously estimated as proved reserves becoming unrecoverable. For example, a decline in the market price of oil or natural gas to an amount that is less than the cost of recovery of such oil and natural gas in a particular location could make production thereof commercially impracticable. Each of these factors, by having an impact on the cost of recovery and the rate of production, will also affect the present value of future net cash flows from estimated reserves. Many of the factors, assumptions and variables involved in estimating reserves are beyond our control and may prove to be incorrect over time. Results of drilling, testing and production after the date of the estimates may require substantial upward or downward revisions in our reserve data. Any downward adjustment could lead to lower future production and thus adversely affect our financial condition, future prospects and market value. See “Initial Business and Properties of POT - Natural Gas

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Reserves — Initial Asset”, page 62 and “Business and Properties Relating to the Additional Assets — Natural Gas Reserves — Additional Assets”, page 82.

Several factors may hinder or prohibit us from acquiring the Additional Assets in which case management has broad discretion to identify and acquire other assets.

         Our lenders have placed restrictions on our ability to borrow funds from them, which require us to have at least all of the Rights held by POG, Treherne and 409790 exercised prior to our lenders advancing any financing for our acquisition of the Additional Assets. If we fail to meet this threshold:

• the lenders will not finance us;

• we will continue to be obligated to PRL’s lenders under the guarantee discussed below;

• we will be unable to acquire any interest in the Additional Assets; and

• we may be unable to repay the $30,000,000 secured indebtedness we owe to PRL.

         We will not return the proceeds from the exercise of your Rights and if we are unable to finance the acquisition of the Additional Assets through these lenders you will have to rely on our management:

• for prudent use of the proceeds of the Rights Offering including identifying suitable assets for future acquisitions; and

• to secure alternative debt financing.

         In addition, our lenders will not make a final determination of the initial borrowing base (and therefore the exact amount of funds that they will lend to us) under the proposed credit facilities that we have arranged with them until shortly prior to the Rights Expiry Time. The amount of funds available may be significantly less than the maximum amount under the commitment letter of $100,000,000. If this occurs we may not be able to acquire 100% of PRL’s interest in the Additional Assets even if the Rights Offering is fully subscribed.

         Even if the Rights Offering is fully subscribed we may nonetheless fail to acquire any interest in the Additional Assets due to, among other things, unforeseen title defects, extreme volatility in the oil and gas industry and other unforeseen factors. Under this scenario we would not receive the debt financing. See “Bank Financing and Guarantees”, page 65.

There are conditions precedent which may hinder POG and its subsidiaries’ ability to exercise their Rights.          While POG, Treherne and 409790 represent under the Rights Exercise Agreement that they have available funding including bank financing, which will allow the exercise of all their Rights, the funding of amounts under their credit arrangements is conditional upon a number of things, including the provision by POG, Treherne and 409790 to their lenders of sufficient collateral. In the event that POG, Treherne and 409790 are unable to draw down the required amounts under these facilities, or PRL is not in a position to pay to POG the full amount that PRL owes to POG, POG, Treherne and 409790 may not be able to exercise all of their Rights. In such event our $20,000,000 guarantee of PRL’s debt may not be released and we may not be able to repay the $30,000,000 secured indebtedness we owe to PRL and which will be assigned by PRL to its lenders. See “Bank Financing and Guarantees”, page 65.

Our title to the Initial Assets and Additional Assets may have defects which could result in additional costs and adversely affect our interests in disputed properties.

         We have not obtained a legal opinion as to the title to the Initial Assets and Additional Assets and cannot guarantee or certify that a defect in the chain of title may not arise to defeat our claim to a particular oil and natural gas property. Remediation of title problems could result in additional costs and litigation. If we are not able to remedy these title defects, we may lose some of our interest in the disputed properties resulting in reduced production and distributable income available to you.

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Our guarantee to PRL’s lenders may impair our ability to operate.

         PRL’s lenders require us to guarantee and provide guarantee security for $20,000,000 of PRL’s debt to them. The guarantee security will be a second charge on our assets after the first $30,000,000 charge securing our indebtedness to PRL for the Initial Assets which PRL will assign to its lenders and consequently we face significant risks including:

• we will be unable, absent lenders’ consent, to dispose of the Initial Assets;

• our borrowing base may be over-leveraged;

• the lenders will have the right to foreclose on, and force the sale of, the Initial Assets and any other pledged security, if PRL does not meet its debt repayment obligations; and

• we may have to reallocate cash resources to satisfy the guarantee, to the detriment of our ongoing revenue generating activities.

         Additionally, concurrent with the execution of the Take-Up Agreement we will pay to PRL a deposit on the purchase price of the Additional Assets through the issuance of a $5,000,000 non-interest bearing promissory note. If closing under the Take-Up Agreement does not occur due to a material breach of the agreement by POT, the deposit may be forfeited to PRL and PRL may demand payment under the promissory note. The occurrence of this event may result in us facing similar risks to those detailed above.

         Adverse developments with respect to the guarantee or the deposit may affect our continued listing on any stock exchange and the liquidity of your Trust Units. See “Bank Financing and Guarantees”, page 65.

Our lenders have the ability in certain circumstances to impair our ability to pay distributions on our Trust Units and to pay cash redemptions for Trust Units.

         Under the terms of the proposed facility with our lenders, if our lenders determine that our borrowing base under the facility has been exceeded by the amount loaned to us, and assuming there is not a demand for repayment resulting therefrom, we will be precluded from providing distributions on the Trust Units and from paying cash for redemptions of Trust Units, until our borrowing base no longer is in a shortfall position. Our lenders may also restrict our ability to pay distributions when we are in breach or default of our agreements with them. See “Bank Financing and Guarantees”, page 65.

Our operations involve many uncertainties and operating risks that can prevent us from realizing profits and can cause substantial losses.

         Our operations may be delayed or unsuccessful for many reasons, including cost overruns, lower oil and natural gas prices, equipment shortages, mechanical and technical difficulties and labor problems. Our operations will also often require the use of new and advanced technologies, which can be expensive to develop, purchase and implement, and may not function as we expect. We may experience substantial cost overruns caused by changes in the scope and magnitude of our operations, employee strikes and several unforeseen technical problems including natural hazards which may result in blowouts, environmental damage or other unexpected or dangerous conditions giving rise to liability to third parties. In particular, drilling activities are subject to many risks, including the risk that no commercially productive reservoirs will be encountered. We cannot assure you that new wells we drill will be productive or that we will recover all or any portion of our investment in them. Drilling for oil and natural gas could involve unprofitable efforts, not only from dry wells, but from wells that are productive but do not produce enough net revenue to return a profit after drilling, operating and other costs. The cost of drilling, completing and operating wells is often uncertain. In addition, our operations depend on the availability of drilling and related equipment in the particular areas where exploration and development activities will be conducted. Demand for the equipment or access restrictions may affect the availability of that equipment to us and delay our operations.

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We will encounter competition in all areas of our business and may not be able to successfully compete with our competitors.

         The oil and gas industry is extremely competitive, especially with regard to exploration for, and exploitation and development of, new sources of oil and natural gas. We may not be able to compete successfully with some of our larger, well-established competitors. Consequently, POT may be forced to pay more for attractive properties or be unable to acquire new assets efficiently, which would materially adversely affect POT’s ability to maintain and expand its oil and natural gas reserves.

         Some of our competitors are much larger, well-established companies with substantially greater resources, and in many instances they have been engaged in the oil and gas business much longer than we have. These larger companies, especially those created by recent mergers, are developing strong market power through a combination of different factors, including:

• diversification and reduction of risk;

• financial strength necessary for capital-intensive developments;

• exploitation of benefits of integration;

• exploitation of economies of scale in technology and organization;

• exploitation of mutual advantages of expertise, industrial infrastructure and reserves; and

• strengthening of positions as global players.

         These companies may be able to pay more for productive oil and natural gas properties and may be able to define, evaluate, bid for and purchase a greater number of properties and prospects, including operatorships and licenses, than our financial or human resources permit. They may also be able to attract more qualified employees, including our key personnel.

The success of your investment is highly dependent on our key personnel.

         You will be entirely dependent on our management in respect of administration of all matters relating to our assets and securities. Our management has broad discretion in allocating the proceeds of the Rights Offering in the event that the Rights Offering is not fully subscribed and we are unable to acquire the Additional Assets. If you are not willing to rely on our management you should not invest in the Trust Units. Moreover, our operations will be highly dependent upon our executive officers and key employees. The unexpected loss of the services of any of these individuals could have a detrimental effect on us. See “The Administrator — Directors and Officers”, page 102.

Some of our key personnel may have conflicts of interest.

         Some of the officers and directors of the Administrator are also directors of PRL and of other oil and natural gas companies which may, from time to time, be in competition with us for working interest partners, property acquisitions, key employees and other resources. See “The Administrator — Directors and Officers”, page 102, “Conflicts of Interest”, page 123 and “Interest of Insiders and Others in Material Transactions”, page 124.

The production and revenue of our properties may to some extent be dependent on the ability of third party operators.

         The continuing production from approximately 8% of the Additional Assets based on current production, and to some extent the marketing of such production, are dependent upon the ability of third party operators of the property. If, in situations where we are not the operator, the operator fails to perform these functions properly or becomes insolvent, our revenue may be reduced. Payments from production generally flow through the operator and, where we are not the operator, there is a risk of delay and additional expenses in receiving such revenues. As owner of working interests in properties we do not operate, we will generally have only a cause of action for damages arising as a result of the gross negligence or wilful misconduct of the operator. The expense of bringing such an action could be significant and we may

23

be unsuccessful in recovering damages. Additionally any delay in payment along the production chain could adversely impact your distributions.

We are not insured against all potential losses and could be seriously harmed by natural disasters or operational catastrophes.

         Exploration for and production of oil and natural gas is hazardous, and natural disasters, operator error or other occurrences can result in oil spills, blowouts, cratering, fires, equipment failure and loss of well control, which can injure or kill people, damage or destroy wells and production facilities, and damage other property and the environment. Losses and liabilities arising from such events could significantly reduce our revenues or increase our costs and have a material adverse effect on our operations or financial condition.

         We may be unable to obtain insurance against these risks at premium levels that justify its purchase, insurance may be unavailable and any insurance we may obtain may be insufficient to provide full coverage. The occurrence of a significant event that is not fully insured could have a material adverse effect on our financial position and reduce or eliminate distributions to you.

There is a potential for accounting write-downs which could be viewed unfavorably in the market and limit our ability to borrow funds.

         Under Canadian accounting rules the net capitalized cost of oil and natural gas properties may not exceed a “ceiling limit” which is based in part upon estimated future net cash flows from reserves. If our net capitalized costs exceed this limit, we will have to charge the amount of the excess against earnings. A decline in oil and natural gas prices could cause our capitalized costs to exceed the cost ceiling, resulting in a charge against earnings. The market may view the charge to earnings unfavorably. The charge to earnings may also limit our ability to borrow funds.

We may be unable to secure additional financing.

         Trust Units will have very limited value when reserves from our properties can no longer be economically produced. We will need to seek additional financing to maintain and expand our business. Such financing may not be available on terms or under conditions that are favorable to us or at all.

Significant capital expenditures could reduce or even eliminate distributions to you.

         The timing and amount of our capital expenditures will directly affect your distributions. We may reduce or even eliminate distributions at times when we make significant capital or other expenditures.

It may be difficult for you to dispose of Trust Units or recoup your investment.

         The right to redeem Trust Units will not be the primary mechanism for Unitholders to liquidate their investments and there may not be an active trading market for the Trust Units that would facilitate other sales. Generally, we will not redeem in cash more than $100,000 of Trust Units in any one calendar month. Instead we will pay such excess redemption amount by the issuance of promissory notes of PET which will be unsecured, subordinated to all of our indebtedness, be due and payable 5 years after issuance and for which no market is expected to develop. Our ability to pay redemptions in cash or to make payment on such promissory notes may be further restricted by our lenders. (See “Description of the Trust Units and Special Voting Units – Redemption Right”, page 90.

You may suffer dilution of your interest in PET.

         To the extent that any Rights are exercised, holders of Dividend Units who do not exercise their Rights will suffer a decrease in their percentage ownership of PET. In addition, to maintain or expand POT’s oil and natural gas reserves

24

we will need to finance capital expenditures and property acquisitions. Consequently, you may suffer dilution as a result of any future offering of Trust Units or securities convertible into Trust Units that we undertake.

Trust Units do not carry the same statutory rights as common shares and may expose you to personal liability.

         Securities such as the Trust Units are hybrids in that they share certain attributes common to both equity securities and debt instruments. However, the Trust Units are unlike debt instruments as there is no principal amount owing to Unitholders and are unlike traditional equity securities as Unitholders have none of the statutory rights normally associated with ownership of shares of a corporation (including, for example, the right to bring “oppression” or “derivative” actions). In addition, Unitholders are not protected from our liabilities to the same extent that a shareholder would be protected from a corporation’s liabilities. For example, personal liability of Unitholders may arise from claims in tort or claims for taxes against us. Unlike many other royalty trusts and income funds, our structure does not include the interposition of a limited liability entity such as a corporation or limited partnership which would provide further limited liability protection to Unitholders. As a result, ownership of Trust Units may expose you to personal liability. See “The PET Trust Indenture”, page 91 and “Description of the Trust Units and Special Voting Units – PET Unitholder Liability”, page 87.

Non-Residents are subject to restrictions on their ownership of our securities, which may require them to sell their Trust Units when market conditions are not favorable.

         The trust indenture which established PET as a trust restricts the ownership of Trust Units by Unitholders who are non-residents of Canada. Unitholders who are non-residents of Canada for the purposes of the Tax Act face the risk of being forced to sell some or all of their Trust Units, when market conditions may not be favorable, in order to comply with these restrictions. See “Description of the Trust Units and Special Voting Units – Non-Resident Trust Unitholders”, page 91.

Any decline in the marketability or the price of natural gas could materially harm our financial condition.

         The prices of and demand for oil and natural gas fluctuate for reasons largely beyond our control. Such fluctuations may have a negative effect on our revenue (and hence on distributable income), as well as on the acquisition costs of any future oil and natural gas properties that we may acquire. Our initial production is weighted exclusively to natural gas and we may be more subject to price fluctuations in natural gas than our competitors whose production is more diversified than ours.

         Both oil and natural gas prices are extremely volatile. Oil prices are determined by international supply and demand. Political developments, compliance or non-compliance with self-imposed quotas, or agreements between members of Organization of Petroleum Exporting Countries all can affect world oil supply and prices. Numerous other factors beyond our control will affect the marketability and price of oil and natural gas that we acquire or discover, including:

• the demand for oil and natural gas;

• the proximity and capacity of oil and natural gas pipelines and processing equipment;

• changes in government regulations (including regulations relating to environmental protection, royalties, allowable production, pricing, importing and exporting of oil and natural gas);

• weather;

• general economic conditions; and

• conditions in other natural gas producing regions.

         The negative impact of any one of these or other factors could significantly affect our results of operations, our distributable income and our overall financial condition.

25

Variations in interest rates may limit our distributions to you.

         Variations in interest rates could result in a significant increase in the amount we pay to service our debt, resulting in a decrease in distributable income to you. Certain covenants in our loan agreements with our lenders could limit distributions to you. Our credit facilities will be subject to periodic review. Our lenders may reduce the size of the credit facilities, limiting our ability to maintain operations and to acquire new properties, thereby reducing your distributions. See “Bank Financing and Guarantees”, page 65 and “Description of Trust Units and Special Voting Units — Distributions”, page 88.

As a Canadian operator, we are exposed to risk caused by fluctuations in currency exchange rates.

         Our operating costs, including costs of production, are generally paid in Canadian dollars. World oil prices are quoted in U.S. dollars and the price Canadian producers receive is therefore affected by the Canadian/U.S. dollar exchange rate that will fluctuate over time. A material increase in the value of the Canadian dollar may negatively impact our production revenue. See “Management Discussion and Analysis and Liquidity and Capital Resources - Quantitative and Qualitative Disclosures About Market Risk — Sensitivities”, page 55.

Future hedging activities could result in losses.

         The nature of our operations results in exposure to fluctuations in commodity prices. We will monitor and, when appropriate, may utilize derivative financial instruments and physical delivery contracts to hedge our exposure to these risks. We may be exposed to credit-related losses in the event of non-performance by counter-parties to the financial instruments. From time to time we may enter into hedging activities in an effort to mitigate the potential impact of declines in oil and natural gas prices. These activities may consist of, but are not limited to:

• buying a price floor under which we will receive a minimum price for our oil and natural gas production;

• buying a collar, under which we will receive a price within a specified price range for oil and natural gas production;

• entering into fixed price contract for oil and natural gas production; and

• entering into a contract to fix the price differential between light and heavy oil.

         If product prices increase above those levels specified in our various hedging agreements, we would be precluded from receiving the full benefit of commodity price increases.

         In addition, by entering into these hedging activities, we may suffer financial loss if:

• we are unable to produce sufficient quantities of oil or natural gas to fulfill our obligations;

• we are required to pay a margin call on a hedge contract; or

• we are required to pay royalties based on a market or reference price that is higher than our fixed or ceiling price.

Changes in the market values of our permitted investments could adversely affect the value of the Trust Units.

         We may invest in certain permitted investments whose prices may fluctuate. For example, the prices of Canadian government securities, bankers’ acceptances and commercial paper react to economic developments and changes in interest rates. Commercial paper is also subject to issuer credit risk. Other permitted investments in energy-related entities will be subject to the general risks of investing in equity securities. These include the risk that the financial condition of issuers may become impaired, or that the energy sector may suffer a market downturn. Securities markets in general are affected by a variety of factors including governmental, environmental, and regulatory policies, inflation and interest rates, economic cycles, and global, regional and national events. The value of the Trust Units could be affected by adverse changes in the market values of permitted investments.

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Changes in legislation could materially adversely affect our business.

         We currently benefit from certain tax treatments and government incentive programs, including our treatment as a mutual fund trust for Canadian income tax purposes and the status of income or royalty trusts and the resource allowance. Income tax laws and other laws or government incentive programs relating to the oil and gas industry may change in a manner adversely affecting us and your investment. Tax authorities having jurisdiction over us may disagree with our treatment of revenue for tax purposes or change their administrative practices to our and your detriment. See “Government Regulations”, page 111.

We may incur material costs to comply with, or as a result of, health, safety and environmental laws and regulations.

         Compliance with environmental laws and regulations could materially increase our costs. We will incur substantial capital and operating costs to comply with increasingly complex laws and regulations covering the protection of the environment and human health and safety. These include costs to reduce certain types of air emissions and discharges and to remediate contamination at various facilities and at third party sites where our products or wastes will be handled or disposed.

         We are subject to statutory strict liability in respect of losses or damages suffered as a result of pollution caused by spills or discharges of petroleum from petroleum facilities covered by any of our licenses. This means that anyone who suffers losses or damages as a result of pollution caused by our operations can claim compensation from us without needing to demonstrate that the damage is due to any fault on our part.

         New laws and regulations, the imposition of tougher requirements in licensing, increasingly strict enforcement of or new interpretations of existing laws and regulations, or the discovery of previously unknown contamination may require future expenditures to:

• modify operations;

• install pollution control equipment;

• perform site clean-ups; or

• curtail or cease certain operations.

         In particular, the Canadian government is considering whether or not to adopt the 1997 Kyoto Protocol to the United Nations Framework Convention on Climate Change, known as the Kyoto Protocol. If adopted, new requirements and regulations may require us to incur significant costs to comply. In addition, increasingly strict environmental requirements affect product specifications and operational practices. Future expenditures to meet such specifications could have a material adverse effect on our operations or financial condition. Any abandonment costs we incur will reduce your distributions. See “Government Regulations”, page 111.

Adverse regulatory decisions regarding applications for the shut in of natural gas wells could materially impact the Initial Assets and the Additional Assets.

         The Initial Assets and the Additional Assets are all located in northeast Alberta where the Alberta Energy Utilities Board (“AEUB”) is currently deciding whether or not to approve applications to shut in natural gas production in favour of the recovery of underlying bitumen. Depending upon the decisions and the criteria the AEUB uses in reaching its decision, applications could be made to shut-in production of natural gas overlying bitumen in areas of northeast Alberta, potentially including production from the Initial Assets and the Additional Assets. In such case, POT may not be able to negotiate adequate compensation for having to shut-in any such production. This could have a material adverse effect on the amount of income available for distribution to our Unitholders. See “Government Regulation – Regulatory Rulings”, page 111.

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The Trust Units may cease to be qualified investments under the Tax Act, which could materially adversely affect the market for Trust Units.

         The Tax Act imposes penalties for the acquisition or holding of non-qualified or ineligible investments by registered retirement savings plans, deferred profit sharing plans, registered retirement income funds and registered education savings plans. We cannot assure investors who hold Trust Units in such plans that the Trust Units will remain qualified investments at any particular time or that they will not be subject to penalties for holding the Trust Units in these vehicles. In addition, should the Trust Units become ineligible or non-qualified investments for purposes of being held in such plans, it may adversely affect the market for the Trust Units both immediately and in the future. See “Certain Canadian Federal Income Tax Considerations - Status of PET”, page 114.

PET could be a PFIC for U.S. tax purposes, which could subject you to materially adverse United States federal income tax consequences.

         PET could be a “passive foreign investment company” (or PFIC) for United States federal income tax purposes. However, based on PET’s current and projected income, assets and activities, and disregarding the separate existence of POT, PET’s management believes PET would not presently be treated as a PFIC for United States federal income tax purposes. PET’s status in future years will depend on its assets and activities (and those of POT) in those years. If PET were considered a PFIC, then United States persons holding Trust Units would be subject to materially adverse United States federal income tax consequences with respect to distributions received on, and dispositions of, Trust Units. See “Certain United States Federal Income Tax Considerations – Tax Consequences of Holding Trust Units – Passive Foreign Investment Company”, page 120.

A judgment of a United States court for liabilities under U.S. securities laws may be unenforceable in Canada, and you may be unable to bring an original action in Canada against us or PRL for liabilities under U.S. securities laws.

         PET, POT, the Administrator and PRL are all Canadian entities, all of our directors and officers are residents of Canada, the Dealer Managers and experts named in this prospectus are residents of Canada and all or substantially all of our assets are and the assets of our directors and officers, the Dealer Managers and the experts named in this prospectus may be located outside the United States. As a result, it may be difficult for you to:

• effect service of process within the United States on PRL or us or any of its or our respective directors and officers, or

• enforce judgments obtained in the United States courts against PRL, us or its or our directors and officers based upon the civil liability provisions of the United States federal securities law.

         We have been advised by our Canadian counsel, Gowling Lafleur Henderson LLP, that there is doubt as to:

• whether a judgment of a United States court based solely upon the civil liability provisions of the United States federal securities laws would be enforceable in Canada against PRL or us or its or our directors and officers, and

• whether an original action could be brought in Canada against us or such others to enforce liabilities based solely upon the United States federal securities law.

A small portion of the Additional Assets are subject to rights of first refusal, which may result in us not acquiring all or part of that particular portion of the Additional Assets.

         Certain of the properties in the Additional Assets that we intend to acquire from PRL are subject to rights of first refusal in favor of third parties. For a third party to exercise a right of first refusal they must pay the value that we have ascribed to the interest we intend to acquire. It is possible that lands comprising a portion of the Additional Assets with related production of approximately 1.6 mmcf/d (approximately 2% of the average daily production associated with the Additional Assets based on production levels for the month of May 2002) may be acquired by third parties exercising

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such rights of first refusal. If that were to happen, we will receive cash in lieu of such portion of the Additional Assets or an adjustment to the purchase price of the Additional Assets depending on when the right of first refusal is exercised.

FORMATION OF TRUST STRUCTURE AND STRUCTURING TRANSACTIONS

Decision to Implement and the Special Committee

Background

         In December of 2001, members of PRL’s senior management approached its professional advisors for tax, legal and financial advice respecting the establishment of a royalty trust. Members of PRL’s senior management reviewed various structures and considered the tax and business consequences in relation to such structures. In mid-April of 2002, members of PRL’s senior management proposed to PRL’s board of directors the formation of a trust to hold a number of mature producing properties of PRL.

         Pursuant to the proposal, PRL would distribute the units of such trust to the holders of PRL Common Shares through a dividend-in-kind. The mature, net cash generating, producing properties to be transferred to the trust were considered to be suitable for a trust and management believed the transaction would be financially beneficial to shareholders of PRL as the securities markets have recently tended to place a premium valuation on assets of this type when held by royalty trusts as opposed to corporations. A fundamental underlying business purpose of the transaction was to eliminate the layer of corporate income tax attributable to the production income from the properties, as the income from a trust may be flowed through more efficiently to its beneficiaries than by a corporation to its shareholders. This consideration was particularly important given the substantial amount of taxes PRL would be incurring and which would negatively impact its financial flexibility and growth plans as cash available for capital expenditures would be reduced.

         While PRL was considering the trust proposal it was provided the opportunity to acquire Summit Resources Limited (“Summit”). The proposed formation of PET was publicly announced on May 12, 2002 in conjunction with PRL’s announcement that it had entered into an agreement to acquire Summit for cash consideration of $7.40 per share for an aggregate value, including assumed debt, of $332 million. The Summit acquisition was completed on June 28, 2002. While the trust proposal and the Summit transaction were separate transactions, the acquisition of Summit was considered complementary and strategic for two key reasons. First, while the Summit acquisition was strategic to PRL as a result of the operational overlap, the Summit properties also allowed PRL to maintain the size and scale of its operations following the sale of PRL’s mature assets to POT under the trust proposal. The two transactions taken together effectively result in PRL trading relatively mature assets out of its portfolio in return for additional growth assets of similar size which are located in PRL’s key core area of central Alberta. Secondly, the Summit transaction provided many of the items required to effect the initial public offering of PET which would otherwise be an incremental cost, including accounting systems and staff, office space and furniture, land records system, and computer systems and software.

         In addition, the sale of PRL’s interest in the Additional Assets provides PRL with an indirect means to finance part of the Summit acquisition.

         At meetings of the board of directors of PRL held on April 18, 2002 and May 1, 2002, upon receiving advice from financial, legal and tax advisors, the board of directors of PRL gave its initial approval to the structuring of the current transaction and most of the essential terms thereof and instructed its advisors to commence preparation of the documentation required to implement the transaction. Thereafter, weekly meetings were held until the week of August 5, 2002 at which a working group consisting of PRL’s financial, legal and tax advisors and representatives of management of PRL and of the Administrator reviewed and directed the progress of the preparation of the documentation. Legal counsel for the Dealer Managers also provided input into the preparation of the documentation.

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Special Committee

         In conjunction with the approvals of the board of directors of PRL at the April 18, 2002 and May 1, 2002 meetings and to further consider the trust proposal, the Special Committee of PRL’s board of directors, consisting of John B. Roy (as Chairman), Dirk Jungé, David M. Knott and Bernie M. Wylie, was established.

         The Special Committee members are independent of the management of PRL and its largest shareholder, POG. The mandate of the Special Committee is to assess the merits of the transactions comprised of: the formation of PET, the Trust Structuring, the Dividend, the Rights Offering and the sale of PRL’s interest in the Additional Assets under the Take-Up Agreement, essentially on the terms previously established by the board of directors of PRL and to consider such other alternative courses of action to carry out the intent and purpose of those transactions as may be appropriate in the circumstances. Specifically, the Special Committee was granted the authority to assess the transactions with a view to whether or not the transactions are in the best interests of PRL and are fair, from a financial point of view, to the PRL Shareholders and to provide a recommendation to the board of directors of PRL with respect thereto. The Special Committee was not authorized to, and did not, negotiate the terms of the transaction.

         The Special Committee first met on May 3, 2002 to review and discuss its mandate. The Special Committee engaged Macleod Dixon LLP as its legal counsel. In addition, the Special Committee, with the assistance of Macleod Dixon LLP, selected Paul, Weiss, Rifkind, Wharton & Garrison to act as its United States legal counsel.

         At a meeting held on May 15, 2002, the Special Committee met with Scotia Capital Inc., considered its qualifications and ultimately retained it to serve as financial advisor to the Special Committee and to prepare and deliver a fairness opinion in respect of the transaction. The Special Committee satisfied itself that Scotia Capital Inc. was a qualified and independent advisor and competent to provide the financial services required by the Special Committee. Scotia Capital Inc. has not provided any financial advisory services or participated in any equity financing involving PRL or its associates or affiliates, of a material nature, within the past two years, other than the services provided in connection with its engagement by the Special Committee. The sole shareholder of Scotia Capital Inc. is one of five lenders in PRL’s banking syndicate, the agent bank of which is another Canadian chartered bank, and has been a participant in this syndicate since April 2001. The sole shareholder of Scotia Capital Inc. is also one of the three participants in the acquisition credit facilities for PRL in respect of the acquisition of Summit and has committed to participate in a credit facility for PET and POT. Scotia Capital Inc. has advised us that the fees paid or which remain payable in connection with these credit facilities are not material to the sole shareholder of Scotia Capital Inc. At this time, the fees remaining to be paid relate solely to participation in the facility for the Summit acquisition and are not related to the Trust Structuring or the opinion prepared by Scotia Capital Inc.

         Between May 15 and •, 2002, the Special Committee met • times with its legal and financial advisors. At these meetings, Scotia Capital Inc. provided the Special Committee with information on the royalty trust market in general and together with Macleod Dixon LLP updated the Special Committee on the progress of the transaction and related issues. The Special Committee members were active participants in these meetings, initiating and participating in discussions, making inquiries and requesting follow-up materials or analysis. At the June 20, 2002 meeting, Macleod Dixon LLP advised the members of the Special Committee of their legal duties and responsibilities in the discharge of their duties. Macleod Dixon LLP discussed with members of the Special Committee their duties of care and loyalty as prescribed under the Business Corporations Act (Alberta). The role of the Special Committee in the context of the transaction was discussed, including the necessity for the members of the Special Committee to act for a proper purpose which is in the best interests of PRL and not for any collateral or conflicting purpose, the duty to be informed with respect to the business risks and opportunities of PRL and the ability of the Special Committee in accordance with its mandate to utilize the services of outside counsel and independent financial advisors. Discussion was also held regarding the process to be followed by the Special Committee in making a reasoned and informed decision in respect of the transaction and in the exercise of its business judgment. These matters were considered and discussed by the Special Committee members in detail. At the meeting held on June 27, 2002, the Special Committee, together with its legal and financial advisors, reviewed the Trust Structuring, transaction mechanics and the material agreements underlying the Trust Structuring and how these material agreements related to the transactions referred to in this prospectus.

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         Between May 29 and August 7, 2002, Mr. Roy, together with the Special Committee’s legal and financial advisors, attended weekly meetings of all parties involved in the transaction, including management of PRL, the Administrator and their legal, tax and financial advisors, and provided updates to the Special Committee of the status and progress of the transaction. The Special Committee meetings were typically scheduled to follow these working group meetings so the Special Committee could be apprised of the status of the transaction and any outstanding issues. In addition, Mr. Roy, as Chairman of the Special Committee, met or communicated with Scotia Capital Inc. and Macleod Dixon LLP on a daily basis.

         On August 7, 2002, Scotia Capital Inc. presented to the Special Committee the results of its financial analysis and together with Macleod Dixon LLP reviewed the material terms of the formation of the Trust, the Trust Structuring, the Dividend, the Rights Offering and the acquisition under the Take-Up Agreement. At the meeting on August 7, 2002, Scotia Capital Inc. presented the primary factors it had considered to assess the financial fairness of the trust proposal to the PRL Shareholders. Specifically, Scotia Capital Inc. advised the Special Committee that it had considered: (i) PRL’s business objectives for initiating the trust proposal; (ii) certain financial and business attributes of PRL, both on a stand-alone basis and after giving effect to the trust proposal; (iii) certain financial and business attributes of PET; (iv) the procedures and steps being undertaken to implement the trust proposal; (v) certain subjective factors respecting PET and PRL; (vi) certain of the strategic alternatives to the trust proposal which may be available to PRL; and (vii) certain other factors relating to the Canadian royalty trust and exploration and production sectors.

         The financial analysis Scotia Capital Inc. presented to the Special Committee included its assessment of the expected trading ranges of the PRL Common Shares and Trust Units of PET after the completion of the trust proposal on a fully-settled basis together with the value which is potentially obtainable through the exercise or sale of the Rights, as compared to the current and historical trading range of the PRL Common Shares. Scotia Capital Inc. outlined that the extent to which a PRL Shareholder realizes value from the trust proposal may depend upon the nature and timing of that individual’s investment decisions respecting any of the PRL Common Shares, Trust Units or Rights. Scotia Capital Inc. advised that the expected trading range for the Trust Units and, indirectly, the Rights, will be influenced principally by cash on cash yield. However, Scotia Capital Inc. also advised they considered other secondary market valuation methodologies or benchmarks applicable to a sample of comparable trusts (in respect of PET), and corporations (in respect of PRL, both before and following the reorganization) selected by Scotia Capital Inc. and which it considered to be appropriate for this purpose, including those relating to entity value, market capitalization, public float, asset composition, reserve life index, net asset value, leverage, and operations or business. Scotia Capital Inc. advised the Special Committee that the trading ranges of the Trust Units and Rights could be adversely affected while Trust Units and Rights re-circulate from PRL Shareholders to new investors due to the nature of the Trust Units representing an investment in a trust as compared to an investment in a corporation.

         Scotia Capital Inc. also considered the possible tax consequences of the trust proposal on PRL and PRL Shareholders, having received advice from legal counsel as to the application of tax rules.

         Scotia Capital Inc. calculated the net present value of the projected future cash flows for PRL before giving effect to the trust proposal and for PET and PRL after giving effect to the trust proposal. Scotia Capital Inc. advised the Special Committee that it considered the terms of the Rights Offering which it determined were structured so as to provide a measure of intrinsic value to holders of Trust Units and to maximize the probability of the exercise of the outstanding Rights. Scotia Capital Inc. also considered the procedural steps being undertaken in implementing the trust proposal.

         PRL’s prospects as a stand-alone entity and the limited alternatives to the trust proposal which were considered by PRL, assuming it did not implement the trust proposal and remained operating under its current and prospective business plan, relative to the trust proposal and the prospects of PRL and PET following the trust proposal were addressed by Scotia Capital Inc. for the Special Committee.

         Scotia Capital Inc.’s presentation to the Special Committee was subject to the express qualifications and limitations which are set forth in the opinion of Scotia Capital Inc. set forth at page A-1 of this prospectus.

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         In presenting its views to the Special Committee, Scotia Capital Inc. followed its standard internal procedures which include, among other things, due diligence review of applicable documentation and financial, asset and operating information, formal due diligence sessions with the management of PRL and PET, presentation to, and review with a committee of senior members of Scotia Capital Inc. with experience in mergers, acquisitions, valuations and fairness opinions. Scotia Capital Inc.’s committee supported the view that the transaction was fair from a financial point of view. PRL and PET did not impose any limitations or restrictions on the scope of Scotia Capital Inc.’s work or its access to information or analysis and instructed Scotia Capital Inc. to perform the analysis without restriction. Scotia Capital Inc. recommends that investors review the full text of its opinion beginning on page A-1.

         The Special Committee also considered the preliminary prospectus and registration statement prepared in respect of the proposed distribution of the Dividend, the Rights Offering and related transactions. Scotia Capital Inc. presented its views to the Special Committee of the financial aspects of the Dividend, the Rights Offering and related transactions, including its view, as of August 7, 2002, of the fairness of these transactions from a financial point of view to the PRL Shareholders. Scotia Capital Inc. tabled a draft of the form of fairness opinion which Scotia Capital Inc. intends to provide at the time that the final prospectus and registration statement were filed with the appropriate securities regulatory authorities. After discussion and receipt of advice from its financial and legal advisors, the Special Committee unanimously determined to recommend to the full board of directors of PRL that the transaction was in the best interests of PRL and the PRL Shareholders, to proceed with the filing of the preliminary prospectus and registration statement with the appropriate securities regulatory authorities and that it approve the steps necessary at this time to implement the transaction. The Special Committee further advised the board of directors that it would present its final recommendations with respect to the transaction at the time of filing the final prospectus in the context of the financial, business and other applicable circumstances then in existence.

         On August 7, 2002, the board of directors of PRL met and received the preliminary report of the Special Committee and unanimously gave its approval to proceed with the transactions referred to in this prospectus and to file the preliminary prospectus and registration statement with the appropriate securities regulatory authorities.

PET, POT and the Administrator

PET

         PET is an unincorporated trust established on June 28, 2002 under the laws of the Province of Alberta pursuant to a trust indenture among Computershare Trust Company of Canada as trustee, BMO Nesbitt Burns Inc. as settlor, and the Administrator. This trust indenture was subsequently amended and restated effective as of August 1, 2002 (the “PET Trust Indenture”). Computershare Trust Company of Canada has been appointed as the trustee (the “Trustee”) of PET. At the date of this prospectus, one Trust Unit of PET, which was issued on June 28, 2002, is outstanding and is held by PRL. The assets of PET consist of 100% ownership of the Administrator, the ownership of 100% of the beneficial interests of POT and its organizational funding of $100.

         PET was established for the purposes of issuing Trust Units and acquiring and holding royalties and other investments including the entire beneficial interest in POT and the POT Royalty. PET will effectively finance the operations of POT. PET will distribute cash to its Unitholders, which will initially be comprised of royalty and interest income PET receives from POT and from ARTC, if any, less expenses and any other amounts it must withhold or pay to third parties. Under the PET Trust Indenture, PET has broad powers to invest funds that are not distributed to Unitholders. See “The PET Trust Indenture”, page 91.

POT

         POT is an unincorporated trust established on June 28, 2002 under the laws of the Province of Alberta pursuant to a trust indenture between the Administrator as trustee, and CIBC World Markets Inc. as settlor, with PET as its sole beneficiary. This trust indenture was subsequently amended and restated effective as of August 1, 2002 (the “POT Trust Indenture”). At the date of this prospectus, POT’s assets consist of its organizational funding of $100 and certain

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furniture, fixtures and computers acquired from Summit as of July 1, 2002 in exchange for an interest bearing promissory note in the amount of $2,073,000 which will be subordinated to all other indebtedness of POT. Under the terms of the POT Trust Indenture, the Administrator is the trustee of POT. POT’s business is acquiring, developing, exploiting, owning and disposing of oil and natural gas properties. See “The POT Trust Indenture”, page 98.

The Administrator

         The Administrator was incorporated on June 28, 2002 under the Business Corporations Act (Alberta) (the “ABCA”). All of the issued and outstanding shares of the Administrator are beneficially held by PET. As trustee of POT, the Administrator will hold legal title to the assets and properties of POT on behalf of, and for the benefit of, POT and will administer, manage and operate the oil and gas business of POT. The Administrator, in its capacity as trustee, will retain employees to administer, manage and operate the oil and gas business of POT. In addition, the Trustee has, in accordance with the PET Trust Indenture, effectively delegated to the Administrator the significant management, administrative and governance functions with respect to PET. Unlike many conventional royalty trusts, we will not have an external management company. The day-to-day running of our business will be carried out by the Administrator rather than a third party as is the case in many conventional royalty trusts. We will therefore not incur the management fees and expenses that would be charged by an external management company. Much like a traditional oil and gas corporation, only costs incurred by or on behalf of the Administrator to operate our business will ultimately be borne by the Unitholders. See “The PET Trust Indenture”, page 91, “The POT Trust Indenture”, page 98 and “The Administrator”, page 102.

Headquarters

         The principal business office of both PET and POT, and the registered address and principal business office of the Administrator, is 500, 630 – 4th Avenue S.W., Calgary, Alberta, T2P 0J9, telephone: (403) 269-4400.

Trust Structuring

         Upon the effectiveness of the U.S. registration statement in which this prospectus is included and the issuance of the final receipts for the Canadian Prospectus, the Trust Structuring will be executed in the following order:

(a)

PRL will convey to POT, pursuant to the terms of the Sale Agreement, all of PRL’s interest in the Initial Assets. See “Initial Business and Properties of POT”, page 58. POT will pay for the Initial Assets by delivering to PRL a demand promissory note in the amount of approximately $81,000,000 and will, together with PET, provide a secured guarantee in respect of $20,000,000 of PRL’s indebtedness to PRL’s lenders. In addition, under the Sale Agreement, interest on the $81,000,000 purchase price, at a rate of 6.5% per annum from July 1, 2002, will accrue to PRL. We will assume all risks on the Initial Assets, and revenues and expenses associated with the Initial Assets will accrue to POT for POT’s account, as of July 1, 2002.

(b)

PRL and POT will execute the Take-Up Agreement which requires PRL to sell and transfer, and obligates POT to purchase, subject to certain conditions, up to 100% of PRL’s interest in the Additional Assets. POT will pay a deposit on the purchase price of these assets through the issuance of a non-interest bearing promissory note to PRL in the amount of $5,000,000. If closing under the Take-Up Agreement does not occur due to a breach of the agreement by POT, the deposit may be forfeited to PRL and PRL may demand payment under the promissory note. The conveyance of the acquired interest in the Additional Assets will occur upon the completion of the Rights Offering. We will assume all risks on the Additional Assets, and revenues and expenses associated with the acquired interest in the Additional Assets will accrue to POT for POT’s account, as of July 1, 2002. See “Formation of Trust Structure and Structuring Transactions – Rights Offering and Take-Up of Additional Assets”, page 34 and “Business and Properties Relating to the Additional Assets – The Take-Up Agreement”, page 73.

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(c)	POT and PET will enter into the POT Royalty Agreement effective as of July 1, 2002, pursuant to which POT will grant the POT Royalty with respect to the Initial Assets, the Additional Assets (to the extent POT acquires them) and all other petroleum and natural gas properties POT may acquire from time to time. Pursuant to the POT Royalty Agreement, PET will receive 99% of POT’s net revenue from its petroleum and natural gas properties, less permitted deductions with respect to debt payments, capital expenditures and certain other amounts. PET will pay for the POT Royalty by issuing a first promissory note in the amount of $30,000,000 and a second demand promissory note in the amount of $34,152,000. The first promissory note is a demand note and will bear annual interest equal to the prime rate of a major Canadian chartered bank from time to time plus 1.875% from the date of issuance. POT will direct PET to pay and issue these two promissory notes to PRL in satisfaction of $64,152,000 of the indebtedness that POT owes PRL for the purchase of the Initial Assets under the Sale Agreement. This payment will reduce the principal amount of indebtedness that POT owes PRL to approximately $16,848,000 which will be represented by a demand promissory note that will bear annual interest from the date of issue equal to the prime rate of a major Canadian chartered bank from time to time plus 1.875%. PET will grant a security interest to PRL in PET’s assets as security for its indebtedness under the first promissory note and POT will grant a guarantee to PRL for such indebtedness and will grant to PRL a security interest over its assets for the guarantee.
(d)	PET will issue 6,636,045 Trust Units to PRL in full repayment of the indebtedness under the second promissory note.
(e)	PET will purchase from PRL the remaining $16,848,000 in indebtedness that POT owes to PRL in exchange for the issuance to PRL of an additional 3,273,721 Trust Units.
(f)	At this point in the Trust Structuring, PET’s assets will be comprised of the POT Royalty, interest- bearing indebtedness of POT in the principal amount of $16,848,000 and 100% of the beneficial interest in POT.
(g)	At this point in the Trust Structuring, PET’s liabilities will be comprised of a principal amount of $30,000,000 owing to PRL and a contingent liability of $20,000,000 arising from the secured guarantee in favor of PRL’s lenders.

         All of the above referenced promissory notes not payable to PRL will be subordinated and postponed in certain circumstances pursuant to arrangements in favor of our lenders under our proposed credit facilities.

Dividend-in-Kind

         Following completion of the Trust Structuring, PRL’s board of directors will declare and pay the Dividend, payable by the distribution of the Dividend Units, being all 9,909,767 of the Trust Units that PRL will then hold as a result of the Trust Structuring. See “Details of the Dividend”, page 63. PRL is required to withhold and remit taxes in an amount equal to 25% of the fair market value of the Dividend Units paid to PRL Shareholders who are neither resident nor deemed to be resident in Canada for the purposes of the Tax Act, including PRL Shareholders that are partnerships, any member of which is neither resident nor deemed to be resident in Canada for the purposes of the Tax Act (the “Non-Resident Shareholders”), subject to reduction under an applicable tax treaty (for example, under the tax treaty with the United States such withholding is generally reduced to 15%). See “Details of the Dividend – Withholding of Tax”, page 64.

Rights Offering and Take-Up of Additional Assets

         After PRL’s distribution of the Dividend Units, PET will issue to holders of Trust Units of record on the Rights Record Date, Rights to subscribe for additional Trust Units on the basis of three Rights for each Trust Unit held. See “Details of the Rights Offering”, page 66.

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         If all of the Rights are exercised, the gross proceeds of the Rights Offering will be $150,132,970. Under the terms of the Take-Up Agreement, we are obligated to apply the gross proceeds of the Rights Offering, along with the proceeds of available bank financing that we have arranged, to acquire up to 100% of PRL’s interest in the Additional Assets. The purchase price of 100% of PRL’s interest in the Additional Assets will be $220,000,000. We will assume all risks on the Additional Assets POT acquires, and revenues and expenses associated with the relevant percentage interest in the Additional Assets will accrue to POT for POT’s account, as of July 1, 2002. Assuming all of the Rights are exercised and our lenders advance the full amount of $100,000,000 under our proposed credit facility, there will be sufficient funds available to repay the $30,000,000 we will owe to PRL arising from the acquisition of the Initial Assets and acquire 100% of PRL’s interest in the Additional Assets. If less than all of the Rights are exercised or our lenders do not loan to us our requested loan under the proposed credit facility, we will use the gross proceeds of the Rights Offering, to repay the $30,000,000 we will owe to PRL arising from the acquisition of the Initial Assets, and use the remainder of such proceeds together with the amount our lenders are willing to advance us under our proposed credit facility to acquire as much of an interest as we are able in the Additional Assets. The interest in the Additional Assets that we will acquire will be proportionate to the amount that such remainder is to the total purchase price of the Additional Assets. To the extent we do not acquire 100% of PRL’s interest in the Additional Assets, PRL will continue to have an interest in the Additional Assets. See “Bank Financing and Guarantees”, page 65.

         PRL’s lenders have agreed to release the $20,000,000 secured guarantee we will have provided to them in favor of PRL, arising from our acquisition of the Initial Assets, on the conditions that: (i) all of the Rights held by or on behalf of POG, Treherne and 409790 are exercised; (ii) we use the net proceeds of the Rights Offering together with available bank financing to repay the $30,000,000 we will owe to PRL arising from the acquisition of the Initial Assets and acquire up to 100% of PRL’s interest in the Additional Assets; and (iii) PRL is not in default under its credit facilities with its lenders. PRL, C.H. Riddell, POG, Treherne and 409790 have entered into the Rights Exercise Agreement with PRL’s lenders which obligates POG, Treherne and 409790 to exercise all Rights held by or on behalf of them, thereby subscribing for all Trust Units available to them under the Initial Subscription Privilege. POG and its subsidiaries are required to provide evidence to PRL’s lenders of their financial ability to subscribe for such Trust Units. Under the terms of the Rights Exercise Agreement, POG, Treherne and 409790 represent that they have in place available bank financing which, when combined with an amount of $33,000,000 owing by PRL to POG, and other funds available to POG, Treherne and 409790, will be sufficient to allow these parties to acquire all of the Trust Units that will be available to them under the Initial Subscription Privilege for the Rights that they will receive. The funding of amounts under their credit arrangements are conditional upon a number of things, including the provision by POG, Treherne and 409790 to their lenders of sufficient collateral. In the event that POG, Treherne and 409790 are unable to draw down the required amounts under these facilities, or PRL is not in a position to pay to POG the full amount that PRL owes to POG, POG, Treherne and 409790 may not be able to exercise all of their Rights. See “Details of the Rights Offering — Intentions of Insiders and Others to Exercise Rights”, page 69.

         The following diagram illustrates our structure following the completion of the Trust Structuring, the Dividend, the Rights Offering and the acquisition under the Take-Up Agreement of an interest in the Additional Assets.

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PLAN OF OPERATIONS

         Our goal is to provide Unitholders with a tax effective vehicle through which we can distribute income and add value through the exploitation of the Initial Assets and our interest in the Additional Assets as well as through prudent acquisitions of further assets. We believe that the Initial Assets and an interest in the Additional Assets will provide a good basis for the establishment of a royalty trust. The properties comprised in the Initial Assets and the Additional Assets are located in close proximity to one another in northeast Alberta, Canada, have a long production history and have demonstrated a predictable decline in reserves over the years. The assets are comprised of natural gas properties that require low capital reinvestment. We anticipate that cash flow from the Initial Assets and the interest POT acquires in the Additional Assets will be sufficient to fund our production and administrative expenses, interest, capital expenditures and to permit us to accumulate working capital for our on-going operations. We do not anticipate that it will be necessary to

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raise any additional funds in the next eighteen (18) months to meet such expenses and expenditures, nor for working capital.

         Historically, production from the properties comprising part of the Initial Assets and the Additional Assets has been marketed internally by PRL’s gas marketers. POT’s internal marketing group will continue to market production from the Initial Assets and the Additional Assets with a view to optimizing gas netbacks by seeking out the best markets. Transportation of our production will be continually monitored to obtain the lowest possible transportation fees. Once we have completed the Rights Offering we anticipate that we will have 85 full and part-time employees. The technical staff at PRL who have been responsible for managing the Initial Assets and Additional Assets for a number of years are employed by the Administrator for and on behalf of POT and will be responsible for the ongoing management of these properties on behalf of POT. The continuity of this technical team should ensure the continued efficient exploitation of our asset base. See “The Administrator – Employees”, page 107.

Exploitation Drilling

         We intend to optimize the value of the Initial Assets and our interest in the Additional Assets by exploiting the natural gas production potential associated with these properties. We will focus our capital expenditures on drilling low risk development wells to maximize production and cash flow. We believe that the Initial Assets and the Additional Assets have developmental potential that fit our conservative definition of acceptable risk. In addition, we believe our ownership of processing and transportation facilities and our large consolidated acreage position will allow us to realize operating synergies and thus maintain operating costs at their current levels. We intend to farmout higher risk exploration projects, by entering into agreements with third parties whereby they will provide exploration funding in exchange for an earned interest, or sell properties which we do not feel will provide adequate returns or do not have an acceptable risk profile.

Acquisitions

         While we initially intend to pursue the acquisition of other properties in our core areas as well as seek corporate opportunities focused on natural gas, we also expect to pursue acquisition opportunities to diversify from our current commodity and geographic focus. Our primary objective is the creation of value for Unitholders and as such we will target acquisitions that are accretive to our net asset value and our cash flow and which increase our reserve and production base. We will target the acquisition of high quality, long reserve life assets with substantial low risk development potential and low capital requirements. We will not limit our acquisitions by commodity or geography and plan to finance such acquisitions through debt and equity financings. While we do not currently intend to make any particular acquisition, we believe there are many opportunities to make prudent acquisitions in the current market place.

TRENDS

         We perceive a number of trends that may affect our business, including:

• Consolidation of Industry Participants. Our industry has been experiencing a large number of business combinations, involving companies of all sizes. This consolidation process has resulted in a number of asset rationalization programs pursuant to which assets have become available for acquisition. This same consolidation process has resulted in some of the industry participants with whom we will be competing for attractive large asset or share acquisitions having become larger and more competitive which may increase the demand for acquisitions.

• Investor Focus. Investors are becoming increasingly aware of the oil and natural gas royalty trust sector and the income trust sector (“Trust Sector”). We believe that due to the nature of the assets held by royalty trusts, as well as their focus on development and exploitation rather than exploration, investor interest in the oil and natural gas sector has increased with the growing perception that royalty trusts, such as PET, offer a vehicle to invest in the oil and natural gas industry with less risk than more traditional oil and natural gas investments. Consequently, the

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	Trust Sector has recently been able to access the capital markets more readily than traditional oil and gas companies. This access to capital has made the Trust Sector a competitor for oil and natural gas property and corporate acquisitions. The Trust Sector has an advantage over oil and gas companies in corporate taxation. A number of Canadian-based oil and gas companies are currently taxable, having depleted their accumulated tax pools, and therefore they generally assess the merits of potential acquisitions on an “after-tax” basis. Oil and gas royalty trusts and income trusts distribute income to their unitholders. Units of these royalty and income trusts are often held in tax sheltered vehicles such as registered retirement savings plan accounts, and distributions on the units held in such vehicles are thus generally sheltered from immediate taxation.
•	Foreign Investment. Non-Canadian companies have been investing heavily in the Canadian oil and natural gas industry by acquiring both property and companies. In particular, companies from the United States have been attracted to the Canadian market to acquire supplies of natural gas, in part by the weakness of the Canadian dollar relative to the United States dollar and the development of additional pipeline facilities for the efficient transmission of natural gas to the United States markets. Management believes this trend will continue to influence Canadian asset valuation parameters and will result in truly North American valuations for Canadian producers.
•	Price Volatility. Our income and the value of your Trust Units will be affected by fluctuations in the price of natural gas. Natural gas pricing is largely a function of supply and demand and has been very volatile. For example, prices per GJ, based on the Alberta Reference Price, fluctuated between $2.50 and $8.29 in 2000, $2.40 and $11.42 in 2001, and between $2.71 and $3.91 from January through April of 2002. The price of natural gas in the North American markets reached record highs in late 2000 and early 2001, partly because of the demand created by new gas-fired electrical generating facilities and ultimately led to fuel switching in an effort by some consumers to minimize its effect. This switching, along with a number of other factors, including mild weather during late 2001, caused a material shift in demand for natural gas and resulted in large volumes of natural gas being stored. This led to a sharp decline in natural gas prices. Although natural gas is expected to remain in tight supply, the increased storage volumes should reduce some of the volatility in natural gas prices.

FUTURE DEVELOPMENT

         The McDaniel Report estimates that future capital costs of $2.6 million will be required over the life of the proved reserves for the drilling, completion, equipping and tie-in of up to 4 wells and the equipping, tie-in and recompletion of up to 13 wells included in the proved reserves. Additionally, many of the areas comprised in the Initial Assets and Additional Assets include remaining exploitation opportunities. We have currently identified a minimum of 55 development drilling locations including:

• Approximately 20 development wells in the Legend Area.

• The installation of three field compressors to increase gas deliverability from the Legend Area.

• Six development wells at Corner.

• Six development wells at Legend East.

• Two development wells at Liege South.

• Two development wells at Teepee Creek.

         The foregoing exploitation opportunities, which we believe to be low risk, will be implemented over the next few years at the discretion of the Administrator as economic factors such as commodity prices, operating costs and gas production rates change whether due to market conditions or through the optimization of operations by the Administrator. The spending of additional capital beyond the estimates contained in the McDaniel Report would be intended to increase

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value to Unitholders through the acceleration of production, increasing of recoverable reserves and decreasing of gas production rate declines.

SELECTED FINANCIAL DATA AND FINANCIAL AND PRODUCTION INFORMATION

         The following is a summary of certain selected historical financial data and financial and production information and is qualified in its entirety by the detailed provisions of the attached Financial Statements for PRL’s Northeast Alberta Properties on page F-7 for the years ended December 31, 2001, 2000 and 1999, together with the unaudited six month interim periods ended June 30, 2002 and 2001, contained elsewhere in this prospectus. Selected information for the unaudited period ended December 31, 1998 and 1997 is also set forth below.

PRL Northeast Alberta Properties Selected Financial Data⁽⁴⁾
(Cdn $000 except as indicated)

	Six Months Ended
	June 30				Year ended
	2002		2001		2001		2000		1999		1998(5)		1997(5)
	(unaudited)										(unaudited)
Canadian GAAP
Revenue (Before royalties and hedging)		56,385		174,775		235,641		195,927		131,805		109,944		83,696
Net Earnings		34,896		51,374		67,914		51,825		27,319		(1)		(1)
Total assets		281,070				299,853		301,633		261,093		(1)		(1)
Net assets (Investment by Paramount Resources Ltd.)		122,030				172,113		195,085		214,497		(1)		(1)
US GAAP(2)(3)
Total assets		281,861				304,170		301,633		261,093		(1)		(1)
Net assets (Investment by Paramount Resources Ltd.)		129,313				175,070		195,085		214,497		(1)		(1)

Notes:

(1)	Certain of the selected financial data has not been provided for 1998 and 1997, as financial statements have not been prepared for the PRL Northeast Alberta Properties on a stand alone basis for those periods. See below for selected financial data on the Initial Assets and Additional Assets.
(2)	The differences between Canadian GAAP and US GAAP are described in the notes to the financial statements of the PRL Northeast Alberta Properties.
(3)	Other than disclosed here, the Canadian GAAP and US GAAP amounts are the same for the items included in the selected financial data.
(4)	The operations of PRL in its northeast Alberta core area as presented in the financial statements for the PRL’s Northeast Alberta Properties presented elsewhere in this prospectus. The Northeast Alberta Properties include the Initial Assets, the Additional Assets and the Excluded Assets. The Excluded Assets generated $7.4 million of revenue for the year ended December 31, 2001. (See “Government Regulations – Regulatory Rulings”, page 111).
(5)	The 1997 and 1998 figures are unaudited and we have not filed a comfort letter with respect to such numbers with any securities regulatory authority.

Selected Financial and Production Information for the Initial Assets and the Additional Assets

	Six Months Ended June 30,
	2002									2001
	Initial			Addl.			Total			Initial			Addl.			Total
(Cdn$000 except as indicated)	Assets			Assets			Assets			Assets			Assets			Assets
Production (mmcf/d)		18.6			76.7			95.3			15.6			93.7			109.3
Price ($/mcf)	$	3.42		$	3.14		$	3.20		$	6.52		$	8.96		$	8.61
Revenue	$	11,520		$	43,611		$	55,131		$	18,404		$	152,030		$	170,434
Royalties		(2,418	)		(6,948	)		(9,366	)		(5,063	)		(25,827	)		(30,890	)
Operating Costs		(3,220	)		(12,757	)		(15,977	)		(2,733	)		(14,226	)		(16,959	)
Operating Income(2)	$	5,882		$	23,906		$	29,788		$	10,608		$	111,977		$	122,585

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							Years Ended December 31,
				2001									2000
	Initial			Addl.			Total			Initial			Addl.			Total
(Cdn$000 except as indicated)	Assets			Assets			Assets			Assets			Assets			Assets
Production (mmcf/d)		17.3			85.4			102.7			14.0			93.4			107.4
Price ($/mcf)	$	4.51		$	6.41		$	6.09		$	4.74		$	4.65		$	4.65
Revenue	$	28,492		$	199,791		$	228,283		$	24,357		$	158,370		$	182,727
Royalties		(8,888	)		(36,873	)		(45,761	)		(6,366	)		(28,825	)		(35,191	)
Operating Costs		(4,628	)		(28,242	)		(32,870	)		(3,318	)		(20,828	)		(24,146	)
Operating Income(2)	$	14,976		$	134,676		$	149,652		$	14,673		$	108,717		$	123,390

											Years Ended December 31,
				1999									1998(1)									1997(1)
(Cdn $000 except as indicated)	Initial			Addl.			Total			Initial			Addl.			Total			Initial			Addl.			Total
	Assets			Assets			Assets			Assets			Assets			Assets			Assets			Assets			Assets
Production (mmcf/d)		14.0			99.0			113.0			14.6			120.9			135.5			9.7			79.1			88.8
Price ($/mcf)	$	2.64		$	2.60		$	2.61		$	1.92		$	1.90		$	1.90		$	2.00		$	1.96		$	1.96
Revenue	$	13,426		$	94,149		$	107,575		$	10,250		$	83,724		$	93,974		$	7,084		$	56,546		$	63,630
Royalties		(2,765	)		(20,008	)		(22,773	)		(1,569	)		(12,212	)		(13,781	)		(1,353	)		(9,097	)		(10,450	)
Operating Costs		(754	)		(17,357	)		(18,111	)		(1,554	)		(18,391	)		(19,945	)		(902	)		(9,867	)		(10,769	)
Operating Income(2)	$	9,907		$	56,784		$	66,691		$	7,127		$	53,121		$	60,248		$	4,829		$	37,582		$	42,411

(1)	The 1997 and 1998 figures are unaudited and we have not filed a comfort letter with respect to such numbers with any securities regulatory authority.
(2)	For the purposes of the tables immediately above, operating income excludes gains or losses related to hedging which are considered corporate rather than operating activities.

         The information set out above and in the financial statements for PRL’s Northeast Alberta Properties for the years ended December 31, 2001, 2000 and 1999 and the unaudited six month interim periods ended June 30, 2002 and 2001 contained elsewhere in this prospectus with respect to the Additional Assets assumes the acquisition by POT of 100% of PRL’s interest in the Additional Assets. See note 3 to the pro forma consolidated financial statements beginning on page F-25 for information on additional potential Rights exercise scenarios. In the event the Rights Offering is not fully subscribed or if, for any reason (including the failure of POG, Treherne and 409790 to acquire all of the Trust Units that will be available to them under the Initial Subscription Privilege for the Rights that they will receive) our lenders do not loan to us our requested loan under the proposed credit facility that we have arranged with them, POT may be unable to acquire 100% of PRL’s interest in the Additional Assets and POT may only be able to acquire a lesser percentage interest or no interest in the Additional Assets. See “Business and Properties Relating to the Additional Assets”, page 73 and “Bank Financing and Guarantees”, page 65.

SELECTED PRO FORMA FINANCIAL AND PRODUCTION INFORMATION

         The following is a summary of certain selected pro forma historical financial and production information and is qualified in its entirety by the detailed provisions of PET’s pro forma statements for the six month period ended June 30, 2002 and for the year ended December 31, 2001, contained elsewhere in this prospectus.

Six Months Ended June 30, 2002
(Cdn$000)

					Additional Assets												Total to PET
		Initial Assets			Rights @ 100%			Rights @ 75%			Rights @ 50%			Rights @ 100%			Rights @ 75%			Rights @ 50%
Revenue:
	Sales of natural gas	$	11,520		$	43,611		$	35,955		$	23,434		$	55,131		$	47,475		$	34,954
	Hedging		—			—			—			—			10,709			9,222			6,790
	Royalties		(2,418	)		(6,948	)		(5,728	)		(3,733	)		(9,366	)		(8,146	)		(6,151	)
			9,102			36,663			30,227			19,701			56,474			48,551			35,593
Expenses:
	Operating		3,220			15,977			13,738			10,075			15,977			13,738			10,075
	General and administrative														2,070			2,070			2,070
	Interest														2,126			1,864			1,437

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			Additional Assets					Total to PET
		Initial Assets	Rights @ 100%	Rights @ 75%	Rights @ 50%	Rights @ 100%		Rights @ 75%		Rights @ 50%
	Depletion and depreciation						28,816		24,344		17,030
	Site restoration						1,522		1,264		843
							50,511		43,280		31,455
Net Earnings						$	5,963	$	5,271	$	4,138
Net Earnings per Trust Unit
	Basic					$	0.15	$	0.16	$	0.17
	Diluted					$	0.15	$	0.16	$	0.17

Year ended December 31, 2001
(Cdn. $000)

					Additional Assets												Total to PET
		Initial Assets			Rights @ 100%			Rights @ 75%			Rights @ 50%			Rights @ 100%			Rights @ 75%			Rights @ 50%
Revenue:
	Sales of natural gas	$	28,492		$	199,791		$	164,719		$	107,356		$	228,283		$	193,211		$	135,848
	Hedging		—			—			—			—			8,838			7,480			5,259
	Royalties		(8,888	)		(36,873	)		(30,400	)		(19,813	)		(45,761	)		(39,288	)		(28,701	)
			19,604			162,918			134,319			87,543			191,360			161,403			112,406
Expenses:
	Operating		4,628			28,242			23,284			15,176			32,870			27,912			19,804
	General and administrative														4,498			4,498			4,498
	Interest														4,250			3,453			2,656
	Depletion and Depreciation														63,478			53,435			37,008
	Site restoration														3,398			2,820			1,874
															108,494			92,118			65,840
Net Earnings														$	82,866		$	69,285		$	46,566
Net Earnings per Trust Unit
	Basic													$	2.09		$	2.15		$	1.88
	Diluted													$	2.09		$	2.15		$	1.88

         The information set out above and in PET’s pro forma statements for the six month period ended June 30, 2002 and for the year ended December 31, 2001 contained elsewhere in this prospectus with respect to the Additional Assets assumes the acquisition by POT of 100% of PRL’s interest in the Additional Assets. See note 3 to the pro forma consolidated financial statements beginning on page F-25 for information on additional potential Rights exercise scenarios. In the event the Rights Offering is not fully subscribed or if, for any reason (including the failure of POG, Treherne and 409790 to acquire all of the Trust Units that will be available to them under the Initial Subscription Privilege for the Rights that they will receive) our lenders do not loan to us our requested loan under the proposed credit facility that we have arranged with them, POT may be unable to acquire 100% of PRL’s interest in the Additional Assets and POT may only be able to acquire a lesser percentage interest or no interest in the Additional Assets. See “Business and Properties Relating to the Additional Assets”, page 73 and “Bank Financing and Guarantees”, page 65.

MANAGEMENT’S DISCUSSION AND ANALYSIS AND LIQUIDITY AND CAPITAL RESOURCES

         You should read the following discussion of our financial condition and results of operations together with our audited balance sheets, the financial statements for PRL’s Northeast Alberta Properties and the pro forma financial statements beginning on page F-1 of this prospectus.

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Selected Financial and Operating Information

	Six Months Ended June 30,				Years Ended December 31,
	2002		2001		2001		2000		1999
Initial Assets
Natural Gas Reserves (bcf)(2)(3)		49.8		n/a		49.6		52.0		53.6
Gas Production (mmcf/d)		18.6		15.6		17.3		14.0		14.0
Gas Price ($/mcf)		3.42		6.52		4.51		4.74		2.64
Revenue ($000’s)		11,520		18,404		28,492		24,357		13,426
Operating Income ($000’s)(4)		5,882		10,608		14,976		14,673		9,907
Additional Assets
Natural Gas Reserves (bcf)(2)(3)		111.4		n/a		135.7		167.1		262.1
Gas Production (mmcf/d)		76.7		93.7		85.4		93.4		99.0
Gas Price ($/mcf)		3.14		8.96		6.41		4.65		2.60
Revenue ($000’s)		43,611		152,030		199,791		158,370		94,149
Operating Income ($000’s)(4)		23,906		111,977		134,676		108,717		56,784
Northeast Alberta Properties (1)
Natural Gas Reserves (bcf)(2)(3)		163.9		n/a		188.0		258.1		357.3
Gas Production (mmcf/d)		97.2		111.8		105.6		119.5		138.7
Gas Price ($/mcf)		3.21		8.64		6.11		4.49		2.60
Royalty Rate (%)		17.2		18.0		20.1		19.8		21.6
Revenue ($000’s)		56,385		174,775		235,641		195,927		131,805
Operating Income ($000’s)(4)		30,504		126,188		154,367		131,793		82,364

Notes:

(1)	The operations of PRL in its northeast Alberta core area as presented in the financial statements for PRL’s Northeast Alberta Properties presented elsewhere in this prospectus. The Northeast Alberta Properties include the Initial Assets, the Additional Assets and the Excluded Assets. The Excluded Assets generated $7.4 million of revenue for the year ended December 31, 2001. (See “Government Regulations – Regulatory Rulings”, page 111).
(2)	Reserves are gross working and/or royalty interests share of reserves before deducting royalties owned by others.
(3)	Reserves include total proved reserves.
(4)	Operating income excludes gains or losses related to hedging which are considered corporate rather than operating activities.

         General

         Historically, PRL has maintained accounting records necessary to support its consolidated financial statements and for other internal or tax reporting purposes. PRL has not previously prepared separate complete financial statements for the Northeast Alberta Properties or for any of its other core areas. While the amounts applicable to the Northeast Alberta Properties for certain revenues, expenses, assets and liabilities can be derived directly from the accounting records of PRL, it has been necessary to allocate certain items in the manner described in the notes to the financial statements. While we believe the methods of allocation chosen are most representative of the nature of the activities at PRL and most consistent with the purposes and objective of the financial statements presented in this prospectus, other methods of allocation could result in significantly different amounts. In addition, an amount resulting from the allocation of revenues, expenses, assets or liabilities of PRL may not be indicative of the amount that would have resulted if the PRL Northeast Alberta Properties had existed as an independent entity during the periods covered by the financial statements or that would result in future periods.          As of July 1, 2002, the estimated gross proved natural gas reserves of the Northeast Alberta Properties were 163.9 bcf (net 132.6 bcf after all royalties payable). For the six months ended June 30, 2002, the PRL Northeast Alberta Properties produced an average of 97.2 mmcf per day of natural gas. The Northeast Alberta Properties are located entirely in the Province of Alberta, Canada and produce only natural gas. Consequently, our initial operations will comprise one geographic and one business segment.

         The Northeast Alberta Properties earn income from the sale of natural gas within the Province of Alberta, Canada.

         The expenses of the Northeast Alberta Properties include:

         •     Royalties paid to the Province of Alberta and others. The rate of such royalties varies in relation to volume of production and
               natural gas prices.

         •     Operating costs related to the production and transportation of natural gas including, but not limited to, labor, utilities,
               chemicals, gathering costs, repairs, maintenance and overhead.

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         Due to the maturity of the properties and the declining level of capital investment in the northeast Alberta area, cumulative cash flow from these areas has exceeded the amounts invested and excess cash flow has been used in conjunction with bank financing to fund the exploration and development in PRL’s growth areas. For these reasons, no amount of the debt, or associated interest costs, have been allocated to the northeast Alberta area.

         Period to period fluctuations in the operating income of the Northeast Alberta Properties are the result of a combination of a number of factors including:

         •     The volume of natural gas produced and sold.

         •     The exchange rate between Canadian and U.S. dollars as Canadian natural gas prices tend to fluctuate, in part, in relation to
               changes in U.S. prices.

         •     Changes in royalties paid to mineral owners, expressed as a percentage of revenues (the “Royalty Rate”).

         •     Changes in the operating costs of producing natural gas from the Northeast Alberta Properties.

         •     Changes in Canadian and North American natural gas prices.

         Approximately one-half of the natural gas produced from the Northeast Alberta Properties is sold under dedicated arrangements with natural gas aggregators who then re-sell gas to numerous additional third parties.

         Two reference prices which often provide an indication of overall Canadian and North American natural gas prices are the “Alberta Reference Price” in Canada and “NYMEX” prices in the U.S. The Alberta Reference Price is the monthly weighted average price for gas consumed in Alberta and gas exported from Alberta reduced for allowances for transportation and marketing. The NYMEX price represents the average of the last three days closing trading prices of the near month natural gas futures contracts on the New York Mercantile Exchange. While reference prices are generally a good indicator of natural gas price market conditions, the changes in prices realized by the Northeast Alberta Properties are not always consistent with those in reference prices as natural gas produced from the Northeast Alberta Properties is sold to specific producers and ultimately delivered to markets which may not experience conditions entirely consistent with reference prices.

           Results of Operations

         The financial and operating information of the Northeast Alberta Properties has been prepared in accordance with Canadian generally accepted accounting principles (“Canadian GAAP”). Canadian GAAP differs in some respects from generally accepted accounting principles in the United States, such differences are described in note 6 to the historic financial statements of the Northeast Alberta Properties on page F-7.

         The following analysis considers the combined results of operations for the Northeast Alberta Properties followed by a separate discussion of each of the Initial Assets and Additional Assets (production, revenues, royalties and operating costs). The impact of the trust structure on the results of operations on the Northeast Alberta Properties, such as the impact on interest expense and the provision for income taxes, are reflected in the pro forma financial statements and the accompanying notes.

           Northeast Alberta Properties

Six Months Ended June 30, 2002 Compared to the Six Months Ended June 30, 2001

         Natural gas sales for the Northeast Alberta Properties decreased 68 percent to $56.4 million for the six months ended June 30, 2002, compared to $174.8 million for the six months ended June 30, 2001. Decreased production volumes resulted in a $22.9 million decrease in revenue while lower natural gas prices decreased revenue by $95.5 million.

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         Realized natural gas prices dropped correspondingly by 63 percent for the first half of 2002 to $3.21 per mcf from $8.64 per mcf in 2001. Average Alberta Reference Prices dropped 43 percent from $8.98 per GJ for the first half of 2001 to $3.88 per GJ for the first half of 2002. The Northeast Alberta Properties realized a decrease in average natural gas prices greater than that for the reference prices due to the fact that production was higher in the early part of 2001 when prices were higher and then declined later in the year. Consequently, the 2001 first half price for the Northeast Alberta Properties was relatively higher than the reference price. The decrease in gas prices resulted from lower demand due to a mild winter and weaker economic conditions combined with increased supply. During the same period, U.S. NYMEX natural gas prices decreased 48 percent to U.S.$2.88 per Mmbtu from U.S.$6.04 per Mmbtu in the 2001 quarter. A 3 percent decrease in the Canada/U.S. exchange rate was offset by increased Canadian transportation capacities which reduced transportation costs for Canadian natural gas.

         Natural gas production for the Northeast Alberta Properties decreased 13 percent during the 2002 period to 97.1 mmcf/d from 111.8 mmcf/d in the first half of 2001, as production additions realized from the drilling of 57 (48.8 net) natural gas wells with a 92 percent success rate, during the 18 months ended June 30, 2002 did not offset natural production declines.

         For the six months ended June 30, 2002, the Royalty Rate for the Northeast Alberta Properties was 17.2% compared to 18.0% for the first half of 2001. Royalty Rates in Alberta are sensitive to reference prices and consequently the average Royalty Rate decreased with reference prices. However, as Royalty Rates are on a sliding scale to reference prices, the Royalty Rate change was less than that for prices.

         While total production costs decreased $1.0 million due to the overall production volume decrease, unit production costs increased 9 percent in the first half of 2002 to $0.92 per mcf from $0.85 per mcf in the first half of 2001. First half production costs are typically higher than the annual average as most of the Northeast Alberta Properties are located in winter-only access areas and much activity occurs prior to spring break-up. Furthermore, the Northeast Alberta Properties include plant facilities and gathering systems intended to facilitate the delivery of natural gas to market. These facilities incur fixed costs which are in addition to costs incurred at the well level thereby increasing total production costs. As production declines in mature areas such as those areas comprising the Northeast Alberta Properties, unit production costs increase. Specifically, the 2002 operating cost increases were experienced in the areas of engine and equipment repairs and maintenance, well service and workovers and compressor overhauls.

         The significantly lower commodity prices and to a lesser extent the production declines described above combined to reduce operating income for the Northeast Alberta Properties by 76 percent from $126.2 million to $30.5 million for the six months ended June 30, 2002, compared to the same period in 2001:

($Cdn millions)
Production decrease	$	(22.9	)
Price decrease		(95.5	)
Royalty decrease		21.7
Operating cost decrease		1.0
Decrease in net operating income	$	(95.7	)

         We presently expect gas production from the Northeast Alberta Properties to approximate that predicted in the McDaniel Report, declining over time at an average annual rate of approximately 20%. Royalty Rates and unit operating costs are not expected to change materially from amounts outlined in the McDaniel Report, being a Royalty Rate of 20% and unit operating costs of $0.76 per mcf.

         The Northeast Alberta Properties were allocated a portion of PRL’s overall derivative hedging, general and administrative expenses and income taxes as described in note 1 to the historic financial statements for the Northeast Alberta Properties.

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         Hedging gains allocated to the Northeast Alberta Properties were a gain of $11.0 million in 2002 compared to a loss of $17.3 million in 2001. See note 5 to the historical financial statements for the Northeast Alberta Properties for details of outstanding derivative instruments at June 30, 2002, page F-16.

         Allocated general and administrative expenses decreased from $2.1 million in the first six months of 2001 to $2.0 million in the first six months of 2002 period. This decrease is related to decreased production volumes for the Northeast Properties in 2002.

         During 2000, the Alberta Energy and Utilities Board (the “AEUB”) issued a decision regarding the Surmont natural gas bitumen co-production issue. The Surmont property is in northeast Alberta, is not acquired by PET and is one of the Excluded Assets. As a result of this decision, the AEUB ordered the shut-in of approximately 22 mmcf/d of PRL’s production. On February 28, 2002 PRL and other Surmont gas producers entered into a Memorandum of Understanding with the Province of Alberta effective May 1, 2000. The Memorandum provided for the compensation of approximately $85 million to be paid to PRL and the other Surmont producers by the Alberta Crown, as well as granting to the Province of Alberta an 11% gross overriding royalty encompassing certain wells, land and leases affected by the shut-in order of May 1, 2000. In June 2002, PRL received approximately $47 million from the Province of Alberta as compensation for its proportionate share of the settlement. The cash settlement, net of the book value of associated wells, lands and leases in the affected area, was recorded as a gain of $37.1 million in net earnings in the six months ended June 30, 2002. See “Government Regulation – Regulatory Rulings”, page 111.

         Total allocated income taxes decreased from $38.1 million for the first six months of 2001 to $16.2 million in 2002. This decrease is consistent with lower earnings before tax in the first six months of 2002.

Year Ended December 31, 2001 Compared to the Year Ended December 31, 2000

         Natural gas sales for the Northeast Alberta Properties increased 20 percent to $235.6 million for the year ended December 31, 2001 compared to $195.9 million in 2000. Significantly higher natural gas prices in 2001 increased revenue by $62.5 million and offset the effects of natural production declines which reduced revenue by $22.8 million. The Northeast Alberta Properties realized an average natural gas price of $6.11 per mcf in 2001, an increase of 36 percent from $4.49 per mcf in 2000. Average Alberta Reference Prices increased 25 percent over the same period from $5.02 per GJ in 2000 to $6.30 per GJ in 2001. During the same period U.S. NYMEX natural gas prices increased by 13 percent to U.S.$4.40 per Mmbtu from U.S.$3.91 per Mmbtu in 2000. Canadian reference prices increased by more than U.S. reference prices due to the combination of a four percent decrease in the Canada/U.S. exchange rate and lower transportation differentials between Canadian and U.S. gas prices related to increased pipeline capacity from Canada. Continued concerns about gas supply contributed to very high prices in early 2001 and resulted in the increase in the average price over 2000. Prices fell through much of 2001 as demand weakened and supply responded to increased North American drilling activity. The Northeast Alberta Properties realized an increase in average natural gas prices greater than that for the reference prices due to the fact that production was higher in the early part of 2001 when prices were higher and then declined later in the year.

         Average natural gas production for the Northeast Alberta Properties decreased 12 percent in 2001 to 105.6 mmcf/d from 119.5 mmcf/d in 2000. Production additions from the drilling of 39 (34.3 net) natural gas wells with a 93 percent success rate in 2001 were offset by natural production declines as well as the fact that 2000 included production from the Surmont properties, which was shut-in during 2000 due to the bitumen co-production issue described above, for part of that year.

         The average Royalty Rate for 2001 increased to 20.1 percent from 19.8 percent in 2000. While Royalty Rates in Alberta are sensitive to prices, the 2001 rate increase was less than the natural gas price increase for the Northeast Alberta Properties, as Royalty Rates reach maximum amounts at higher price levels such as those achieved in 2001.

         Unit production costs in 2001 increased 52 percent to $0.88 per mcf from $0.58 per mcf in 2000, while total operating costs increased by $8.6 million. The Northeast Alberta Properties include plant facilities and gathering systems

45

intended to control the flow of our natural gas to market. These facilities incur fixed costs, which are in addition to costs incurred at the well level, thereby increasing total production costs. As production declines in more mature areas, such as those areas comprising the Northeast Alberta Properties, per unit production costs increase. Furthermore, with increased levels of industry activity in 2001 compared to 2000, competition for services increased labor costs including well supervision and contract operating of wells as well as related aviation support and overhead, increasing costs in these categories. There were also an unusually large amount of repairs, maintenance and overhaul expenditures on the Northeast Alberta Properties in 2001 as PRL installed amine treatment facilities in a number of areas.

         Higher commodity prices in 2001 more than offset production declines and higher production costs resulting in operating income for the Northeast Alberta Properties increasing by 17 percent to $154.4 million from $131.8 million in 2000 as follows:

($Cdn millions)
Production decrease	$	(22.8	)
Price increase		62.5
Royalty increase		(8.5	)
Operating cost increase		(8.6	)
Increase in net operating income	$	22.6

         The Northeast Alberta Properties were allocated a portion of PRL’s overall derivative hedging, general and administrative expenses and income taxes as described in note 1 to the historic financial statements for the Northeast Alberta Properties.

         Hedging gains allocated to the Northeast Alberta Properties were a gain of $9.1 million in 2001 compared to a loss of $0.5 million in 2000. See note 5 to the historical financial statements for the Northeast Alberta Properties for details of outstanding derivative instruments at December 31, 2001, page F-16.

         Allocated general and administrative expenses increased from $4.9 million in 2000 to $5.5 million in the 2001. This increase resulted from the Northeast Alberta Properties comprising a greater proportion of overall PRL production in 2001.

         Total allocated income taxes increased from $47.0 million in 2000 to $47.9 million in 2001. This increase resulted from the Northeast Alberta Properties comprising a greater proportion of overall PRL earnings before taxes in 2001 due to increased depletion charges in PRL’s other core areas.

Year Ended December 31, 2000 Compared to the Year Ended December 31, 1999

         Natural gas sales for the Northeast Alberta Properties increased 49 percent to $195.9 million for the year ended December 31, 2000, compared to $131.8 million in 1999. Significantly higher natural gas prices in 2000 increased revenue by $82.4 million and offset the effects of natural production declines which decreased revenue by $18.2 million. The Northeast Alberta Properties realized an average natural gas price of $4.49 per mcf in 2000, an increase of 73 percent from $2.60 per mcf in 1999. Average Alberta Reference Prices increased 70 percent over the same period from $2.96 per GJ in 1999 to $5.02 per GJ in 2000. During the same period U.S. NYMEX natural gas prices increased by 72 percent to U.S.$3.91 per Mmbtu from U.S.$2.27 per Mmbtu in 1999. The changes in Canadian and U.S. reference prices were consistent as average Canada/U.S. exchange rates were unchanged from 1999 to 2000 and the change in prices realized by Northeast Alberta Properties was consistent with the change in reference prices. Tight supply and increased demand and concerns about the ability of North American producers to deliver additional gas volumes contributed to the gas price increases in 2000.

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         Average natural gas production for the Northeast Alberta Properties decreased 14 percent in 2000 to 119.5 mmcf/d from 138.7 mmcf/d in 1999. Production additions from the drilling of 41 (31.9 net) natural gas wells in 2000 with a 97 percent success rate were offset by natural production declines. During 2000 production was also shut-in on most of the Surmont properties due to the natural gas bitumen co-production issue.

         The average Royalty Rate for 2000 decreased to 19.8 percent from 21.6 percent in 1999. Royalties on the Northeast Alberta Properties are calculated and paid based on the Alberta Reference Price. The gas price for the Northeast Alberta Properties increased by more than the Alberta Reference Price in 2000. However, the average Royalty Rate decreased slightly because royalties were calculated and paid based upon the Alberta Reference Price.

         Unit production costs in 2000 increased 41 percent to $0.58 per mcf from $0.41 per mcf in 1999 and total operating costs increased by $4.5 million. The Northeast Alberta Properties include plant facilities and gathering systems intended to control the flow of natural gas to market. These facilities incur fixed costs, which are in addition to costs incurred at the well level, thereby increasing total production costs. As production declines in more mature areas, such as those areas comprising the Northeast Alberta Properties, per unit production costs increase. The Northeast Alberta Properties also experienced overall increases in labor charges, aviation support, property taxes and overhead in 2000.

         Significantly higher commodity prices in 2000 more than offset production declines and higher production costs resulting in operating income for the Northeast Alberta Properties increasing by 60 percent to $131.8 million from $82.4 million in 1999 as follows:

($Cdn millions)
Production decrease	$	(18.2	)
Price increase		82.4
Royalty increase		(10.3	)
Operating cost increase		(4.5	)
Increase in net operating income	$	49.4

         The Northeast Alberta Properties were allocated a portion of PRL’s overall derivative hedging, general and administrative expenses and income taxes as described in note 1 to the historic financial statements for the Northeast Alberta Properties, page F-11.

         Hedging gains allocated to the Northeast Alberta Properties were a gain of $1.1 million in 1999 compared to a loss of $0.5 million in 2000.

         Allocated general and administrative expenses decreased from $5.5 million in 1999 to $4.9 million in 2000. This decrease resulted from the Northeast Alberta Properties comprising a lesser proportion of overall PRL production in 2000.

         Total allocated income taxes increased from $19.0 million in 1999 to $47.0 million in 2000. This increase resulted from the significant increase in earnings before taxes in 2000.

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Initial Assets

Six Months Ended June 30, 2002 Compared to the Six Months Ended June 30, 2001

         Natural gas sales for the Initial Assets decreased 37 percent to $11.5 million for the six months ended June 30, 2002, compared to $18.4 million for the six months ended June 30, 2001. Increased production volumes resulted in a $3.5 million increase in revenue while lower natural gas prices decreased revenue by $10.4 million. Realized natural gas prices dropped by 47 percent for the first half of 2002 to $3.42 per mcf from $6.51 per mcf in 2001. The change in average gas prices for the Initial Assets was consistent with that in reference prices as Alberta Reference Prices dropped 43 percent from $8.98 per GJ for the first half of 2001 to $3.88 per GJ for the first half of 2002. The decrease in gas prices resulted from lower demand due to a mild winter and weaker economic conditions combined with increased supply. During the same period, U.S. NYMEX natural gas prices decreased 48 percent to U.S.$2.88 per Mmbtu from U.S.$6.04 per Mmbtu in the 2001 quarter. A 3 percent decrease in the Canada/U.S. exchange rate was offset by increased Canadian transportation capacities which reduced transportation costs.

         Natural gas production for the Initial Assets increased 19 percent during the period to 18.6 mmcf/d from 15.6 mmcf/d in the first half of 2001, as production additions were realized from the drilling of 19 (16.5 net) natural gas wells with a 100 percent success rate, during the 18 months ended June 30, 2002.

         For the six months ended June 30, 2002, the Royalty Rate decreased to 21.0 percent from 27.5 percent as compared to the six months ended June 30, 2001. Royalty Rates in Alberta are on a sliding scale sensitive to prices. Consequently the decrease in the average Royalty Rate is consistent with lower natural gas prices in the corresponding half of 2002.

         While total production costs increased by $0.5 million in the first six months of 2002 due to higher production, unit production costs were consistent at $0.96 and $0.97 per mcf in the first half of 2002 and 2001, respectively.

         The significantly lower commodity prices more than offset production additions and resulted in operating income for the Initial Assets decreasing by 45 percent from $10.6 million to $5.9 million for the six months ended June 30, 2002, compared to the same period in 2001 as follows:

($Cdn millions)
Production increase	$	3.5
Price decrease		(10.4	)
Royalty decrease		2.7
Operating cost increase		(0.5	)
Decrease in net operating income	$	(4.7	)

         We presently expect gas production from the Initial Assets to approximate that predicted in the McDaniel Report, declining over time at an average annual rate of 13%. Royalty Rates and unit operating costs are not expected to change materially from amounts outlined in the McDaniel Report, being a Royalty Rate of 20% and unit operating costs of $0.76 per mcf.

Year Ended December 31, 2001 Compared to the Year Ended December 31, 2000

         Natural gas sales for the Initial Assets increased 17 percent to $28.5 million for the year ended December 31, 2001 compared to $24.4 million in 2000. Increased production volumes increased revenue by $5.6 million which was offset by a decrease of $1.5 million related to decreased natural gas prices. The Initial Assets realized an average natural gas price of $4.51 per mcf in 2001, a decrease of 5 percent from $4.74 per mcf in 2000. Average Alberta Reference Prices increased 25 percent over the same period from $5.02 per GJ in 2000 to $6.30 per GJ in 2001. During the same

48

period U.S. NYMEX natural gas prices increased by 13 percent to U.S.$4.40 per Mmbtu from U.S.$3.91 per Mmbtu in 2000. Canadian reference prices increased by more than U.S. reference prices due to the combination of a four percent decrease in the Canada/U.S. exchange rate and lower transportation differentials between Canadian and U.S. gas prices related to increased pipeline capacity from Canada. A large portion of the gas produced from the Initial Assets was sold under contracts dedicated to certain natural gas aggregators. The prices realized on these contracts did not increase in relation to reference prices in 2001.

         Average natural gas production for the Initial Assets increased 24 percent in 2001 to 17.3 mmcf/d from 14.0 mmcf/d in 2000. Production additions from the drilling of 8 (7.3 net) natural gas wells with a 100 percent success rate in 2001 offset natural production declines.

         The average Royalty Rate on the Initial Assets for 2001 increased to 31.2 percent from 26.1 percent in 2000. Royalty Rates in Alberta are sensitive to reference prices and consequently the average Royalty Rate increased with reference prices.

         Production costs increased by $1.3 million in 2001 from 2000 in relation to increased production. As well, unit production costs in 2001 increased 12 percent to $0.73 per mcf from $0.65 per mcf in 2000. With increased levels of industry activity in 2001 compared to 2000, competition for services increased labor costs including well supervision and contract operating of wells as well as related aviation support and overhead, thus increasing costs in these categories.

         Lower commodity prices in 2001 were offset by production additions resulting in operating income for the Initial Assets increasing by 2 percent to $15.0 million from $14.7 million in 2000 as follows:

($Cdn millions)
Production increase	$	5.6
Price decrease		(1.5	)
Royalty increase		(2.5	)
Operating cost increase		(1.3	)
Increase in net operating income	$	0.3

Year Ended December 31, 2000 Compared to the Year Ended December 31, 1999

         Natural gas sales for the Initial Assets increased 82 percent to $24.4 million for the year ended December 31, 2000, compared to $13.4 million in 1999. Significantly higher natural gas prices resulted in the entire increase in revenue. The Initial Assets realized an average natural gas price of $4.74 per mcf in 2000, an increase of 79 percent from $2.64 per mcf in 1999. Average Alberta Reference Prices increased 70 percent over the same period from $2.96 per GJ in 1999 to $5.02 per GJ in 2000. During the same period U.S. NYMEX natural gas prices increased by 72 percent to U.S.$3.91 per Mmbtu from U.S.$2.27 per Mmbtu in 1999. The changes in Canadian and U.S. reference prices were consistent as average Canada/U.S. exchange rates were unchanged from 1999 to 2000 and the change in prices realized by Initial Assets was consistent with the change in reference prices. Tight supply and increased demand and concerns about the ability of North American producers to deliver additional gas volumes contributed to the gas price increases in 2000. Average natural gas production for the Initial Assets was unchanged at 14.0 mmcf/d in both 1999 and 2000.

         The average Royalty Rate for the Initial Assets for 2000 increased to 26.1 percent from 20.6 percent in 1999. Royalty Rates in Alberta are sensitive to reference prices and consequently the average Royalty Rate increased with reference prices.

         Unit production costs in 2000 increased 333 percent to $0.65 per mcf from $0.15 per mcf in 1999 and total operating costs increased by $2.5 million in 2000. The Initial Assets include plant facilities and gathering systems intended to control the flow of natural gas to market. In addition to labor, overhead and gas processing charges increasing

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in 2000, a significant amount of equipment repairs and maintenance and well workover activity was undertaken in 2000 in order to maintain production volumes.

         Significantly higher commodity prices in 2000 more than offset higher production costs resulting in operating income for the Initial Assets increasing by 48 percent to $14.7 million from $9.9 million in 1999 as follows:

($Cdn millions)
Price increase		10.9
Royalty increase		(3.6	)
Operating cost increase		(2.5	)
Increase in net operating income	$	4.8

Additional Assets

Six Months Ended June 30, 2002 Compared to the Six Months Ended June 30, 2001

         Natural gas sales for the Additional Assets decreased 71 percent to $43.6 million for the six months ended June 30, 2002, compared to $152.0 million for the six months ended June 30, 2001. Decreased production volumes resulted in a $27.6 million decrease in revenue while lower natural gas prices decreased revenue by $80.8 million. Realized natural gas prices dropped correspondingly by 65 percent for the first half of 2002 to $3.14 per mcf from $8.96 per mcf in 2001. Average Alberta Reference Prices dropped 43 percent from $8.98 per GJ for the first half of 2001 to $3.88 per GJ for the first half of 2002. The Additional Assets realized a decrease in average natural gas prices greater than that for the reference prices due to the fact that natural gas sales attributable to production from the Additional Assets was higher in the early part of 2001 when prices were higher and then declined later in the year. Consequently, the 2001 price for the Additional Assets was relatively higher than the reference price. The decrease in gas prices resulted from lower demand due to a mild winter and weaker economic conditions combined with increased supply. During the same period, U.S. NYMEX natural gas prices decreased 48 percent to U.S.$2.88 per Mmbtu from U.S.$6.04 per Mmbtu in the 2001 quarter. A 3 percent decrease in the Canada/U.S. exchange rate was offset by increased Canadian transportation capacities which reduced transportation costs.

         Natural gas production for the Additional Assets decreased 18 percent during the period to 76.7 mmcf/d from 93.7 mmcf/d in the first half of 2001, as production additions realized from the drilling of 38 (32.3 net) natural gas wells with an 89 percent success rate, during the 18 months ended June 30, 2002 did not offset natural production declines.

         For the six months ended June 30, 2002, the Royalty Rate for the Additional Assets was 15.9% compared 17.0% for the first half of 2001. Royalty Rates in Alberta are on a sliding scale sensitive to prices. Consequently the decrease in the average Royalty Rate is consistent with lower natural gas prices in the corresponding half of 2002.

         While total production costs decreased by $1.5 million due to the decrease in production, unit production costs increased 10 percent in the first half of 2002 to $0.92 per mcf from $0.84 per mcf in the first half of 2001. First half production costs are typically higher than the annual average as most of the Additional Assets are located in winter-only access areas and much activity occurs prior to spring break-up. Furthermore, the Additional Assets include plant facilities and gathering systems intended to control the flow of natural gas to market. These facilities incur fixed costs which are in addition to costs incurred at the well level thereby increasing total production costs. As production declines in mature areas such as those areas comprising the Additional Assets, unit production costs increase. Specifically, the 2002 operating cost increases were experienced in the areas of engine and equipment repairs and maintenance, well service and workovers and compressor overhauls.

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         The significantly lower commodity prices and to a lesser extent the production declines described above combined to reduce operating income for the Additional Assets by 79 percent from $112.0 million to $23.9 million for the six months ended June 30, 2002, compared to the same period in 2001:

($Cdn millions)
Production decrease	$	(27.6	)
Price decrease		(80.8	)
Royalty decrease		18.8
Operating cost decrease		1.5
Decrease in net operating income	$	(88.1	)

         We presently expect gas production from the Additional Assets to approximate that predicted in the McDaniel Report, declining over time at an average annual rate of 20.5%. Royalty Rates and unit operating costs are not expected to change materially from amounts outlined in the McDaniel Report, being a Royalty Rate of 20% and unit operating costs of $0.76 per mcf.

Year Ended December 31, 2001 Compared to the Year Ended December 31, 2000

         Natural gas sales for the Additional Assets increased 26 percent to $199.8 million for the year ended December 31, 2001 compared to $158.4 million in 2000. Significantly higher natural gas prices in 2001 increased revenue by $55.0 million which offset the effects of natural production declines which reduced revenue by $13.5 million. The Additional Assets realized an average natural gas price of $6.41 per mcf in 2001, an increase of 38 percent from $4.65 per mcf in 2000. Average Alberta Reference Prices increased 25 percent over the same period from $5.02 per GJ in 2000 to $6.30 per GJ in 2001. During the same period U.S. NYMEX natural gas prices increased by 13 percent to U.S.$4.40 per Mmbtu from U.S.$3.91 per Mmbtu in 2000. Canadian reference prices increased by more than U.S. reference prices due to the combination of a four percent decrease in the Canada/U.S. exchange rate and lower transportation differentials between Canadian and U.S. gas prices related to increased pipeline capacity from Canada. Continued concerns about gas supply contributed to very high prices in early 2001 and resulted in the increase in the average price over 2000. Prices fell through much of 2001 as demand weakened and supply responded to increased North American drilling activity. The Additional Assets realized an increase in average natural gas prices greater than that for the Reference Prices due to the fact that production was higher in the early part of 2001 when prices were higher and then declined later in the year.

         Average natural gas production for the Additional Assets decreased 9 percent in 2001 to 85.4 mmcf/d from 93.4 mmcf/d in 2000. Production additions from the drilling of 31 (27.0 net) natural gas wells with a 92 percent success rate in 2001 were offset by natural production declines.

         The average Royalty Rate for the Additional Assets for 2001 increased to 18.5 percent from 18.2 percent in 2000. While Royalty Rates in Alberta are sensitive to prices, the 2001 rate increase was less than the natural gas price increase for the Additional Assets, as Royalty Rates reach maximum amounts at higher price levels such as those achieved in 2001.

         Unit production costs in 2001 increased 49 percent to $0.91 per mcf from $0.61 per mcf in 2000 and total operating costs increased by $7.5 million. The Additional Assets include plant facilities and gathering systems intended to control the flow of our natural gas to market. These facilities incur fixed costs, which are in addition to costs incurred at the well level, thereby increasing total production costs. As production declines in more mature areas, such as those areas comprising the Additional Assets, per unit production costs increase. Furthermore, with increased levels of industry activity in 2001 compared to 2000, competition for services increased labor costs including well supervision and contract operating of wells as well as related aviation support and overhead. There were also an unusually large amount of repairs, maintenance and overhaul expenditures on the Additional Assets in 2001 as PRL installed amine treatment facilities in a number of areas.

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         Higher commodity prices in 2001 more than offset production declines and higher unit production costs resulting in operating income for the Additional Assets increasing by 24 percent to $134.7 million from $108.7 million in 2000 as follows:

($Cdn millions)
Production decrease	$	(13.5	)
Price increase		55.0
Royalty increase		(8.0	)
Operating cost increase		(7.5	)
Increase in net operating income	$	26.0

Year Ended December 31, 2000 Compared to the Year Ended December 31, 1999

         Natural gas sales for the Additional Assets increased 68 percent to $158.4 million for the year ended December 31, 2000, compared to $94.1 million in 1999. Significantly higher natural gas prices in 2000 increased revenue by $69.6 million and offset the effects of natural production declines which reduced revenue by $5.3 million. The Additional Assets realized an average natural gas price of $4.65 per mcf in 2000, an increase of 79 percent from $2.60 per mcf in 1999. Average Alberta Reference Prices increased 70 percent over the same period from $2.96 per GJ in 1999 to $5.02 per GJ in 2000. During the same period U.S. NYMEX natural gas prices increased by 72 percent to U.S.$3.91 per Mmbtu from U.S.$2.27 per Mmbtu in 1999. The changes in Canadian and U.S. reference prices were consistent as average Canada/U.S. exchange rates were unchanged from 1999 to 2000 and the change in prices realized by Additional Assets was consistent with the change in reference prices. Tight supply and increased demand and concerns about the ability of North American producers to deliver additional gas volumes contributed to the gas price increases in 2000.

         Average natural gas production for the Additional Assets decreased 6 percent in 2000 to 93.4 mmcf/d from 99.0 mmcf/d in 1999. Production additions from the drilling of 37 (28.4 net) natural gas wells in 2000 with a 97 percent success rate were offset by natural production declines.

         The average Royalty Rate for 2000 decreased to 18.2 percent from 21.3 percent in 1999. Royalties on the Additional Assets are calculated and paid based on the Alberta Reference Price. The gas price for the Additional Assets increased by more than the Alberta Reference Price in 2000. However, the average Royalty Rate decreased slightly and total operating costs increased by $3.5 million because royalties were calculated and paid based upon the Alberta Reference Price.

         Unit production costs in 2000 increased 27 percent to $0.61 per mcf from $0.48 per mcf in 1999. The Additional Assets include plant facilities and gathering systems intended to control the flow of natural gas to market. These facilities incur fixed costs, which are in addition to costs incurred at the well level, thereby increasing total production costs. As production declines in more mature areas, such as those areas comprising the Additional Assets, per unit production costs increase. The Additional Assets also experienced increases in labor charges, aviation support, property taxes and overhead in 2000.

         Significantly higher commodity prices in 2000 more than offset production declines and higher production costs resulting in operating income for the Additional Assets increasing by 91 percent to $108.7 million from $56.8 million in 1999 as follows:

($Cdn millions)
Production decrease	$	(5.3	)
Price increase		69.5
Royalty increase		(8.8	)
Operating cost increase		(3.5	)
Increase in net operating income	$	51.9

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Liquidity and Capital Resources

PRL Northeast Alberta Properties

         No additional capital expenditures are planned for the remainder of 2002. Our 2003 budget presently totals $6.5 million for the drilling, completion and tie-in of 11 wells as well as facility upgrades principally in the Legend area. PRL’s capital expenditures on the Initial Assets and Additional Assets totalled $41.8 million in 2001. The cost of drilling and completing a well in these areas is approximately $400,000 to $500,000.

         The McDaniel Report includes a total of $5.2 million in estimated future capital costs over the life of the reserves required for the drilling, completion, equipping and tie-in of up to 8 wells and the equipping, tie-in and recompletion of up to 28 wells included in the proved plus probable reserves of the Northeast Alberta Properties. We have no additional material known future capital requirements. While there are no significant seasonal limitations on gas production from the Northeast Alberta Properties, the Northeast Alberta Properties are located in winter access areas and consequently, capital and operating expenditures tend to be higher in winter months.

         Mineral and surface rentals for the Initial Assets and the Additional Assets are payable to the Province of Alberta and others for both producing and non-producing acreage. Such payments are estimated to total $1,498,210, $1,383,063, $1,326,884, $1,282,487 and $1,270,756 in 2003, 2004, 2005, 2006 and 2007, respectively. Paramount Energy Trust

         Our internal source of cash in the future will initially be entirely the net operating income generated by the Initial Assets and Additional Assets and distributions to Unitholders will be limited to available cash after costs of operation and capital expenditures related to the properties. In addition to available bank financing and cash flow from the Initial Assets and the Additional Assets, we may issue additional Trust Units in the future.

         We estimate the gross proceeds of the Rights Offering to be approximately $150,132,970, assuming the Rights Offering is fully subscribed. We will use the gross proceeds together with available bank financing to repay the $30,000,000 we owe to PRL arising from the acquisition of the Initial Assets and acquire up to 100% of PRL’s interest in the Additional Assets pursuant to the Take-Up Agreement. At that time, taking into account net income that will accrue to POT from July 1, 2002 until the anticipated closing, it is estimated that our outstanding long-term debt will be approximately $75,000,000. This $75,000,000 figure assumes that the Rights Offering is fully subscribed and that our lenders advance to us the full $100,000,000 under our proposed credit facility.

         A syndicate of financial institutions have agreed, pursuant to the terms and conditions of a commitment letter, to provide PET with a demand revolving credit facility in the maximum amount of $100,000,000 which amount includes a $10,000,000 working capital component. Actual borrowings under the credit facility will be limited to a borrowing base as determined from time to time by our lenders.

         Under the credit facility PET will pay interest rates and commitment fees on undrawn amounts on terms negotiated and at rates agreed to between us and our lenders from time to time.

         We presently anticipate commencing distributions to Unitholders in the month of •. Prior to that time, cash flow from the Initial Assets and Additional Assets will be used to fund production and administrative expenses, interest, capital expenditures and to accumulate working capital for our ongoing operations, and, in the event that the Rights Offering is not fully subscribed, to acquire a further interest in the Additional Assets. Assuming distributions commence in January of 2003, such accumulation is estimated to be $25 million. See pro forma financial statements beginning on page F-25 for information on additional potential Rights Exercise scenarios.

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         Contractual Obligations and Commercial Commitments – Northeast Alberta Properties

         PET will, assuming acquisition of 100% of PRL’s interest in the Additional Assets, incur bank debt pursuant to its proposed credit facility of approximately $100,000,000 which would be reduced by an estimated $25,000,000 of net operating income from the Initial Assets and the Additional Assets from July 1, 2002 to the anticipated date of closing under the Take-Up Agreement. Amounts due under the proposed credit facility will be due on demand and consequently are shown as due in less than one year, however, assuming no such demand is made repayments of principal will not be required over the term of the proposed credit facility to the extent that our borrowing base as determined, from time to time, by the lenders exceeds actual borrowings under the credit facility. In addition, we have agreed to issue to PRL’s lenders a $20,000,000 guarantee and/or indemnity of PRL indebtedness to them, secured by a second charge over all of our assets. PRL’s lenders have agreed to release the $20,000,000 secured guarantee on the conditions that: all of the Rights held by or on behalf of POG, Treherne and 409790 are exercised; the $30,000,000 we will owe PRL pursuant to the acquisition of the Initial Assets is repaid in full; that we use the gross proceeds of the Rights Offering together with available bank financing to acquire the applicable interest in the Additional Assets; and PRL is not in default under its credit facilities with its lenders.

         The proposed credit facility is expected to contain restrictions and covenants usual and customary for transactions of this type, including, without limitation: (i) delivery of financial statements, engineering and other reports; (ii) delivery of compliance certificate; (iii) requirement to provide notices of default, material litigation and material governmental and environmental proceedings; (iv) compliance with laws and maintenance of permits; (v) payment of taxes; (vi) maintenance of insurance; (vii) prohibition on liens (subject to permitted encumbrances); (viii) prohibitions on mergers, consolidations; (ix) limitation on asset sales; (x) prohibition on incurrence of debt (subject to permitted indebtedness) /limitation on hedging exposure; (xi) prohibition on dividends, redemptions and other distributions during a default or borrowing base shortfall and at all other times not to exceed POT’s free cash flow, after considering ongoing capital expenditure requirements and reserves; provided that the foregoing will not preclude issuance of redemption notes by PET that have been subordinated and postponed in form satisfactory to the Lenders, (xii) limitations on investments and asset acquisitions, excluding asset acquisitions in the Western Canadian Sedimentary Basin; (xiii) no speculative trading; (xiv) no change in business; (xv) negative pledge; (xvi) perfection of security interests; (xvii) use of proceeds; and (xviii) prohibition on material amendments, waivers or consents to (A) our trust indentures or royalty agreement without the prior written consent of our lenders and (B) any other material contract which may have an adverse effect on the rights or remedies of the lenders.

Quantitative and Qualitative Disclosures About Market Risk

         No derivative financial instruments such as commodity futures contracts, price swaps, options, interest or foreign currency swap arrangements will be assumed by POT from PRL upon the acquisition of either the Initial Assets or the Additional Assets. We may use such derivative instruments for hedging purposes in the future to limit the risks of commodity price, foreign currency and/or interest rate fluctuations.

         We intend to limit the use of derivative financial instruments to hedging purposes and we do not intend to engage in speculative transactions for which there is no underlying offsetting position.

Governmental Regulation Risk

         We operate in a highly regulated industry and it is possible any changes in such regulation or adverse regulatory decisions could affect our production which could reduce our distributions. See “Risk Factors”.

Weather Risk

         The demand for natural gas is affected by temperature changes on the North American continent. Moderate temperatures reduce consumption of natural gas which could cause an oversupply of natural gas and a reduction in prices received for natural gas. Conversely, extreme temperatures could increase consumption of natural gas and increase prices.

54

Consequently, overall revenue can be higher or lower depending on weather conditions at any particular time of the year. Any fluctuation in the price of natural gas could affect our distributions.          While there are no significant seasonal limitations on gas production from the Northeast Alberta Properties, the Northeast Alberta Properties are located in winter access areas and consequently, capital and operating expenditures tend to be higher in winter months.

Foreign Exchange Risk

         Commodity prices for oil and natural gas are highly correlated to corresponding reference prices in United States markets. As a result, realized Canadian prices will be greatly affected by the exchange rate between Canadian and United States dollars. As we incur operating and administrative costs principally in Canadian dollars, increases in the Canadian dollar relative to the United States dollar would decrease our revenues without a corresponding decrease in costs.

Interest Rate Risk

         We will be exposed to interest rate risk on all of our outstanding bank debt. Increases in interest rates will increase interest expense correspondingly.

Sensitivities

         The following table summarizes the effects on forecast 2003 cash available for distributions of changes in natural gas production, prices, exchange rates and interest rates:

			Effect on Cash Available for Distributions
Variable			Change			(	$000's	)	($/Trust Unit)
Natural Gas Production (mmcf/d)				1.0		$	1,083			0.03
Natural Gas Price ($/mcf)	Cdn$			0.10		$	2,324			0.06
Canada – US Exchange (U.S.$/Cdn$)		U.S.$		0.01		$	1,970			0.02
Interest Rates (%)				1	%	$	800			0.05

Note:

(1) Assumes that 39,639,069 Trust Units will be outstanding following the exercise of 100% of the Rights and the acquisition of 100% of PRL’s interest in the Additional Assets.

Critical Accounting Assumptions

         As described in the notes to the financial statements of the PRL Northeast Alberta Properties, PRL follows the successful efforts method of accounting. PET will follow the full cost method of accounting for Canadian accounting purposes. Under U.S. generally accepted accounting principles PET will follow the successful efforts method of accounting as discussed in note 5(b) to the pro forma financial statements. Under full cost accounting all costs of acquiring petroleum and natural gas properties and related development costs are capitalized and accumulated in one cost center. PET places a limit on the aggregate cost of property, plant and equipment which may be carried forward for amortization against revenues of future periods (the “ceiling test”). The ceiling test is a cost recovery test whereby the capitalized costs less accumulated depletion and site restoration are limited to an amount equal to estimated undiscounted future net revenues from proved reserves less recurring general and administrative expenses, site restoration, management fees, future financing costs and income taxes. Costs and prices at the balance sheet dates are used. Any costs carried on the balance sheet in excess of the ceiling test limitation are charged to earnings. We estimate that the accounting carrying value of the Northeast Alberta Properties would exceed the ceiling test limitation at realized future natural gas prices below $3.00 per mcf.          Production from the Northeast Alberta Properties will deplete over time as outlined in the McDaniel Report. To the extent that production declines exceed those expected and to the extent that the Northeast Alberta Properties are not

55

replaced by the acquisition of additional assets, our cash flow will decline in the future. Each 1 mmcf/d change in production would impact our cash available for distributions by approximately $1.1 million.

         Operating costs and unit operating costs are a factor of, among other things, the cost and availability of labor and other oil and gas services, power prices, the general level of activity in the oil and gas industry and the individual performance of the wells in the Northeast Alberta Properties. The McDaniel Report projects operating costs of $0.76 per mcf. To the extent that the industry competition for labor and services rises, power prices increase or individual wells require a higher level of repairs and maintenance, operating costs could increase in the future.

USE OF PROCEEDS

         If the Rights Offering is fully subscribed, we will receive gross proceeds of $150,132,970. We will use the gross proceeds of the Rights Offering to repay the $30,000,000 (represented by a demand note bearing interest at a rate equal to the prime rate of a major Canadian chartered bank, from time to time, plus 1.875% from the date of issuance) we will owe to PRL arising from the acquisition of the Initial Assets and use the remaining $120,132,970 together with available bank financing to acquire up to 100% of PRL’s interest in the Additional Assets for a purchase price of $220,000,000. See “Formation of Trust Structure and Structuring Transactions — Trust Structuring”, page 33. We will use any proceeds of the Rights Offering remaining after the purchase of the Additional Assets for our working capital purposes. Since the revenues and expenditures associated with the Initial Assets and the Additional Assets will be adjusted as of July 1, 2002, net cash flow after July 1, 2002 from the Initial Assets and that interest in the Additional Assets that we acquire will belong to us. We will use net cash flow from July 1, 2002 until December 31, 2002 to cover operational expenses arising from ownership of our properties after July 1, 2002 and to pay the fees and costs of the Soliciting Dealer Group relating to the Rights Offering and our other costs and expenses relating to this prospectus and the Rights Offering estimated to be $1,000,000. We intend to pay our costs of the offering and the Soliciting Dealers Fees out of revenues accruing to POT from July 1, 2002. For accounting purposes, the costs of the offering will be accounted for under Canadian GAAP as the cost of selling the Trust Units and correspondingly recorded as a reduction to the credit to unitholders’ equity. We may also use a portion of such income to acquire a further interest in the Additional Assets to the extent that all of the Rights have not been exercised. In the event that not all of such income is used, we will use any balance for ongoing working capital requirements. We do not intend to distribute all or any portion of such income to Unitholders. Distributable income from our properties after December 31, 2002 will be used for distributions to Unitholders. In the event that we are unable, for whatever reason, to complete our purchase of any interest in the Additional Assets, we will not return the proceeds from the exercise of your Rights. In those circumstances we will utilize the criteria referred to under “Plan of Operations – Acquisition” in order to select and acquire other suitable assets. See “Descriptions of the Trust Units and Special Voting Rights – Distributions”, page 88 and “Bank Financing and Guarantees”, page 65.          The following tables detail PET’s available funds upon the closing of the Rights Offering, assuming 50% of the Rights are exercised, 75% of the Rights are exercised and 100% of the Rights are exercised.

					100% of
Sources of Funds	50% of Rights Exercised		75% of Rights Exercised		Rights Exercised
Proceeds of Rights Offering	$	75,066,485	$	112,599,727	$	150,132,970
Anticipated Bank Financing(1)		62,500,000		81,250,000		100,000,000
Anticipated Accumulated Revenues on Initial Assets and Additional Assets to December 31, 2002		25,076,035		34,405,273		37,383,002
TOTAL	$	162,642,520	$	228,255,000	$	287,515,972

56

Anticipated Use of Funds		50% of Rights Exercised			75% of Rights Exercised			100% of Rights Exercised
Repayment of debt owed to PRL from Initial Assets Purchase		$	30,000,000		$	30,000,000		$	30,000,000
Percentage of Additional Assets to be Acquired			53.73	%		82.45	%		100	%
Purchase Price of Relevant Percentage of Additional Assets			118,206,000			181,390,000			220,000,000
Interest on Purchase Price (6.5%), less Deposit			6,311,695			8,365,175			9,620,000
Expenses and Fees of Offering(2)			1,000,000			1,375,000			1,750,000
Repayment of Note owed to Summit Resources Limited(3)			2,073,000			2,073,000			2,073,000
Interest on Summit Note			51,825			51,825			51,825
Working Capital/Debt Reduction			5,000,000			5,000,000			24,021,147
	TOTAL	$	162,642,520		$	228,255,000		$	287,515,972

Notes:

(1)	While our lenders have provided estimated levels of anticipated bank financing, they will not determine our actual initial borrowing base under the proposed credit facility until the Rights Expiry Time, and one week prior to the Rights Expiry Time they will provide the initial borrowing base amounts which would result from the rights exercise percentages set forth above.
(2)	For the purposes of this line item expenses of the offering have been held constant at $1,000,000 and the variable component represents anticipated Soliciting Dealer Fees.
(3)	An interest bearing promissory note was issued from POT to Summit for the purchase of furniture, fixtures and computers as of July 1, 2002.

PET’S CONSOLIDATED CAPITALIZATION

         The following table shows PET’s consolidated capitalization as of June 30, 2002 both before and after giving effect to the Trust Structuring, the Dividend, the Rights Offering and the acquisition of the stated percentages of PRL’s interest in the Additional Assets:

Pro Forma as at June

Pro Forma as at June

Pro Forma as at June 30,

30, 2002 after giving

30, 2002 after giving

2002 after giving effect

effect to the Trust

effect to the Trust

to the Trust

Structuring, the

Structuring, the

Structuring, the

Pro Forma as at

Dividend, the exercise

Dividend, the exercise

Dividend, the exercise

June 30, 2002 after

of 50% of the Rights

of 75% of the Rights

of 100% of the Rights

giving effect to

Offering and the

Offering and the

Offering and the

the Trust

acquisition of

acquisition of

acquisition of the

Structuring and the

Additional Assets by

Additional Assets by

Additional Assets by

Authorized

As at June 30, 2002

Dividend

POT(4)

POT(4)(2)(3)(6)

POT(4)

Long-term Debt

—

Nil

$

30,000,000

(2)(3)

$

74,139,000

(2)(3)(6)(7)

$

99,790,000

(2)(3)(6)(7)

$

100,867,000

(2)(3)(6)(7)

Unitholders Equity

Unlimited

$

200

(1)

$

17,774,000

$

79,960,000

$

111,333,000

$

144,921,600

Trust Units

(1 Trust Unit)

(9,909,767 Trust Units)

(24,774,418 Trust Units)

(32,206,743 Trust Units)

(39,639,068 Trust Units)

Special Voting Units

Unlimited

Nil

Nil

Nil

Nil

Nil

Totals

$

200

$

47,774,000

$

154,099,000

$

211,123,000

$

245,788,000

Notes:

(1)	To facilitate PET’s creation we issued one Trust Unit to PRL. PRL will distribute this Trust Unit as part of the Dividend.
(2)	For a description of our proposed credit facility see “Bank Financing and Guarantees”, page 65.
(3)	The terms of the acquisition of the Initial Assets will require PET and POT to provide guarantees and related guarantee security to PRL’s lenders. This $30,000,000 is represented by a demand promissory note which bears interest at the prime rate of interest

57

	of a major Canadian chartered bank plus 1.875%. It is anticipated that if the Rights Offering is successful, this indebtedness will be outstanding for less than 60 days. See “Bank Financing and Guarantees”, page 65.
(4)	We have made adjustments for expenses associated with the preparation and filing of this prospectus and the Rights Offering and a reduction for the excess of the consideration paid over the predecessor book value of the Initial Assets and the Additional Assets. See Notes to the Pro Forma Consolidated Financial Statements.
(5)	We propose to issue incentive rights (the “Incentive Rights”) under a Unit Incentive Plan (the “Unit Incentive Plan”) to the directors and officers of the Administrator and employees of POT, upon PRL’s distribution of the Dividend. See “Unit Incentive Plan”, page 108.
(6)	Does not include net income accruing to POT from the production associated with the Initial Assets and the Additional Assets from July 1, 2002 until the anticipated closing of the transactions. See “Management’s Discussion and Analysis and Liquidity and Capital Resources – Liquidity and Capital Resources”, page 53.
(7)	While our lenders have provided estimated levels of anticipated bank financing, they will not determine our actual initial borrowing base under the proposed credit facility until the Rights Expiry Time, and one week prior to the Rights Expiry Time they will provide the initial borrowing base amounts which would result from the rights exercise percentages set forth above.

PRIOR ISSUANCE OF PET UNITS

         As at the date hereof, PET has one Trust Unit issued and outstanding, which we issued to PRL on June 28, 2002 in connection with the settlement and establishment of PET. PRL will distribute that Trust Unit as part of the Dividend.

INITIAL BUSINESS AND PROPERTIES OF POT

         Following the effectiveness of the registration statement of which this prospectus forms a part, the Trust Structuring will be completed, including our acquisition of 100% of PRL’s interest in the Initial Assets pursuant to the Sale Agreement. The Initial Assets consist of the Legend, Alberta property and related assets. See the fold-out map on the inside of the cover page to this prospectus. Pursuant to the Sale Agreement, we anticipate we will become the operator of the Initial Assets. The purchase price for the Initial Assets of $81,000,000 was calculated based on the present value, before income tax, of the expected future cash flows generated by the oil and natural gas properties included in the Initial Assets, discounted by 15% as derived from the escalating price reserve evaluation prepared by McDaniel effective July 1, 2002 with minor adjustments for undeveloped land and ancillary assets included in the Initial Assets.

         A description of the Initial Assets is set out below. The Initial Assets are properties comprised of Alberta provincial Crown leases that have been in existence for a number of years without any disputes as to ownership. As at July 31, 2002, 98% of the proved producing reserves (45.65 bcf) associated with the Initial Assets are on production.

         The Initial Assets consist entirely of natural gas producing properties and related transportation and processing facilities located in the northeast part of the Province of Alberta. Consequently, the operations related to the Initial Assets consist of one business segment in one geographic segment. There have been no significant changes in the operations related to the Initial Assets during the last three financial years.

         The demand for natural gas is affected by temperature changes on the North American continent. Moderate temperatures reduce consumption of natural gas which could cause an oversupply of natural gas and a reduction in prices received for natural gas. Conversely, extreme temperatures could increase consumption of natural gas and increase prices. Consequently, overall revenue can be higher or lower depending on weather conditions at any particular time of the year.

         While there are no significant seasonal limitations on gas production from the Initial Assets, the Initial Assets are located in winter access areas and consequently, capital and operating expenditures tend to be higher in winter months.

         Natural gas from the Initial Assets is produced and sold to third party purchasers under industry standard terms at or near the point of production.

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         The Initial Assets do not require additional raw materials for the production of natural gas.

         The production of natural gas from the Initial Assets is not dependent on significant patents, licenses or industrial, commercial or financial contracts.

         For a description of the effects of government regulation on the Initial Assets see “Government Regulations”, page 111.

Principal Property – Legend, Alberta

         The Legend Area is approximately 120 kilometres northwest of Fort McMurray. The area comprises 150,400 gross acres (132,668 net acres) including an average 82% working interest in 59 gross (48.38 net) producing natural gas wells in this area. The average daily production for the month of August 2002 based upon such working interest from the Legend Area was approximately 20.8 mmcf/d of natural gas (net). The McDaniel Report evaluated PRL’s proved reserves at 49.78 bcf (gross) of natural gas for the Legend Area. PRL has a 77.9% interest in and currently operates one gas plant and six field booster compressors that process the natural gas from this area, all of which interest is included in the Initial Assets.

         For development plans concerning the Legend Area see “Future Development”.

History – Daily Sales Volumes and Netbacks

         The following table sets forth the daily sales volumes and netbacks on a quarterly basis in respect of the Initial Assets for the quarters ended June 30, 2002 and March 31, 2002 and for the years ended December 31, 2001 and December 31, 2000.

		2002									2001									2001
		Quarter Ended									Quarter Ended									Total
		June 30			March 31			Dec 31			Sept 30			June 30			Mar 31
Daily Sales Volumes
	Natural Gas (mmcf/d)		22.0			15.5			17.3			18.8			19.0			14.2			17.3
Natural Gas Netbacks ($/mcf)
	Sales	$	3.77			2.80		$	3.70		$	2.69		$	4.14		$	8.49		$	4.51
	Royalties		(0.65	)		(0.37	)		(1.13	)		(1.38	)		(0.91	)		(2.46	)		(1.41	)
	Operating Costs(1)		(0.64	)		(1.25	)		(0.44	)		(0.71	)		(0.69	)		(1.18	)		(0.73	)
	Netback	$	2.48		$	1.18		$	2.13		$	0.60		$	2.54		$	4.85		$	2.37

					2000									2000
					Quarter Ended									Total
		Dec 31			Sept 30			June 30			Mar 31
Daily Sales Volumes Natural Gas (mmcf/d)			15.7			14.9			14.0			11.6			14.0
Natural Gas Netbacks ($/mcf)
	Sales	$	7.10		$	4.13		$	3.99		$	3.31		$	4.74
	Royalties		(1.77	)		(1.17	)		(0.97	)		(0.95	)		(1.24	)
	Operating Costs(1)		(0.46	)		(0.62	)		(0.81	)		(0.74	)		(0.65	)
	Netback	$	4.87		$	2.34		$	2.21		$	1.62		$	2.85

Note:

(1) Operating costs include amounts incurred to bring natural gas to the surface, gather store, field process, treat and store same, including principally labor, processing, utilities, supplies, repairs and maintenance, taxes, lease rentals and overhead.

Capital Expenditures

         The following table shows capital expenditures made by PRL on the Initial Assets in the categories and for the periods indicated:

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	2002				2001
													2001
($000)	Quarter Ended				Quarter Ended								Total
Category of Expenditure	June 30		March 31		Dec 31		Sept 30		June 30		Mar 31
Land and Acquisition	$	—	$	—	$	—	$	—	$	—	$	185	$	185
Drilling & Exploration		—		3,278		159		35		1,750		641		2,585
Equipping		—		65		35		1		63		1		100
Facilities & Gathering		775		3,149		1,884		1,315		5,801		790		9,790
Total	$	775	$	6,492	$	2,078	$	1,351	$	7,614	$	1,617	$	12,660

	2000
										2000
	Quarter Ended									Total
Category of Expenditure	Dec 31			Sept 30		June 30		Mar 31
Land and Acquisition	$	1,574		$	—	$	—	$	—	$	1,574
Drilling & Exploration		230			883		544		839		2,496
Equipping		25			7		29		37		98
Facilities & Gathering		(968	)		1,065		2,941		3,353		6,391
Total	$	861		$	1,955	$	3,514	$	4,229	$	10,559

Note:

(1)	Reference should be made to note 11 under the heading “Initial Business and Properties of POT — Natural Gas Reserves-Initial Assets”, page 62 below for McDaniel’s estimates on required capital expenditures for 2002.
(2)	Amounts determined under successful efforts method of accounting as applied by PRL. See note (2) to the historical financial statements for the Northeast Alberta Properties.

Future Commitments

         We have no material future contracts to buy, sell or transport natural gas from the Initial Assets.

Land Holdings

         The following table sets out the developed and undeveloped land holdings in the area comprising the Initial Assets as at July 1, 2002.

	Land Holdings
	Developed Acres				Undeveloped Acres(3)
									Undeveloped Acres
Name of Area	Gross(1)		Net(2)		Gross(1)		Net(2)		Market Value(4)
Legend, Alberta		104,960		87,766		45,440		44,902	$	450,112

Notes:

(1)	“Gross” refers to the total number of developed and undeveloped acres, respectively, in which a working interest is included in the Initial Assets.
(2)	“Net” refers to the aggregate of the numbers obtained by multiplying each gross acre by the actual percentage working interest therein comprised in the Initial Assets.
(3)	During 2002, 26,880 net acres are set to expire and 1,280 are set to expire in 2003. We intend to assess such expiring lands and, where appropriate, to seek continuation through development activity or, in the case of higher risk areas, farmouts, where third parties provide exploration funding in exchange for an earned working interest.
(4)	Market value has been taken from the McDaniel Report “Update on Unproven Acreage Interests as of July 1, 2002” based upon McDaniel’s individual price per acre estimates as of January 1, 2002.

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Natural Gas Wells

         The following table shows the number of natural gas wells producing or capable of producing in the Initial Assets as at July 1, 2002.

	Natural Gas Wells
	Producing				Non-Producing(3)(4)
Name of Area	Gross(1)		Net(2)		Gross(1)		Net(2)
Legend, Alberta		59		48.4		5		4.5

Notes:

(1)	“Gross” refers to the number of producing and non-producing wells, respectively, in which a working interest or royalty interest is included in the Initial Assets.
(2)	“Net” refers to the aggregate of the numbers obtained by multiplying each gross well by the percentage working interest therein comprised in the Initial Assets.
(3)	“Non-Producing” refers to wells which are not currently producing either due to lack of facilities and/or marketing but are capable of producing in commercial quantities.
(4)	Additionally, there is included in the Initial Assets 15 (11.9 net) wells which are not capable of producing in commercial quantities at this time. Allowance for the abandonment costs associated with the wellbores was made in the McDaniel Report. One well that is classified as a service well is included in the gross/net well count.

Drilling Activity

         PRL drilled, or participated in drilling, exploratory and development wells comprised in the Initial Assets for the periods indicated as shown in the following table. The “Natural Gas” wells listed below comprise all natural gas wells capable of production, whether producing or capped, in which an interest is included in the Initial Assets.

	Quarter Ended				Quarter Ended				Year Ended				Year Ended				Year Ended
	June 30, 2002				March 31, 2002				December 31, 2001				December 31, 2000				December 31, 1999
Natural Gas Wells	Gross(1)		Net(2)		Gross(1)		Net(2)		Gross(1)		Net(2)		Gross(1)		Net(2)		Gross(1)		Net(2)
Natural Gas		—		—		11		9.2		8		7.3		4		3.5		2		2.0
Service		—		—		—		—		—		—		—		—		—		—
Dry and Abandoned		—		—		—		—		—		—		—		—		—		—
Total		—		—		11		9.2		8		7.3		4		3.5		2		2.0
Success Rate (%)						100		100		100		100		100		100		100		100
Exploratory(3)		—		—		—		—		1		1.0		—		—		—		—
Development(4)		—		—		11		9.2		7		6.3		4		3.5		2		2.0
Total		—		—		11		9.2		8		7.3		4		3.5		2		2.0

Notes:

(1)	“Gross” refers to all wells in which a working interest or a royalty interest is included in the Initial Assets.
(2)	“Net” refers to the aggregate of the percentage working interests in the gross wells, before the deduction of royalties, comprised in the Initial Assets.
(3)	“Exploratory” well, in general, is a well either drilled in search of a new and yet undiscovered pool of oil or natural gas, or with the expectation of significantly extending the limits of a pool which is partly delineated.
(4)	“Development” well, in general, is a well drilled within or in close proximity to a discovered pool of oil or natural gas.

Production History

         The following table shows the average daily net production from the Initial Assets for the periods indicated, before deduction of royalties payable to others.

61

	Quarter Ended		Quarter Ended		Year Ended		Year Ended		Year Ended
Type of Production	June 30, 2002		March 31, 2002		December 31, 2001		December 31, 2000		December 31, 1999
Natural Gas (mmcf/d)		22.0		15.5		17.3		14.0		14.0

Natural Gas Reserves — Initial Assets

         The McDaniel Report evaluates the proved natural gas reserves attributable to the properties comprising the Initial Assets using a constant price of $2.87 per Mmbtu as provided by PRL, being the price received from sales of natural gas by PRL on June 28, 2002, based upon Remaining Reserves (as defined below) as at July 1, 2002. These reserves are all located in Canada. For the purposes of this prospectus we are utilizing only the proved reserves.

         In preparing its report, McDaniel used basic historical information it had from PRL for its January 1, 2002 evaluation of PRL, which included land data, well information, geological information, reservoir studies, estimates of on-stream dates, contract information, hydrocarbon product prices, operating cost data, financial data and future operating plans. McDaniel obtained other engineering, geological or economic data required to conduct the evaluation and upon which the McDaniel Report is based, from public records, other operators and from McDaniel’s non-confidential files. McDaniel accepted as represented from all sources the extent and character of ownership and the accuracy of all factual data supplied for the independent evaluation.

         The price utilized for the constant price assumptions in the McDaniel Report was Cdn $2.87 per Mmbtu for natural gas.

         Based on the McDaniel Report, the following tables show the estimated share in respect of the natural gas reserves included in the Initial Assets and the discounted present value of estimated future net revenues for these reserves using constant prices and costs. All evaluations of the present value of estimated future net revenue in the McDaniel Report are after provision for estimated future capital expenditures and operating costs. An allowance for future wellbore abandonment costs was made for all wells in which there is a working interest; however no allowance was made for the abandonment of any surface, wellsites and facilities, for income tax or for ARTC. These evaluations do not necessarily represent the fair market value of the reserves.

Natural Gas Reserves and Present Value of Estimated Future Cash flows
(Based on Constant Price Assumptions)

					Present Value Cash
	Remaining Reserves				Flow Discounted at
Reserves Categories	of Natural Gas(1)(2)				10% (Net)
	Gross(3)		Net(4)
	mmcf		mmcf		(M$)
Proved Developed Producing(7)		46,647		36,577		44,875
Proved Undeveloped(8)		3,135		2,249		3,198
Total Proved(6)		49,782		38,826		48,073

Notes:

(1)	“Natural Gas” means the lighter hydrocarbons and associated non-hydrocarbon substances occurring naturally in an underground reservoir, which under atmospheric conditions is essentially a gas, but which may contain liquids. The natural gas reserve estimates are reported on a marketable basis, that is the gas which is available to a transmission line after removal of certain hydrocarbons and non-hydrocarbon compounds present in the raw natural gas and which meets specifications for use as a domestic, commercial or industrial fuel.
(2)	“Remaining Reserves” means those quantities of crude oil, natural gas, natural gas liquids and sulphur remaining after deducting those quantities produced up to the reference date of the study.
(3)	“Gross Reserves” are the total of the working interests and/or royalty interests share of reserves before deducting royalties owned by others.

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(4)	“Net Reserves” are the total of the working interests and/or royalty interests share of reserves after deducting the amount attributable to the royalties owned by others.
(5)	The term “royalties”, as used in the McDaniel Report, refers to royalties paid to others. The royalties deducted from the reserves are based on the royalty percentage calculated by applying the applicable Royalty Rate or formula. In the case of Crown sliding scale royalties which are dependent on selling price, the price forecasts for the individual properties in question has been employed.
(6)	“Proved” Reserves are the estimated quantities of crude oil, natural gas, and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions, i.e. prices and costs as of the date the estimate is made. Prices include consideration of changes in existing prices provided only by contractual arrangements, but not on escalations based upon future conditions.
(7)	“Proved Developed” Reserves are reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. Additional oil and gas expected to be obtained through the application of fluid injection or other improved recovery techniques for supplementing the natural forces and mechanisms of primary recovery should be included as “proved developed” reserves only after testing by a pilot project or after the operation of an installed program has confirmed through production response that increased recovery will be achieved.
(8)	“Proved Undeveloped” Reserves are reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. Reserves on undrilled acreage shall be limited to those drilling units offsetting productive units that are reasonably certain of production when drilled. Proved reserves for other undrilled units can be claimed only where it can be demonstrated with certainty that there is continuity of production from the existing productive formation. Under no circumstances should estimates for proved undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual tests in the area and in the same reservoir.
(9)	Sales Gas includes pipeline and solution gas reserves.
(10)	Product prices used in the constant price evaluations are based on McDaniel’s July 1, 2002 price forecast, Cdn $2.87 per Mmbtu for natural gas. The constant price assumptions assume the continuance of current laws, regulations and operating costs in effect on the effective date of the McDaniel Report.
(11)	The McDaniel Report estimates total net proven capital investment necessary to achieve the estimated future net cash flow to be $1,633,000, of which nil is to be spent in 2002 based on constant cost assumptions, in respect of the Initial Assets.

Historical Reserves

         The following table sets out the proved natural gas reserves at December 31, 2001, 2000, 1999 and 1998 (before deducting amounts attributable to royalties owned by others) to the Initial Assets and based upon constant price and cost assumptions. All of these reserves were located in Canada:

		Proved Natural Gas Reserves (bcf)
December 31, 1998			71.4
	Revisions to previous estimates		(12.7	)
	Purchase (sale of reserves)		—
	Discoveries and extensions		—
	Production		(5.1	)
December 31, 1999			53.6
	Revisions to previous estimates		3.5
	Purchase (sale of reserves)		—
	Discoveries and extensions		—
	Production		(5.1	)

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		Proved Natural Gas Reserves (bcf)
December 31, 2000			52.0
	Revisions to previous estimates		3.9
	Purchase (sale of reserves)		—
	Discoveries and extensions		—
	Production		(6.3	)
December 31, 2001			49.6

DETAILS OF THE DIVIDEND

         It is proposed that PRL’s board of directors will set the Dividend Record Date as 4:30 p.m., Calgary time, on •, 2002. The Dividend will be paid by the distribution of 9,909,767 Trust Units to the PRL Shareholders of record on the Dividend Record Date. There are currently 59,458,600 PRL Common Shares outstanding, which would entitle PRL Shareholders to receive one Dividend Unit for every 6 PRL Common Shares held by them. We anticipate there will be up to 784,000 vested stock options of PRL outstanding at the Dividend Record Date entitling holders thereof to acquire up to an additional 784,000 PRL Common Shares. If any or all of those options are exercised on or prior to the Dividend Record Date, the number of PRL Common Shares necessary to receive one Dividend Unit will increase from 6 to a maximum of 6.079 PRL Common Shares. We and PRL propose to issue a press release on the Dividend Record Date giving notice of what this ratio will be. Except as otherwise indicated in this prospectus we have assumed one Dividend Unit will be issued for each 6 PRL Common Shares. After PRL’s distribution of the Dividend Units it will not own any Trust Units. Neither PRL nor PET will receive any proceeds as a result of the payment of the Dividend. See “Details of the Rights Offering — Registration and Delivery of Certificates Evidencing Securities”, page 70.

         PRL will not distribute any fractional Trust Units in the Dividend. The number of Trust Units distributed to each PRL Shareholder will be rounded down to the next lowest whole number of Trust Units. PRL will return to us, for cancellation without payment or compensation, any Trust Units it does not distribute to the PRL Shareholders by reason of rounding.

Withholding of Tax

         PRL has advised us that each of PRL, any person who pays or credits the Dividend on behalf of PRL and any person to whom the Dividend is paid or credited on behalf of the owner of such PRL Common Shares is required, in respect of the portion of the Dividend that is payable to Non-Resident Shareholders, to withhold and remit taxes in an amount equal to 25% of the fair market value of the Dividend Units, subject to reduction under an applicable tax treaty (for example, under the tax treaty with the United States such withholding is generally reduced to 15%). See “Certain Canadian Federal Income Tax Considerations”, page 113.

         PRL has advised us that for purposes of calculating the amount of tax to be withheld, PRL will determine the fair market value of the Dividend Units on the date the Dividend is paid. PRL’s determination of the fair market value of the Dividend Units is not binding on the CCRA.

         PRL has advised us that tax withholding for Non-Resident Shareholders will occur in the following manner:

(a) for each Non-Resident Shareholder who has registered his or her share ownership directly with PRL, Computershare Trust Company of Canada (“Computershare”) will withhold all of the Dividend Units to which such Non-Resident Shareholder is entitled and will sell, as soon as reasonably possible after obtaining PRL’s determination as to the fair market value of the Dividend Units, a sufficient number of such Non-Resident Shareholder’s Dividend Units on the TSX to obtain net proceeds of such sale sufficient to pay withholding tax payable on behalf of such Non-Resident Shareholder (for example, for

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shareholders who have provided a United States address to PRL, Dividend Units will be sold until the proceeds of such sale are sufficient to pay 15% of the fair market value of the Dividend Units to the CCRA as withholding tax). Computershare will remit withholding tax to the CCRA on behalf of the Non-Resident Shareholder and will forward any proceeds of sale in excess of the amount to be remitted, to the Non-Resident Shareholder, together with the unsold balance of such Non-Resident Shareholder’s Dividend Units, as soon as such sale can be completed. Computershare will attempt to sell Dividend Units on behalf of Non-Resident Shareholders at the earliest possible opportunity after the Dividend is paid and PRL’s determination as to the fair market value is obtained, but it is highly unlikely that such sale will be completed on the date the Dividend is paid. Computershare will sell each such Dividend Unit at the prices it determines in its sole discretion. Computershare’s ability to sell such Dividend Units, and the prices it obtains for such Dividend Units, are dependent upon market conditions. Non-Resident Shareholders will not be entitled to receive Rights for any Dividend Units which have been sold for withholding tax purposes at any time prior to 2 days before the Rights Record Date. None of PRL, PET or Computershare will be liable to any Non-Resident Shareholder for failure to sell any Dividend Units at any particular price or prices, or within any particular time period; or

(b)

for Non-Resident Shareholders whose shares are held through the book-based systems administered by The Canadian Depository for Securities Limited or the Depository Trust Company, withholding and remittance of withholding tax will be made by their stockbroker or by the Depository Trust Company, as the case may be, and such Non-Resident Shareholders should contact their stockbroker to determine how arrangements to satisfy withholding tax obligations in respect of the Dividend will be administered and how this will affect the number of Trust Units that will ultimately be delivered to them and the timing of such delivery pursuant to the Dividend. In such case, none of PRL, PET and Computershare will withhold or remit tax or be responsible for doing so, or be liable to any such Non-Resident Shareholder for failure of any stockbroker, Depository Trust Company or The Canadian Depository for Securities Limited to sell any Dividend Units at any particular price or prices or within any particular time period.

         See “Certain United States Federal Income Tax Considerations”, page 116.

BANK FINANCING AND GUARANTEES

         Our lenders have agreed to finance us pursuant to the terms and conditions of a commitment letter dated August 15, 2002. Under the terms of the commitment letter our lenders have agreed to provide a demand loan revolving credit facility to us of up to $100,000,000, which amount includes a $10,000,000 working capital component. This $100,000,000 maximum loan amount is based on all Rights being exercised and our lenders have indicated that such amount may be reduced if less than all of the Rights are exercised. The exact amount of such credit facility will be determined based upon our lenders’ determination of our borrowing base value of our oil and gas properties at the Rights Expiry Time. Our lenders have agreed to notify us as to the initial borrowing base amounts expected to result from various levels of exercise of Rights no later than one week prior to the Rights Expiry Time. Our lenders will determine the borrowing base of our oil and natural gas properties, or the maximum size of the credit facility they are prepared to make available to us, from time to time, through a subjective assessment and analysis of the reserves of our oil and natural gas properties applying the assumptions, pricing models, risk factors and other relevant information or factors in accordance with the loan parameters of our lenders in effect from time to time in respect of similar borrowers similarly situated. The provision of funds by our lenders to us is conditional, among other things, upon the execution of industry standard documentation, customary conditions for a financing of this type and a satisfactory due diligence review. In addition, funding is conditional upon the exercise of all Rights under the Rights Exercise Agreement and the concurrent closing of the Take-Up Agreement and repayment of the $30,000,000 we will owe to PRL.

         Our lenders’ commitment to provide funding will terminate on November 29, 2002 or such later date as the parties may agree, if funding has not occurred by then.

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         All indebtedness provided to us by our lenders will be payable by us on demand by our lenders. If not demanded earlier, all indebtedness will be repayable by us on May 31, 2003 unless we are able to negotiate a renewal. We operate in an industry where lenders provide financing to certain oil and gas borrowers on a demand basis, subject to renewal based on an annual or more frequent review of the financial affairs and performance of the oil and gas borrower. We believe our lenders will continue to extend their demand loan revolving credit facilities to us at the time of this review, or in the alternative we will seek to replace our credit facilities with other lenders.

         Under the terms of this facility, if our lenders determine that our borrowing base has been exceeded by the amount loaned to us, and assuming there is not a demand for repayment resulting therefrom, we will be precluded from providing distributions on the Trust Units and from paying cash for redemptions of Trust Units, until our borrowing base no longer is in a shortfall position. Our lenders may also restrict our ability to pay distributions when we are in breach or default of our agreements with them.

         We will provide security to our lenders for the credit facility including various first fixed and floating charge debentures over all our assets, a secured guarantee provided by POT and various priority agreements and subordination and postponement arrangements in favor of our lenders. We will pay commitment fees for the undrawn portion of our credit facility and interest on drawn portions of our credit facility at rates agreed to by our lenders and us from time to time.

         Once the acquisition of the Initial Assets has been completed, we will owe PRL $30,000,000, secured by first fixed charges over our assets. PRL is required to assign this debt and the security to its lenders. PRL’s lenders have also requested a $20,000,000 guarantee and/or indemnity from us of PRL’s indebtedness to them, secured by a second charge over our assets. Pursuant to the Rights Exercise Agreement, it is a condition of PRL’s lenders that POG, Treherne and 409790 exercise all Rights held by or on behalf of them thereby subscribing for all Trust Units available to them under the Initial Subscription Privilege. POG and its subsidiaries are required to provide evidence to PRL’s lenders of their financial ability to subscribe for all of such Trust Units. Under the terms of the Rights Exercise Agreement, POG, Treherne and 409790 represent that they have in place available bank financing which, when combined with an amount of $33,000,000 owing by PRL to POG and other funds available to POG, Treherne and 409790, will be sufficient to allow these parties to acquire all of the Trust Units that will be available to them under the Initial Subscription Privilege for the Rights that they will receive. The funding of amounts under their credit arrangements are conditional upon a number of things, including the provision by POG, Treherne and 409790 to their lenders of sufficient collateral. In the event that POG, Treherne and 409790 are unable to draw down the required amounts under these facilities, or PRL is not in a position to pay to POG the full amount that PRL owes to POG, POG, Treherne and 409790 may not be able to exercise all of their Rights. Assuming all of the Rights are exercised and our lenders advance our requested loan of $100,000,000 under our proposed credit facility, there will be sufficient funds available to repay the $30,000,000 we will owe to PRL arising from our acquisition of Initial Assets and to acquire 100% of PRL’s interest in the Additional Assets. If less than all of the Rights are exercised, we will use the net proceeds of the Rights Offering, to repay the $30,000,000 we will owe to PRL arising from our acquisition of the Initial Assets, with the remainder of such proceeds together with the amount our lenders are willing to advance under our proposed credit facility, used to acquire as much interest as we are able in the Additional Assets. PRL’s lenders have agreed to release the $20,000,000 secured guarantee on the condition that all of the Rights held by or on behalf of POG, Treherne and 409790 are exercised, the $30,000,000 we will owe to PRL is repaid in full, that we use the gross proceeds of the Rights Offering together with available bank financing to acquire the applicable interest in the Additional Assets and PRL is not in default under its credit facilities with its lenders. See “Details of the Rights Offering — Intentions of Insiders and Others to Exercise Rights”, page 69.

DETAILS OF THE RIGHTS OFFERING

         The board of directors of the Administrator has determined the Rights Exercise Price based on the net asset value of PRL’s interest in the Additional Assets, being the assets that will be acquired by PET with the proceeds of the Rights Offering. The net asset value of the Additional Assets was calculated by relying on McDaniel’s escalating price evaluation under the McDaniel Report (which is not included herein) of the before tax, discounted present value of estimated future cash flows from the natural gas proved plus risked probable additional reserves included in the

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Additional Assets, net of the debt anticipated to be available and to be incurred to finance the acquisition of the Additional Assets. Certain additional value was ascribed to the undeveloped lands and ancillary assets included in the Additional Assets. The Trust Units may trade at prices which are influenced by factors other than the net asset value of the Trust Units, including, but not limited to, the anticipated distributions on the Trust Units.

Issue of Rights and Rights Certificates

         After payment of the Dividend, PET will issue and distribute three Rights for each Trust Unit held by a Unitholder of record as at 4:30 p.m., Calgary time, •, 2002 (being the Rights Record Date) who is not an Ineligible Person (as that term is defined in “Details of the Rights Offering — Ineligible Persons”). Each Right will entitle the holder to subscribe for one Trust Unit under the Initial Subscription Privilege, at the Rights Exercise Price on or before the Rights Expiry Time.

         We will issue the Rights in registered form evidenced by fully transferable certificates (the “Rights Certificates”). We will mail to each holder of record of Trust Units on the Rights Record Date who has an address of record in Canada or the United States and who is not an Ineligible Person:

(a)	a copy of this prospectus or the Canadian Prospectus, as appropriate; and
(b)	a Rights Certificate evidencing the total number of Rights to which the holder is entitled.

         We will register certificates representing Trust Units purchased on the exercise of the Rights (the “Unit Certificates”) in the name of the registered holder of the Rights Certificate who is not an Ineligible Person, or as otherwise directed, and we will send such certificates to that person at the address specified on the Rights Certificate. Holding Rights will not, as such, give you any of the rights or privileges of a Unitholder.

Additional Subscription Privilege

         If you exercise all the Rights you receive on the Initial Subscription Privilege you may subscribe for additional Trust Units, if available, at the Rights Exercise Price. If all Rights available under the Rights Offering are exercised under the Initial Subscription Privilege, then the Additional Subscription Privilege will not be available. See “How to Exercise the Rights - To Subscribe for Additional Units — Form 2”, page 72 and “How to Exercise the Rights — To Sell or Transfer Rights — Form 3”, page 72. PET will allot additional Trust Units from those Trust Units not issued pursuant to the Initial Subscription Privilege. You will be entitled to your share of additional Trust Units calculated on the basis of the number of Rights you exercised pursuant to the Initial Subscription Privilege as a percentage of the total number of Rights exercised pursuant to the Initial Subscription Privilege by all Rightsholders who subscribed for additional Trust Units.

         You may subscribe for additional Trust Units by:

(a)

completing Form 2 on the Rights Certificate entitled “To Subscribe for Units” and, if applicable, Form 3, “To Sell or Transfer Rights”; and

(b)

delivering the Rights Certificate, together with payment for those additional Trust Units, to the offices of Computershare Trust Company of Canada as subscription agent for the Rights Offering (the “Subscription Agent”) located at 100 University Avenue, 9th Floor, Toronto, Ontario, M5J 2Y1 (the “Subscription Office”) at or before the Rights Expiry Time. You must enclose payment for additional Trust Units subscribed for or your over-subscription for such additional Trust Units will be invalid.

         If the Initial Subscription Privilege is fully subscribed, the Subscription Agent will return to you, by check in Canadian funds, without interest, the payment you included for the over-subscriptions. If the Initial Subscription Privilege is not fully subscribed, the Subscription Agent will deliver to you Unit Certificates for the Trust Units for which you validly subscribed under both your Initial Subscription Privilege and your Additional Subscription Privilege. In addition,

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the Subscription Agent will return to you, without interest, the amount you paid in respect of any over-subscription under the Additional Subscription Privilege for which there were no Trust Units available. You will not receive any interest on excess monies either as a result of an over-subscription or as a result of an overpayment by you. See “Details of the Rights Offering - Intentions of Insiders and Others to Exercise Rights”, page 69.

Ineligible Persons

         We have not qualified the Rights or Trust Units for distribution or registered them under the securities laws of any jurisdictions other than Canada and the United States, excluding the State of Florida. The Rights are not being offered for sale in any other jurisdiction and may not be exercised by any person who is not or appears to us or the Subscription Agent not to be, or who we or the Subscription Agent have reason to believe is not, a resident of Canada or the United States, excluding residents of the State of Florida (an “Ineligible Person”). We will only deliver Rights Certificates to registered Unitholders as of the Rights Record Date whose addresses of record are in Canada or the United States.

         Following a sale or transfer of Rights, we will not register any Rights Certificate in the name of any person who is or appears to us to be an Ineligible Person. We will not accept subscriptions for Trust Units from or on behalf of any Ineligible Persons.

         We will send Unitholders believed to be Ineligible Persons a letter advising them that we will issue their Rights Certificates to the Subscription Agent, who will hold the Rights as their agent. The Subscription Agent will hold such Rights for a period of 15 days from the Rights Record Date to give beneficial owners of such Rights who are residents of Canada or the United States, excluding residents of the State of Florida, an opportunity to claim their Rights Certificates. At the end of the 15 day period, the Subscription Agent will attempt to sell the Rights so held and not claimed on a best-efforts basis, through the facilities of any exchange on which the Rights are listed for trading. The Subscription Agent will sell each Right at the times and prices it determines in its sole discretion. The Subscription Agent’s ability to sell Rights, and the prices it obtains for the Rights, are dependent on market conditions. Neither PET nor the Subscription Agent will be subject to any liability for failure of the Subscription Agent to sell any Rights of Ineligible Persons at any particular price or prices, or at all. Ineligible Persons will receive their share of the proceeds from the sale of such Rights, less applicable costs and expenses according to the total number of Trust Units they held on the Rights Record Date. The Subscription Agent will mail checks to Ineligible Persons at their addresses appearing in the records of the Subscription Agent for their share of the proceeds, less any applicable taxes.

         If you are a resident of Canada or the United States, excluding residents of the State of Florida, and own Trust Units registered in the name of a resident of a jurisdiction other than Canada or the United States, excluding residents of the State of Florida, and believe that we may have delivered your Rights Certificates to the Subscription Agent, then you should contact the Subscription Agent on or prior to the close of business on •, 2002 to have your Rights Certificates mailed to you.

Dealer Managers

         Please see “Plan of Distribution”, on page 85, for a discussion of the Dealer Managers and of the solicitation fees payable under the Rights Offering.

Delivery of Rights by Intermediaries

         Brokers, dealers or other intermediaries may not deliver Rights to beneficial owners of Trust Units who are Ineligible Persons. Intermediaries should attempt to sell those Rights for the accounts of those Ineligible Persons and should deliver any proceeds of sale less any applicable withholding tax to them.

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Fees Payable by Subscribers

         You will be responsible for paying any service charge, commission or other fee your broker charges in connection with the trading of Rights. We will not charge any commission upon the issuance of Rights to Unitholders or upon the exercise of Rights.

Expiry of Rights

         IF YOU HAVE RIGHTS AND DO NOT EXERCISE THEM AT OR BEFORE THE RIGHTS EXPIRY TIME, THE RIGHTS WILL BE VOID AND WILL HAVE NO VALUE.

Intentions of Insiders and Others to Exercise Rights

         We have been advised by certain of the directors and officers of PRL, holding or exercising control or direction over 29,597,581 PRL Common Shares which will entitle them to receive 4,932,763 Dividend Units, that their present intention is to exercise or cause to be exercised the 14,798,289 Rights to which they are entitled. We have also been advised by certain directors of PRL holding or exercising control or direction over 2,418,227 PRL Common Shares which will entitle them to receive 403,037 Dividend Units that they are currently undecided in respect of the exercise of the 1,209,111 Rights to which they are entitled. As at July 31, 2002, directors and senior officers of PRL, including companies they control, collectively owned or exercised control and direction over 32,023,796 PRL Common Shares (53.86% of the issued and outstanding PRL Common Shares) which will result in them holding 5,337,299 Trust Units on the Dividend. None of these individuals or entities owns or has control and direction over greater than 10% of the PRL Common Shares except C.H. Riddell, the Chairman and Chief Executive Officer of the Administrator, who directly and indirectly through POG, exercises control and direction over 28,943,770 PRL Common Shares (48.68% of the issued and outstanding PRL Common Shares). Mr. Riddell’s daughter, S.L. Riddell Rose, the President, Chief Operating Officer and a director of the Administrator, is also a shareholder of POG. The C.H. Riddell Family beneficially own or exercise control and direction over, directly or indirectly, including through POG, an aggregate of 29,590,727 PRL Common Shares. Upon payment of the Dividend, but prior to the exercise of any Rights, the C.H. Riddell Family will beneficially own or exercise control and direction over, directly or indirectly, including through POG, 4,931,787 Trust Units (49.77% of the issued and outstanding Trust Units). Under the Rights Offering, the C.H. Riddell Family will receive and will beneficially own or exercise control and direction over, directly and indirectly, including through POG, 14,795,361 Rights.

         PRL, C.H. Riddell, POG, Treherne and 409790 have entered into the Rights Exercise Agreement with PRL’s lenders which obligates POG, Treherne and 409790 to exercise all Rights (48.53% of the Rights issued) held by or on behalf of them thereby subscribing for Trust Units. POG and its subsidiaries are required to provide evidence to PRL’s lenders of their financial ability to subscribe for 14,428,383 Trust Units on the exercise of their Rights. Under the terms of the Rights Exercise Agreement, POG, Treherne and 409790 represent that they have in place available bank financing which, when combined with an amount of $33,000,000 owing by PRL to POG and other funds available to POG, Treherne and 409790, will be sufficient to allow these parties to acquire all of the Trust Units that will be available to them under the Initial Subscription Privilege for the Rights that they will receive. The funding of amounts under their credit arrangements are conditional upon a number of things, including the provision by POG, Treherne and 409790 to their lenders of sufficient collateral. In the event that POG, Treherne and 409790 are unable to draw down the required amounts under these facilities, or PRL is not in a position to pay to POG the full amount that PRL owes to POG, POG, Treherne and 409790 may not be able to exercise all of their Rights. PRL’s lenders have agreed to release the $20,000,000 guarantee from us to them in favor of PRL, provided that all of the Rights held by or on behalf of POG, Treherne and 409790 are exercised, the proceeds of the Rights Offering together with available bank financing are used to repay the $30,000,000 we will owe to PRL and to acquire the applicable interest in the Additional Assets and PRL is not in default under its credit facility with its lenders. The C.H. Riddell Family and certain other insiders described above (including directors and officers of PRL and certain directors of the Administrator) holding or exercising control or direction over an aggregate of 29,618,531 PRL Common Shares have indicated their intention to exercise or cause to be exercised the 14,809,263 Rights to which they are entitled under the Initial Subscription Privilege, which will result in

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them holding or exercising control or direction over 19,745,684 Trust Units. Additionally, such persons may acquire additional Trust Units through the exercise of their Additional Subscription Privilege. To the extent that other Rightsholders do not exercise their Rights, the C.H. Riddell Family and these other insiders will increase their percentage of ownership of PET.

         After the payment of the Dividend, the directors and officers of the Administrator, as a group, will beneficially own, directly or indirectly, or exercise control or direction over, including through POG, an aggregate 4,840,859 Trust Units representing 48.85% of the then outstanding Trust Units. The directors and officers will also receive Rights pursuant to the Rights Offering and they have advised that it is their intention to acquire all Trust Units available to them under the Initial Subscription Privilege.

         As at October 16, 2002, Fidelity beneficially owns 5,352,000 PRL Common Shares (representing approximately 9.0% of the issued and outstanding PRL Common Shares) in accounts and funds managed by it. Fidelity will, upon payment of the Dividend, hold 892,000 Trust Units. If Fidelity holds such Trust Units on the Rights Record Date they will receive 2,676,000 Rights. We have not been advised of Fidelity’s intention respecting its exercise of Rights.

Decrease in Percentage Ownership

         To the extent that any Rights are exercised, holders of Dividend Units who do not exercise their Rights will suffer a decrease in their percentage ownership of PET. See “Details of the Rights Offering — Intentions of Insiders and Others to Exercise Rights”, page 69.

Registration and Delivery of Certificates Evidencing Securities

         The Subscription Agent will register Trust Units purchased through the Initial Subscription Privilege and the Additional Subscription Privilege in the name of such subscriber unless the subscriber otherwise instructs. The Subscription Agent will mail certificates representing Trust Units as soon as practicable after the Rights Expiry Time to the subscriber at the address appearing on the Rights Certificate. As soon as practicable after the Rights Expiry Time we will issue a press release with the results of the Rights Offering. A copy of such press release will be available under PET’s profile at www.sedar.com.

         The Subscription Agent will be fully discharged from all responsibility as agent with regard to the monies it receives when it has:

(a)	forwarded Unit Certificates to the subscribers;
(b)	forwarded the proceeds of the Rights Offering to us; and
(c)	returned the excess monies to the subscribers in the event of over-subscription.

Subscription Agent and Subscription Office

         We have appointed Computershare Trust Company of Canada (the “Subscription Agent”) as subscription agent to:

(a)	receive subscriptions and payments from subscribers for Trust Units under the Initial Subscription Privilege and the Additional Subscription Privilege;
(b)	perform the services relating to the exercise of the Rights;
(c)	act as the agent for Unitholders who are Ineligible Persons as described under “Details of the Rights Offering — Ineligible Persons”; and
(d)	act as registrar and transfer agent for the Trust Units.

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         You should forward your subscription for Trust Units, by hand, courier or mail to the Subscription Agent at 100 University Avenue, 9th Floor, Toronto, Ontario, M5J 2Y1 (the “Subscription Office”) so that it arrives prior to the Rights Expiry Time.

         We will pay for all services of the Subscription Agent.

HOW TO EXERCISE THE RIGHTS

General

         By completing the appropriate form or forms on the Rights Certificate in accordance with the instructions outlined below, you may:

(a)	subscribe for Trust Units under the Initial Subscription Privilege (Form 1);
(b)	subscribe for additional Trust Units under the Additional Subscription Privilege (Form 2);
(c)	sell or transfer Rights (Form 3); or
(d)	divide, combine or exchange a Rights Certificate (Form 4).

Unexercised Rights

         If you elect to exercise only some of your Rights by completing a Form 1, unless you complete Form 4 to receive a new Rights Certificate the balance of your Rights will be void and of no value. See “How to Exercise the Rights — To Divide, Combine or Exchange a Rights Certificate — Form 4”, page 73.

Signatures

         If you are a trustee, executor or administrator or an officer of a corporation or any person acting in a representative capacity and you sign a form on the Rights Certificate, you must provide satisfactory evidence of your authority to sign to the Subscription Agent.

To Subscribe for Units — Form 1

         You may subscribe for all or any lesser number of Trust Units under your Rights Certificate by:

(a)	completing and executing Form 1 on the Rights Certificate; and
(b)	delivering the Rights Certificate, and payment for the Rights you have exercised, to the Subscription Office on or before the Rights Expiry Time.

         For each Trust Unit you wish to purchase you must pay the full Rights Exercise Price in Canadian funds and may pay by certified check, bank draft or money order payable to “Computershare Trust Company of Canada”.

         Completion of Form 1 constitutes a representation that you are a person resident in Canada or the United States, excluding residents of the State of Florida, or the agent of such a person.

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To Subscribe for Additional Units — Form 2

         If you exercise all of your Rights pursuant to the Initial Subscription Privilege (a “Second Stage Participant”) you may subscribe for Trust Units from Rights the other Rightsholders have not exercised pursuant to the Initial Subscription Privilege, if any (the “Unsubscribed Units”).

         As a Second Stage Participant, you may subscribe for the lesser of:

(a)	the number of Unsubscribed Units you specify in Form 2 on your Rights Certificate (the “Specified Number”); and
(b)	the product (disregarding fractions) (the “Pro Rata Number”) obtained by multiplying:

(i)	the number of Unsubscribed Units; by
(ii)	a fraction, the numerator of which is the number of Rights exercised by you pursuant to the Initial Subscription Privilege, and the denominator of which is the aggregate number of Rights exercised by all Second Stage Participants pursuant to the Initial Subscription Privilege.

         If a Second Stage Participant’s Specified Number is less than that Second Stage Participant’s Pro Rata Number, we will allocate the difference among those Second Stage Participants whose Pro Rata Numbers are less than their Specified Numbers. We will make the allocation on the same basis as described in (b) above, except that the denominator in (b)(ii) will be reduced by the aggregate number of Rights exercised pursuant to the Initial Subscription Privilege by each Second Stage Participant whose Specified Number is less than its Pro Rata Number.

         If you wish to accept the offer to subscribe for additional Trust Units pursuant to the Additional Subscription Privilege, you must:

(a)	complete and execute Form 2;
(b)	complete and execute Form 1; and
(c)	deliver the Rights Certificate and payment for the Rights exercised and Unsubscribed Units to the Subscription Office on or before the Rights Expiry Time.

         You must pay in Canadian funds and may pay by certified check, bank draft or money order payable to “Computershare Trust Company of Canada”.

         The Subscription Agent will notify Second Stage Participants of the number of Unsubscribed Units, if any, it allocates to them, and will deliver Unit Certificates as soon as possible. The Subscription Agent will return checks for excess subscription monies by mail without interest or deduction within 30 days of the Rights Expiry Time.

To Sell or Transfer Rights — Form 3

         Rights Certificates are in registered form. Instead of exercising your Rights, you may sell or transfer them by completing Form 3 on your Rights Certificate and delivering it to the purchaser or other transferee (a “transferee”). If a Rights Certificate is transferred in blank, we may and the Subscription Agent may thereafter treat the bearer as the absolute owner of the Rights Certificate for all purposes and any notice to the contrary will not affect either the Subscription Agent or us. We will not register Rights Certificates in the name of an Ineligible Person.

         The transferee will have all of the rights and privileges of the transferring Rightsholder without obtaining a new Rights Certificate, except in respect of subscribing under the Additional Subscription Privilege. A transferee must

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obtain a new Rights Certificate to exercise its Additional Subscription Privilege. A transferee may exercise the Additional Subscription Privilege by:

(a)	completing and executing Form 3;
(b)	delivering the Rights Certificate to the Subscription Agent;
(c)	receiving a new Rights Certificate issued by the Subscription Agent and registered in the name of the transferee; and
(d)	following the instructions under the heading “How to Exercise the Rights — To Subscribe for Additional Units — Form 2”, page 71.

         If you are a transferring Rightsholder you must have your signature on Form 3 guaranteed by an Eligible Institution satisfactory to the Subscription Agent. An “Eligible Institution” means a Canadian schedule 1 chartered bank, a major trust company in Canada, a member of the Securities Transfer Agent Medallion Program (STAMP), a member of the Stock Exchanges Medallion Program (SEMP) or a member of the New York Stock Exchange, Inc. Medallion Signature Program (MSP). Members of these programs are usually members of a recognized stock exchange in Canada or the United States, members of the Investment Dealers Association of Canada, members of the National Association of Securities Dealers or banks and trust companies in the United States. Contact your bank, broker or financial institution to determine if it is an Eligible Institution. The signature of the transferee on any one or more of the forms on the Rights Certificate must correspond exactly with the name of that transferee shown on Form 3.

To Divide, Combine or Exchange a Rights Certificate — Form 4

         You may divide, combine or exchange your Rights Certificate by completing and executing Form 4 and delivering the Rights Certificate to the Subscription Office. The Subscription Agent will then issue new Rights Certificates in any denominations (totalling the same number of Rights as are evidenced by the Rights Certificate being divided, exchanged or combined) as you request. The Subscription Agent will not issue a new Rights Certificate representing fewer than ten Rights. You must surrender Rights Certificates for division, combination or exchange prior to 4:30 p.m. Calgary time, on •, 2002.

         By duly completing and executing Form 4 on the Rights Certificate, a bank, trust company, investment dealer or broker holding Dividend Units on the Rights Record Date for more than one beneficial owner may divide and transfer the Rights Certificate issued to it, upon providing satisfactory evidence to the Subscription Agent of the ownership of those Dividend Units.

BUSINESS AND PROPERTIES RELATING TO THE ADDITIONAL ASSETS

The Take-Up Agreement

         Following the effectiveness of the U.S. registration statement in which this prospectus is included and the issuance of final receipts for the Canadian Prospectus, the Trust Structuring will be completed, including the execution of the Take-Up Agreement by PRL and the Administrator as trustee for POT. At the Rights Expiry Time we will use the gross proceeds from the Rights Offering to repay the $30,000,000 we will owe to PRL arising from the acquisition of the Initial Assets and the remainder of such proceeds along with available bank financing to acquire up to 100% of PRL’s interest in the Additional Assets. See “Formation of Trust Structure and Structuring Transactions — Trust Structuring”, page 29 and “Bank Financing and Guarantees”, page 65.

         The obligation of PRL to sell to POT all or part of its interest in the Additional Assets under the Take-Up Agreement is subject to the normal terms and conditions of a purchase and sale agreement, including the requirement of obtaining any necessary third party consents or waivers and governmental approvals. The obligation of POT to acquire

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all or part of PRL’s interest in the Additional Assets under the Take-Up Agreement is subject to the normal terms and conditions of a purchase and sale agreement and to the conditions that we satisfy the notification and approval provisions of the Competition Act (Canada) and PRL’s lenders concurrently release the $20,000,000 guarantee of PRL’s debt and related security that we provided to them arising as a result of our acquisition of the Initial Assets. The conveyance of the applicable interest in the Additional Assets is expected to be completed shortly after the Rights Expiry Time. We will assume all risks on the Additional Assets POT acquires, and revenues and expenses associated with the Additional Assets acquired by POT will be adjusted and accrue to POT for POT’s account, as of July 1, 2002. The purchase price for 100% of PRL’s interest in the Additional Assets will be $220,000,000. Interest on the purchase price less the amount of the deposit ($5,000,000) shall be payable to PRL at a rate of 6.5% per annum from July 1, 2002 until closing. The purchase price for the Additional Assets was calculated based on the present value, before income tax, of the expected future cash flows generated by the oil and natural gas properties included in the Additional Assets, discounted by 15% as derived from the escalating price reserve evaluation prepared by McDaniel effective July 1, 2002 and adjusted for the undeveloped land and ancillary assets included in the Additional Assets. Assuming all of the Rights are exercised and our lenders advance our requested loan of $100,000,000 under our proposed credit facility, there will be sufficient funds available to acquire 100% of PRL’s interest in the Additional Assets and to repay our $30,000,000 indebtedness to PRL arising from the acquisition of the Initial Assets. If less than all of the Rights are exercised, or our lenders do not loan to us our requested loan under the proposed credit facility, we will use the gross proceeds of the Rights Offering to repay the $30,000,000 we will owe to PRL arising from the acquisition of the Initial Assets, and use the remainder of such proceeds together with the amount our lenders are willing to advance under our proposed credit facility to acquire as much as we are able of the Additional Assets. The interest in the Additional Assets that we will acquire will be proportionate to the amount that such remainder is to the total purchase price of the Additional Assets. We may also use net revenues accruing to POT from July 1, 2002 to the completion of the Rights Offering associated with the Initial Assets and the applicable portion of Additional Assets in our acquisition of the Additional Assets. In the event that we are unable, for whatever reason, to complete our purchase of any interest in the Additional Assets, we will not return the proceeds from the exercise of your Rights. In those circumstances we will utilize the criteria referred to under “Plan of Operations — Acquisitions” in order to select and acquire other suitable assets. See “Use of Proceeds”, page 56 and “Bank Financing and Guarantees”, page 65. PRL will continue to hold any of its interest in the Additional Assets that POT does not acquire. See “Formation of Trust Structure and Structuring Transactions — Trust Structuring”, page 29.

Additional Assets

         The Additional Assets are comprised of 100% of PRL’s interest in the oil and natural gas properties and related assets provided for in the Take-Up Agreement. The following is a summary description thereof. At the time of closing, PRL will retain any of its interest in the Additional Assets that POT does not acquire. The Additional Assets are properties comprised of Alberta provincial Crown and Indian Oil and Gas Canada leases that have been in existence for a number of years without any disputes as to ownership. As at July 31, 2002, 99.5% of the proved producing reserves (108.89 bcf) associated with the Additional Assets were on production. See the fold-out map on the inside of the cover page to this prospectus. Pursuant to the Take-Up Agreement, we anticipate we will become the operator of those Additional Assets where PRL is currently the operator. The reserves in the Corner and Quigley properties are currently dedicated to a gas purchase contract between PRL and a third party cogeneration facility. The consent of this third party is required to replace the reserves in the Corner and Quigley properties under this contract with reserves from PRL’s other lands. PRL has advised that it is currently making arrangements to obtain that consent.

         The Additional Assets consist entirely of natural gas producing properties and related transportation and processing facilities located in the northeast part of the Province of Alberta. Consequently, the operations related to the Additional Assets consist of one business segment in one geographic segment. There have been no significant changes in the operations related to the Additional Assets during the last three financial years.

         The demand for natural gas is affected by temperature changes on the North American continent. Moderate temperatures reduce consumption of natural gas which could cause an oversupply of natural gas and a reduction in prices received for natural gas. Conversely, extreme temperatures could increase consumption of natural gas and increase prices. Consequently, overall revenue can be higher or lower depending on weather conditions at any particular time of the year.

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         While there are no significant seasonal limitations on gas production from the Additional Assets, the Additional Assets are located in winter access areas and consequently, capital and operating expenditures tend to be higher in winter months.          Natural gas from the Additional Assets is produced and sold to third party purchasers under industry standard terms at or near the point of production.          The Additional Assets do not require additional raw materials for the production of natural gas.          The production of natural gas from the Additional Assets is not dependent on significant patents, licenses or industrial, commercial or financial contracts.

         For a description of the effects of government regulation on the Additional Assets see “Government Regulations”, page 111.

Principal Properties

Bohn Lake, Alberta

         The Bohn Lake Area is in northeast Alberta approximately 90 kilometres south of Fort McMurray. The area comprises 47,360 gross acres (14,806 net acres) including an average 27.60% working interest in 26 (7.17 net) producing natural gas wells in the area. The average daily production to PRL for the month of August, 2002 from the Bohn Lake Area was approximately 2.5 mmcf/d of natural gas (net). The McDaniel Report evaluated PRL’s total proved reserves at 4.67 bcf (gross) of natural gas for the Bohn Lake Area. Production from the Bohn Lake Area is processed through one gas plant owned and operated by Canadian Natural Resources Limited.

Chard, Alberta

         The Chard Area is in northeast Alberta approximately 85 kilometres south of Fort McMurray. The area comprises 26,240 gross acres (21,720 net acres) including an average 81.69% working interest in 16 (13.1 net) producing natural gas wells in the area. The average daily production to PRL for the month of August, 2002 from the Chard Area was approximately 1.7 mmcf/d of natural gas (net). The McDaniel Report evaluated PRL’s total proved reserves at 2.45 bcf (gross) of natural gas for the Chard Area. Production from the Chard Area is processed through one booster compressor owned 79.8% by PRL which is included in the Additional Assets.

Chard Southwest, Alberta

         The Chard Southwest Area is in northeast Alberta approximately 85 kilometres south of Fort McMurray. The area comprises 17,280 gross acres (8,304 net acres) including an average 40.67% working interest in 9 (3.7 net) producing natural gas wells in the area. The average daily production to PRL for the month of August, 2002 from the Chard Southwest Area was approximately 0.6 mmcf/d of natural gas (net). The McDaniel Report evaluated PRL’s total proved reserves at 1.23 bcf (gross) of natural gas for the Chard Southwest Area. Production from the Chard Southwest Area is processed through one booster compressor owned by Superman Resources Inc. and one gas plant owned by Canadian Natural Resources Limited. PRL’s interest in the gas plant is 33.3% and is included in the Additional Assets.

Clyde, Alberta

         The Clyde Area is in northeast Alberta approximately 85 kilometres southwest of Fort McMurray. The area comprises 25,720 gross acres (24,691 net acres) including an average 93.83% working interest in 12 (11.3 net) producing natural gas wells in the area. The average daily production to PRL for the month of August, 2002 from the Clyde Area was approximately 2.7 mmcf/d of natural gas (net). The McDaniel Report evaluated PRL’s total proved reserves at

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1.72 bcf (gross) of natural gas for the Clyde Area. Production from the Clyde Area is processed through one gas plant owned 100% by PRL which is included in the Additional Assets.

Cold Lake, Alberta

         The Cold Lake Area is in northeast Alberta approximately 250 kilometres southeast of Fort McMurray. The Cold Lake area comprises 85,160 gross acres (66,952 net acres) including an average 80.43% working interest in 42 (33.78 net) producing natural gas wells in the area. The average daily production to PRL for the month of August, 2002 from the Cold Lake Area was approximately 6.2 mmcf/d of natural gas (net). The McDaniel Report evaluated PRL’s total proved reserves at 9.41 bcf (gross) of natural gas for the Cold Lake Area. Production from the Cold Lake Area is processed through 14 booster and/or compressor stations owned by Altagas Services Inc.

Cold Lake Sonoma, Alberta

         The Cold Lake Sonoma Area is in northeast Alberta approximately 250 kilometres southeast of Fort McMurray. The Cold Lake Sonoma area comprises 54,400 gross acres (44,150 net acres) including an average 74.04% working interest in 28 (20.7 net) producing natural gas wells in the area. The average daily production to PRL for the month of August, 2002 from the Cold Lake Sonoma Area was approximately 3.2 mmcf/d of natural gas (net). The McDaniel Report evaluated PRL’s total proved reserves at 5.54 bcf (gross) of natural gas for the Cold Lake Sonoma Area. Production from the Cold Lake Sonoma Area is processed through four compressor stations, three at Marie Lake and one at Wolf Lake which are 100% owned by PRL and are included in the Additional Assets.

Corner, Alberta

         The Corner Area is in northeast Alberta approximately 80 kilometres southwest of Fort McMurray. The area comprises 106,240 gross acres (104,195 net acres) including an average 98.97% working interest in 59 (58.39 net) producing natural gas wells in the area. The average daily production to PRL for the month of August, 2002 from the Corner Area was approximately 12.9 mmcf/d of natural gas (net). The McDaniel Report evaluated PRL’s total proved reserves at 17.91 bcf (gross) of natural gas for the Corner Area. Production from the Corner Area is processed through one gas plant owned 100% by PRL which is included in the Additional Assets.

Hoole, Alberta

         The Hoole Area is in northeast Alberta approximately 175 kilometres southwest of Fort McMurray. The area comprises 12,160 gross acres (7,040 net acres) including an average 70% working interest in 5 (3.5 net) producing natural gas wells in the area. The average daily production to PRL for the month of August, 2002 from the Hoole Area was approximately 0.2 mmcf/d of natural gas (net). The McDaniel Report evaluated PRL’s total proved reserves at 0.15 bcf (gross) of natural gas for the Hoole Area. Production from the Hoole Area is processed through one gas plant owned by Husky Energy Inc.

Kettle River, Alberta

         The Kettle River Area is in northeast Alberta approximately 80 kilometres south of Fort McMurray. The area comprises 35,200 gross acres (33,111 net acres) including an average 94.67% working interest in 24 (22.72 net) producing natural gas wells in the area. The average daily production to PRL for the month of August, 2002 from the Kettle River Area was approximately 4.3 mmcf/d of natural gas (net). The McDaniel Report evaluated PRL’s total proved reserves at 6.92 bcf (gross) of natural gas for the Kettle River Area. Production from the Kettle River Area is processed through one gas plant owned 92.5% by PRL, which is included in the Additional Assets.

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Legend East, Alberta

         The Legend East Area is in northeast Alberta approximately 120 kilometres west of Fort McMurray. The area comprises 52,480 gross acres (52,480 net acres) including a 100% working interest in 17 producing natural gas wells in the area. The average daily production to PRL for the month of August, 2002 from the Legend East Area was approximately 3.6 mmcf/d of natural gas (net). The McDaniel Report evaluated PRL’s total proved reserves at 3.44 bcf (gross) of natural gas for the Legend East Area. Production from the Legend East Area is processed through the Legend gas plant included with the Initial Assets and two field booster compressors owned by PRL which are included in the Additional Assets.

Leismer / Leismer South, Alberta

         The Leismer / Leismer South Area is in northeast Alberta approximately 90 kilometres southwest of Fort McMurray. The area comprises 212,160 gross acres (196,155 net acres) including a 91.62% working interest in 53 (48.6 net) producing natural gas wells in the area. The average daily production to PRL for the month of August, 2002 from the Leismer / Leismer South Area was approximately 9.0 mmcf/d of natural gas (net). The McDaniel Report evaluated PRL’s total proved reserves at 10.06 bcf (gross) of natural gas for the Leismer / Leismer South Area. Production from the Leismer / Leismer South Area is processed through one gas plant owned 32.5% by PRL and three field booster compressors owned by PRL which are included in the Additional Assets.

Liege East, Alberta

         The Liege East Area is in northeast Alberta approximately 120 kilometres west of Fort McMurray. The area comprises 13,760 gross acres (12,587 net acres) including an average 89.70% working interest in 10 (9.0 net) producing natural gas wells in the area. The average daily production to PRL for the month of August, 2002 from the Liege East Area was approximately 2.6 mmcf/d of natural gas (net). The McDaniel Report evaluated PRL’s total proved reserves at 3.36 bcf (gross) of natural gas for the Liege East Area. Production from the Liege East Area is processed through the Liege South gas plant owned 80.5% by PRL and one Liege East field booster compressor owned 90.2% by PRL, which are included in the Additional Assets.

Liege North, Alberta

         The Liege North Area is in northeast Alberta approximately 120 kilometres west of Fort McMurray. The area comprises 73,280 gross acres (66,851 net acres) including an average 94.86% working interest in 14 (13.3 net) producing natural gas wells in the area. The average daily production to PRL for the month of August, 2002 from the Liege North Area was approximately 3.0 mmcf/d of natural gas (net). The McDaniel Report evaluated PRL’s total proved reserves at 4.06 bcf (gross) of natural gas for the Liege North Area. Production from the Liege North Area is processed through one gas plant owned 94.6% by PRL, which is included in the Additional Assets.

Liege South, Alberta

         The Liege South Area is in northeast Alberta approximately 120 kilometres west of Fort McMurray. The area comprises 98,720 gross acres (90,406 net acres) including an average 96.76% working interest in 25 (24.19 net) producing natural gas wells in the area. The average daily production to PRL for the month of August, 2002 from the Liege South Area was approximately 4.7 mmcf/d of natural gas (net). The McDaniel Report evaluated PRL’s total proved reserves at 4.71 bcf (gross) of natural gas for the Liege South Area. Production from the Liege South Area is processed through one gas plant owned 80.5% by PRL and three field compressors owned by PRL, which are included in the Additional Assets.

Pony, Alberta

         The Pony Area is in northeast Alberta approximately 75 kilometres southwest of Fort McMurray. The area comprises 18,560 gross acres (7,280 net acres) including an average 52.60% working interest in 5 (2.6 net) producing

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natural gas wells in the area. The average daily production to PRL for the month of August, 2002 from the Pony Area was approximately 0.5 mmcf/d of natural gas (net). The McDaniel Report evaluated PRL’s total proved reserves at 0.80 bcf of natural gas for the Pony Area. Production from the Pony Area is processed through one gas plant owned by Canadian Natural Resources Limited.

Quigley, Alberta

         The Quigley Area is in northeast Alberta approximately 80 kilometres south of Fort McMurray. The area comprises 65,920 gross acres (65,920 net acres) including a 100% working interest in 22 producing natural gas wells in the area. The average daily production to PRL for the month of August, 2002 from the Quigley Area was approximately 3.5 mmcf/d of natural gas (net). The McDaniel Report evaluated PRL’s total proved reserves at 2.00 bcf (gross) of natural gas for the Quigley Area. Production from the Quigley Area is processed through one gas plant and one field compressor owned by PRL, which are included in the Additional Assets.

Saleski, Alberta

         The Saleski Area is in northeast Alberta approximately 110 kilometres west of Fort McMurray. The area comprises 88,000 gross acres (81,766 net acres) including an average 95.05% working interest in 19 (18.1 net) producing natural gas wells in the area. The average daily production to PRL for the month of August, 2002 from the Saleski Area was approximately 4.2 mmcf/d of natural gas (net). The McDaniel Report evaluated PRL’s total proved reserves at 10.05 bcf of natural gas for the Saleski Area. Production from the Saleski Area is processed through one gas plant owned 95.8% by PRL, which is included in the Additional Assets.

Surmont, Alberta

         The Surmont Area is in northeast Alberta approximately 65 kilometres southwest of Fort McMurray. The area comprises 10,880 gross acres (2,720 net acres) including an average 25% working interest in 1 (0.3 net) producing natural gas well in the area. The average daily production to PRL for the month of August, 2002 from the Surmont Area was approximately 0.1 mmcf/d of natural gas (net). The McDaniel Report evaluated PRL’s total proved reserves at 60 mmcf (gross) of natural gas for the Surmont Area. Production from the Surmont Area is processed through one gas plant owned by Devon Canada Corporation.

Teepee Creek, Alberta

         The Teepee Creek Area is in northeast Alberta approximately 175 kilometres southwest of Fort McMurray. The area comprises 147,439 gross acres (95,801 net acres) including an average 50% working interest in 17 (8.5 net) producing natural gas wells in the area. The average daily production to PRL for the month of August, 2002 from the Teepee Creek Area was approximately 1.7 mmcf/d of natural gas (net). The McDaniel Report evaluated PRL’s total proved reserves at 0.66 bcf (gross) of natural gas for the Teepee Creek Area. Production from the Teepee Creek Area is processed through one gas plant owned by Devon Canada Corporation in which PRL has a 37.5% interest, which interest is included in the Additional Assets.

Thornbury, Alberta

         The Thornbury Area is in northeast Alberta approximately 75 kilometres southwest of Fort McMurray. The area comprises 51,200 gross acres (35,136 net acres) including an average 73.54% working interest in 41 (30.2 net) producing natural gas wells in the area. The average daily production to PRL for the month of August, 2002 from the Thornbury Area was approximately 4.8 mmcf/d of natural gas (net). The McDaniel Report evaluated PRL’s total proved reserves at 11.82 bcf (gross) of natural gas for the Thornbury Area. Production from the Thornbury Area is processed through four gas plants and a field booster compressor owned by Altagas Services Inc.

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Winefred, Alberta

         The Winefred Area is in northeast Alberta approximately 200 kilometres southeast of Fort McMurray. The area comprises 98,560 gross acres (83,648 net acres) including an average 88.46% working interest in 39 (34.5 net) producing natural gas wells in the area. The average daily production to PRL for the month of August, 2002 from the Winefred Area was approximately 4.7 mmcf/d of natural gas (net). The McDaniel Report evaluated PRL’s total proved reserves at 10.41 bcf (gross) of natural gas for the Winefred Area. Production from the Winefred Area is processed through two gas plants and a field booster compressor owned by Altagas Services Inc.

For development plans concerning the Additional Assets see “Future Development”, page 38.

History — Daily Sales Volumes and Netbacks

         The following table sets forth the daily sales volumes and netbacks on a quarterly basis in respect of PRL’s interest in the Additional Assets for the quarters ended June 30, 2002 and March 31, 2002 and for the years ended December 31, 2001 and December 31, 2000.

		2002						2001
																				2001
		Quarter Ended						Quarter Ended												Total
		June 30			March 31			Dec 31			Sept 30			June 30			Mar 31
Daily Sales Volumes
	Natural Gas (mmcf/d)		75.4			78.0			71.9			88.3			93.7			87.9			85.4
Natural Gas Netbacks ($/mcf)
	Sales	$	3.75		$	2.54		$	3.21		$	3.86		$	6.46		$	11.64		$	6.41
	Royalties		(0.56	)		(0.45	)		(0.63	)		(1.06	)		(0.72	)		(2.27	)		(1.18	)
	Operating Costs(1)		(0.61	)		(1.22	)		(1.00	)		(1.02	)		(0.68	)		(0.94	)		(0.91	)
	Netback	$	2.58		$	0.87		$	1.58		$	1.78		$	5.06		$	8.43		$	4.32

		2000
														2000
		Quarter Ended												Total
		Dec 31			Sept 30			June 30			Mar 31
Daily Sales Volumes
	Natural Gas (mmcf/d)		85.1			91.4			101.4			95.7			93.4
Natural Gas Netbacks ($/mcf)
	Sales	$	7.41		$	4.92		$	3.72		$	2.86		$	4.65
	Royalties		(1.16	)		(1.13	)		(0.53	)		(0.62	)		(0.85	)
	Operating Costs(1)		(0.59	)		(0.66	)		(0.65	)		(0.55	)		(0.61	)
	Netback	$	5.66		$	3.13		$	2.54		$	1.69		$	3.19

Note:

(1) Operating costs include amounts incurred to bring natural gas to the surface, gather store, field process, treat and store same, including principally labor, processing, utilities, supplies, repairs and maintenance, taxes, lease rentals and overhead.

Capital Expenditures

         The following table shows capital expenditures made by PRL on the Additional Assets in the categories and for the periods indicated:

	2002				2001
															2001
($000)	Quarter Ended				Quarter Ended										Total
Category of Expenditure	June 30		March 31		Dec 31		Sept 30			June 30		Mar 31
Land and Acquisition	$	—		7	$	43	$	(194	)	$	23	$	(27	)	$	(155	)
Drilling & Exploration		—		3,008		190		257			4,923		5,666			11,036

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	2002					2001
														2001
($000)	Quarter Ended					Quarter Ended								Total
Category of Expenditure	June 30		March 31			Dec 31		Sept 30		June 30		Mar 31
Equipping		—		56			23		44		207		161		435
Facilities & Gathering		351		(127	)		2,356		3,044		7,681		4,806		17,887
Total	$	351		2,944		$	2,612	$	3,151	$	12,834	$	10,606	$	29,203

	2000
									2000
	Quarter Ended								Total
Category of Expenditure	Dec 31		Sept 30		June 30		Mar 31
Land and Acquisition	$	911	$	62	$	495	$	30	$	1,498
Drilling & Exploration		1,132		1,892		1,649		3,575		8,248
Equipping		301		86		555		47		989
Facilities & Gathering		691		3,640		4,447		12,705		21,483
Total	$	3,035	$	5,680	$	7,146	$	16,357	$	32,218

Note:

(1)	Reference should be made to note 11 under the heading “Business and Properties Relating to the Additional Assets — Natural Gas Revenues — Additional Assets” below for McDaniel’s estimates of required Capital Expenditures for 2002 in relation to the Additional Assets.
(2)	Amounts determined under successful efforts method of accounting as applied by PRL. See note 2 of the historical financial statements for the Northeast Alberta Properties.

Future Commitments

         We have no material future contracts to buy, sell or transport natural gas from the Additional Assets.

Land Holdings

         The following table sets out the developed and undeveloped land holding in the area comprising the Additional Assets as of July 1, 2002:

Name of Area (Alberta)	Developed Acres				Undeveloped Acres(3)				Undeveloped
									Acres Market
	Gross(1)		Net(2)		Gross(1)		Net(2)		Value(4)
Bohn Lake		45,760		14,273		1,600		533	$	2,012
Chard		19,840		15,476		6,400		6,244	$	91,833
Chard Southwest		7,680		3,118		9,600		5,186	$	118,119
Clyde		11,580		10,551		14,140		14,140	$	253,700
Cold Lake		59,520		46,096		25,640		20,856	$	326,028
Cold Lake Sonoma		39,360		30,006		15,040		14,144	$	99,360
Corner		76,800		75,715		29,440		28,480	$	348,800
Hoole		5,760		3,520		6,400		3,520	$	170,880
Kettle River		35,200		33,111		—		—		—
Legend East		26,880		26,880		25,600		25,600	$	105,600
Leismer / Leismer South		116,480		106,915		95,680		89,240	$	1,744,452
Liege East		11,840		10,751		1,920		1,836	$	12,043
Liege North		73,280		66,851		—		—		—
Liege South		84,640		77,606		14,080		12,800	$	53,402
Pony		11,520		4,240		7,040		3,040	$	25,600
Quigley		52,160		52,160		13,760		13,760	$	108,800
Saleski		64,640		61,200		23,360		20,566	$	109,129
Surmont		5,760		1,440		5,120		1,280	$	8,960
Teepee Creek		77,679		40,761		69,760		55,040	$	437,139
Thornbury		48,000		33,984		3,200		1,152	$	6,400
Winefred		68,480		61,248		30,080		22,400	$	171,742
Total		942,859		775,902		397,860		339,817	$	4,193,999

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Notes:

(1)	“Gross” means the total number of developed and undeveloped acres, respectively, in which PRL has an interest in respect of the Additional Assets.
(2)	“Net” means the aggregate of the numbers obtained by multiplying each gross acre by the actual percentage interest therein.
(3)	During 2002, 26,560 net acres are set to expire. During 2003, 219,200 net acres are set to expire. We intend to assess such expiring lands and, where appropriate, seek continuation through development activity or, in the case of higher risk areas, farmouts, where third parties provide exploration funding in exchange for an earned working interest.
(4)	Market value has been taken from the McDaniel Report “Update on Unproven Acreage Interests as of July 1, 2002” based upon McDaniel’s individual price per acre estimates as of January 1, 2002.

Natural Gas Wells

         The following table shows the number of natural gas wells producing or capable of producing in the Additional Assets as at July 1, 2002.

	Natural Gas Wells
	Producing				Non-Producing(3)(4)
Name of Area (Alberta)	Gross(1)		Net(2)		Gross(1)		Net(2)
Bohn Lake		25		6.8		—		—
Chard		16		13.1		—		—
Chard Southwest		9		3.7		—		—
Clyde		12		11.3		—		—
Cold Lake		44		34.9		8		4.8
Cold Lake Sonoma		28		20.7		2		1.9
Corner		58		57.4		—		—
Hoole		5		3.5		—		—
Kettle River		22		20.7		—		—
Legend E		16		16.0		—		—
Leismer / Leismer South		53		48.6		4		3.3
Liege East		10		9.0		—		—
Liege North		14		13.3		—		—
Liege South		23		22.3		—		—
Pony		5		2.6		—		—
Quigley		22		22.0		—		—
Saleski		19		18.1		—		—
Surmont		1		0.3		—		—
Teepee Creek		15		7.5		—		—
Thornbury		41		30.2		—		—
Winefred		39		34.5		3		2.5
Additional Assets Total		477		396.5		17		12.5

Notes:

(1)	“Gross” refers to the number of wells, producing and non-producing, respectively, in which a working interest or royalty interest is included in the Additional Assets.
(2)	“Net” refers to the aggregate of the numbers obtained by multiplying each gross well by the percentage working interest therein.
(3)	“Non-Producing” refers to wells which are not currently producing either due to lack of facilities and/or markets but are capable of producing in commercial quantities.
(4)	Additionally, there is included in the Additional Assets 469 (395.7 net) wells which are not capable of producing in commercial quantities at this time. Allowance for the abandonment costs associated with the wellbores was made in the McDaniel Report. There are 20 wells that are classified as service wells included in the gross/net well count.

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Drilling Activity

         PRL drilled, or participated in drilling, exploratory and development wells on the Additional Assets for the periods indicated as shown in the following table. The “Natural Gas” wells listed below comprise all natural gas wells capable of production, whether producing or capped, included in the Additional Assets.

	Quarter Ended				Quarter Ended				Year Ended				Year Ended				Year Ended
	June 30, 2002				March 31, 2002				December 31, 2001				December 31, 2000				December 31, 1999
Natural Gas Wells	Gross(1)		Net(2)		Gross(1)		Net(2)		Gross(1)		Net(2)		Gross(1)		Net(2)		Gross(1)		Net(2)
Natural Gas		—		—		5		3.9		30		26.5		36		28.1		45		38.4
Service		—		—		2		1.4		1		0.5		1		0.3		—		—
Dry and Abandoned		—		—		2		1.5		3		2.5		1		1.0		3		2.4
Total		—		—		9		6.8		34		29.5		38		29.4		48		40.8
Success Rate (%)						77.8		77.9		91.2		91.5		97.4		96.6		93.8		94.1
Exploratory(3)		—		—		—		—		11		10.0		20		18.3		16		12.6
Development(4)		—		—		9		6.8		23		19.5		17		10.6		32		28.2
Total		—		—		9		6.8		34		29.5		38		29.4		48		40.8

Notes:

(1)	“Gross” refers to all wells in which a working interest or a royalty interest is included in the Additional Assets.
(2)	“Net” refers to the aggregate of the percentage working interests in the gross wells, before the deduction of royalties comprised in the Additional Assets.
(3)	“Exploratory” well, in general, is a well either drilled in search of a new and yet undiscovered pool of oil or natural gas, or with the expectation of significantly extending the limits of a pool which is partly delineated.
(4)	“Development” well, in general, is a well drilled within or in close proximity to a discovered pool of oil or natural gas.

Production History

         The following table shows the average daily net production from the Additional Assets, before deduction of royalties payable to others, for the periods indicated.

	Quarter Ended		Quarter Ended		Year Ended		Year Ended		Year Ended
Type of Production	June 30, 2002		March 31, 2002		December 31, 2001		December 31, 2000		December 31, 1999
Natural Gas (mmcf/d)		75.4		78.0		85.4		93.4		99.0

Natural Gas Reserves — Additional Assets

         The McDaniel Report evaluates the proved natural gas reserves attributable to PRL’s interest in the properties comprising the Additional Assets using a constant price of $2.87 per Mmbtu as provided by PRL, being the price received by PRL for sales of natural gas on June 28, 2002, based upon Remaining Reserves (as defined below) as of July 1, 2002. These reserves are all located in Alberta, Canada. For the purposes of this prospectus we are utilizing only the proved reserves.

         In preparing its report, McDaniel used basic historical information it had from PRL for its January 1, 2002 evaluation of PRL, which included land data, well information, geological information, reservoir studies, estimates of on-stream dates, contract information, hydrocarbon product prices, operating cost data, financial data and future operating plans. McDaniel obtained other engineering, geological or economic data required to conduct the evaluation and upon which the McDaniel Report is based, from public records, other operators and from McDaniel’s non-confidential files. McDaniel accepted as represented from all sources the extent and character of ownership and the accuracy of all factual data supplied for the independent evaluation.

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         The price utilized for the constant price assumptions in the McDaniel Report was Cdn $2.87 per Mmbtu for natural gas.

         The following tables, based on the McDaniel Report, show the estimated share in respect of the natural gas reserves in the properties comprised in the Additional Assets and the discounted present value of estimated future net revenues for these reserves using constant prices and costs. All evaluations of the present worth of estimated future net revenue in the McDaniel Report are stated after provision for estimated future capital expenditures and operating costs. An allowance for future wellbore abandonment costs was made for all wells in which there is a working interest; however no allowance was made for the abandonment of any surface, wellsites and facilities, for income tax or for ARTC. These evaluations do not necessarily represent the fair market value of the reserves. These evaluations evaluate 100% of PRL’s interest in the proved reserves in the Additional Assets. In the event the Rights Offering is not fully subscribed or if, for any reason (including the failure of POG, Treherne and 409790 to acquire all of the Trust Units that will be available to them under the Initial Subscription Privilege for the Rights that they will receive) our lenders do not loan to us our requested loan under the proposed credit facility that we have arranged with them, POT may be unable to acquire 100% of PRL’s interest in the Additional Assets and POT may only be able to acquire a lesser percentage interest or no interest in the Additional Assets. See “Business and Properties Relating to the Additional Assets”, page 73.

Natural Gas Reserves and Present Value of Estimated Future Cash flows
(Based on Constant Price Assumptions)

	Remaining Reserves of				Present Value Cash Flow
Reserves Categories	Natural Gas(1)(2)				Discounted at 10% (Net)
	Gross(3)		Net(4)
	mmcf		mmcf		(M$)
Proved Developed Producing(7)		108,887		89,381		104,550
Proved Developed Non-Producing(10)		2,520		2,141		(1,504	)
Total Proved(7)		111,407		91,522		103,045

Notes:

(1)	“Natural Gas” means the lighter hydrocarbons and associated non-hydrocarbon substances occurring naturally in an underground reservoir, which under atmospheric conditions is essentially a gas, but which may contain liquids. The natural gas reserve estimates are reported on a marketable basis, that is the gas which is available to a transmission line after removal of certain hydrocarbons and non-hydrocarbon compounds present in the raw natural gas and which meets specifications for use as a domestic, commercial or industrial fuel.
(2)	“Remaining Reserves” means those quantities of crude oil, natural gas, natural gas liquids and sulphur remaining after deducting those quantities produced up to the reference date of the study.
(3)	“Gross” Reserves are the total of PRL’s working interests and/or royalty interests share of reserves before deducting royalties owned by others.
(4)	“Net” Reserves are the total of PRL’s working interests and/or royalty interests share of reserves after deducting the amount attributable to the royalties owned by others.
(5)	The term “royalties”, as used in the McDaniel Report, refers to royalties paid to others. The royalties deducted from the reserves are based on the royalty percentage calculated by applying the applicable Royalty Rate or formula. In the case of Crown sliding scale royalties which are dependent on selling price, the price forecasts for the individual properties in question has been employed.
(6)	“Proved” Reserves are the estimated quantities of crude oil, natural gas and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reserves under existing economic and operating conditions, i.e., prices and costs as of the date the estimate is made. Prices include consideration of changes in existing prices provided only by contractual arrangements, but not on escalations based upon future conditions.

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(7)	“Proved Developed” Reserves are reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. Additional oil and gas expected to be obtained through the application of fluid injection or other improved recovery techniques for supplementing the natural forces and mechanisms of primary recovery should be included as “proved developed” reserves only after testing by a pilot project or after the operation of an installed program has confirmed through production response that increased recovery will be achieved.
(8)	“Proved Undeveloped” Reserves are those reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. Reserves on undrilled acreage shall be limited to those drilling units offsetting productive units that are reasonably certain of production when drilled. Proved reserves for other undrilled units can be claimed only where it can be demonstrated with certainty that there is continuity of production from the existing productive formation. Under no circumstances should estimates for proved undeveloped reserves be attributable to any acreage for which an application of fluid injection to the improved recovery techniques is contemplated, unless such techniques have been provided effective by actual tests in the area and in the same reservoir.
(9)	Sales Gas includes pipeline and solution gas reserves.
(10)	Product prices used in the constant price evaluations are based on McDaniel’s July 1, 2002 price forecast, of Cdn $2.87 per Mmbtu for natural gas. The constant price assumptions assume the continuance of current laws, regulations and operating costs in effect on the effective date of the McDaniel Report.
(11)	The McDaniel Report estimates total net capital investment necessary to achieve the estimated future net cash flow for the proved reserves to be $1,007,000, of which $192,000 is to be spent in 2002 based on constant cost assumptions, in respect of the Additional Assets.

Historical Reserves

         The following table sets out the proved natural gas reserves at December 31, 2001, 2000, 1999 and 1998 (before deducting amounts attributable to royalties owned by others) to the Additional Assets and based upon constant price and cost assumptions. All of these reserves were located in Canada:

		Proved Natural Gas Reserves (bcf)
December 31, 1998			296.4
	Revisions to previous estimates		(38.4	)
	Purchase (sale of reserves)		26.5
	Discoveries and extensions		13.7
	Production		(36.1	)
December 31, 1999			262.1
	Revisions to previous estimates		(66.5	)
	Purchase (sale of reserves)		2.9
	Discoveries and extensions		2.7
	Production		(34.1	)
December 31, 2000			167.1
	Revisions to previous estimates		(0.5	)
	Purchase (sale of reserves)		0.3
	Discoveries and extensions		—
	Production		(31.2	)
December 31, 2001			135.7

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PLAN OF DISTRIBUTION

         The board of directors of the Administrator has determined the Rights Exercise Price based on the net asset value of PRL’s interest in the Additional Assets, being the assets that will be acquired by PET with the proceeds of the Rights Offering. The net asset value of the Additional Assets was calculated by relying on McDaniel’s escalating price evaluation under the McDaniel Report (which is not included herein) of the before tax, discounted present value of estimated future cash flows from the natural gas proved plus risked probable additional reserves included in the Additional Assets, net of the debt anticipated to be available and to be incurred to finance the acquisition of the Additional Assets. Certain additional value was ascribed to the undeveloped lands and ancillary assets included in the Additional Assets. The Trust Units may trade at prices which are influenced by factors other than the net asset value of the Trust Units, including, but not limited to, the anticipated distributions on the Trust Units.          Under the Dealer Manager Agreement dated August 8, 2002, the Dealer Managers agreed to form the Soliciting Dealer Group for the purpose of soliciting subscriptions for the Trust Units offered pursuant to the Rights Offering. In consideration for these services, we will pay any member of the Soliciting Dealer Group (including the Dealer Managers) properly identified in a subscription for Trust Units issued upon the exercise of Rights, a fee of $0.05 for each Trust Unit, subject to a minimum fee of $90 and a maximum fee of $1,500 payable in respect of any one Rightsholder. We will not pay any subscription fee in respect of an exercise of less than 1,500 Rights by any one Rightsholder. We will not pay any subscription fee in respect of the exercise of Rights beneficially owned, directly or indirectly, or over which control or direction is exercised, by POG or any directors or officers of PRL or of the Administrator. We will also reimburse the Dealer Managers for expenses they incur in connection with the Rights Offering, including legal fees. We have agreed to indemnify the Dealer Managers and their controlling persons, directors, officers, employees and agents against certain liabilities. We will also incur our own expenses in relation to this prospectus and the Rights Offering estimated at approximately $1,000,000 consisting of listing fees estimated at $130,000, transfer agency and rights agency fees estimated at $90,000, legal and accounting fees estimated at $780,000. Additionally PRL will incur expenses in relation to the formation of PET, this Offering and the Special Committee estimated at $6,000,000 consisting of advisory fees to the Dealer Managers of $1,700,000, legal and accounting fees and printing costs of $3,450,000 and advisory fees for the Special Committee (including financial and legal) estimated at $850,000. The obligations of the Dealer Managers pursuant to the Dealer Manager Agreement are conditional upon certain terms and conditions for a transaction of this nature including our compliance with all applicable securities laws, the distribution of Trust Units and Rights being as described herein, this Registration Statement becoming effective and the truth and accuracy of all of the information contained herein and our representations and warranties as to factual matters contained in the Dealer Manager Agreement. In the event of a breach or failure to comply with any provision of the Dealer Manager Agreement by us or PRL which is not remedied and/or waived by the Dealer Managers, the Dealer Managers shall have the right to terminate the Dealer Manager Agreement.

The Dealer Managers for the Rights Offering are:

BMO Nesbitt Burns Corp.
700 Louisiana Street, Suite 4400
Houston, Texas 77002
(713) 223-4400 CIBC World Markets Corp.
425 Lexington Avenue
New York, NY 10017
(212) 856-4000 FirstEnergy Capital (USA) Corp.
1600, 333 — 7^th Avenue S.W.
Calgary, Alberta T2P 2Z1
(403) 262-0600

         We have applied for listing of our Trust Units and Rights on the TSX. At the date of this Prospectus, there was no public market for the Trust Units or the Rights. The TSX has conditionally approved the listing of these securities subject to our fulfilling all of the requirements of the TSX on or before January 30, 2003, including distribution of the Dividend Units to a minimum number of public security holders.

         Pursuant to policy statements of the Ontario Securities Commission (“OSC”) and the Commission des valeurs mobilieres du Quebec (“CVMQ”), the Dealer Managers may not, throughout the period of distribution, bid for or purchase Trust Units or Rights. The foregoing restriction is subject to certain exceptions. Such exceptions include:

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(a)	a bid or purchase permitted under the by-laws and rules of the TSX relating to market stabilization and passive market making activities; and
(b)	a bid or purchase made for and on behalf of a customer where the order was not solicited during the period of distribution, provided that the bid or purchase was not engaged in for the purpose of creating actual or apparent active trading in, or raising the price of the securities.

         In order to facilitate the offering of our Trust Units, the Dealer Managers may, if a market develops for the Trust Units, engage in transactions that stabilize, maintain or otherwise affect the market price of our Trust Units. Specifically, the Dealer Managers may bid for, and purchase, Trust Units in the open market, which may maintain the market price of our Trust Units at a level above that which might otherwise prevail in the open market. The Dealer Managers are not required to engage in these activities and, if begun, may end any of these activities at any time.

         Rules of the SEC may limit the ability of the Dealer Managers to bid for or purchase Trust Units before the distribution of the Trust Units is completed. However, the Dealer Managers may, in accordance with the rules, make bids or purchases for the purpose of pegging, fixing or maintaining the price of the Trust Units, so long as stabilizing bids do not exceed a specified maximum.

         Stabilization may cause the price of the Trust Units to be higher than they would be in the absence of such transactions.

         Neither we nor the Dealer Managers make any representation or prediction as to the effect that the transactions described above may have on the price of the Trust Units. If such transactions are commenced, they may be discontinued without notice at any time.

         We have prepared this prospectus only for the distribution of our securities in the United States. We are qualifying the distribution of these securities under the securities legislation of each of the provinces and territories in Canada by way of a Canadian Prospectus for delivery to persons in Canada. This U.S. Prospectus includes certain information that may not be included in the Canadian Prospectus. If you are in Canada, you cannot rely on this prospectus and you should contact Computershare Trust Company of Canada at 100 University Avenue, 9th Floor, Toronto, Ontario, M5J 2Y1, telephone (416) 981-9633, toll free 1-800-564-6253 to request that a copy of the Canadian Prospectus be delivered to you.

         The Subscription Agent will mail certificates representing Trust Units sold pursuant to the Rights Offering as soon as practicable after the Rights Expiry Time to the subscribers thereof at the address of subscribers appearing on the Rights Certificates. See “Details of the Rights Offering”, page 66.

DESCRIPTION OF THE TRUST UNITS AND SPECIAL VOTING UNITS

         PET is authorized to create and issue an unlimited number of Trust Units and an unlimited number of Special Voting Units (defined below). PET is authorized to create, issue, sell and deliver Trust Units, including rights, warrants, special warrants, subscription receipts, instalment receipts, exchangeable securities or other securities to purchase, convert, redeem or exchange into Trust Units or other securities of PET (including debt convertible into Trust Units or other securities of PET), on such terms and conditions as the Administrator may determine. All Trust Units outstanding from time to time are entitled to an equal undivided share of any distributions from PET. In the event that PET ceases to exist or is wound up, each Trust Unit entitles its holder to an equal undivided share in any amounts distributed upon such cessation or winding-up after satisfaction of all liabilities and provision for indemnities. All Trust Units are of the same class with equal rights and privileges. Each Trust Unit is transferable, is fully paid and non-assessable and entitles its holder to one vote at all meetings of Unitholders. The Trust Units do not entitle the Unitholder to any conversion, retraction, redemption or pre-emptive rights, except for the rights referred to under “Description of the Trust Units and Special Voting Units — Redemption Right”, page 90. No fractional Trust Units will be issued or transferred except for the

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purposes of distributions of Trust Units referred to in “Description of the Trust Units and Special Voting Units — Distributions”, page 88.          In order to allow us flexibility in pursuing corporate acquisitions, the PET Trust Indenture allows for the creation and issuance of units with special voting characteristics (the “Special Voting Units”). If and when PET issues Special Voting Units, it will likely be to a trustee for the benefit of the holders of securities which are exchangeable for Trust Units, entitling the trustee to such number of votes at meetings of Unitholders as the Administrator’s board of directors may prescribe. The Special Voting Units will give us the flexibility to acquire the securities of another issuer in exchange for securities that are ultimately exchangeable for Trust Units. The Administrator’s board of directors will set the voting rights or other rights and the terms upon which we issue Special Voting Units. The Special Voting Units will not entitle the holder to any distributions of any nature whatsoever from PET or to any beneficial interest in any of PET’s assets during PET’s existence or upon PET’s termination or winding-up. Presently we have no plans to issue Special Voting Units. To the extent that we issue Special Voting Units, the voting power of existing Unitholders will be reduced.          The legal ownership of the assets of PET and the right to conduct the undertaking of PET (subject to the limitations contained in the PET Trust Indenture) are vested exclusively in the Trustee or such other person as the Trustee determines. The Trust Units are personal property and will confer upon Unitholders only the interest and rights specifically set forth in the PET Trust Indenture. Except as specifically set out in the PET Trust Indenture, no Unitholder has or is deemed to have any right of ownership in any of our assets. Under the PET Trust Indenture material amendments to the PET Trust Indenture affecting the rights of Unitholders would require the approval of Unitholders by a special resolution of at least 662/3% of the votes cast by Unitholders at a validly called meeting of Unitholders. See “The PET Trust Indenture — Meetings and Resolutions of Unitholders”, page 92.          The Trust Units do not represent a traditional investment and you should not view them as “shares” in PET. As a Unitholder, you will not have the statutory rights normally associated with ownership of shares of a corporation including, for example, the right to bring “oppression” or “derivative” actions. We anticipate the market price of the Trust Units will generally be a function of PET’s anticipated distributable income and the Administrator’s ability to effect long-term growth. The market price of the Trust Units will be sensitive to a variety of market conditions including, but not limited to, interest rates, commodity prices and our ability to acquire additional assets. Changes in market conditions may adversely affect the market price of the Trust Units. See “Risk Factors”, page 20.

         The Trust Units are not “deposits” within the meaning of the Canada Deposit Insurance Corporation Act (Canada) and are not insured under the provisions of that act or any other legislation. Furthermore, none of PET, POT or the Administrator is a trust company and, accordingly, none of them are registered under any trust and loan company legislation as they do not carry on, or intend to carry on, the business of a trust company.

PET Unitholder Liability

         The PET Trust Indenture provides that no Unitholder, in its capacity as such, will be subject to any liability to any person:

(a)	in connection with PET’s assets, obligations or affairs; or
(b)	with respect to any act any person performs pursuant to the PET Trust Indenture; or
(c)	with respect to any act or omission of any person in the performance or exercise, or purported performance or exercise, of any obligation, power, discretion or authority conferred under the PET Trust Indenture; or
(d)	with respect to any transaction any person enters into pursuant to the PET Trust Indenture.

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         Furthermore, Unitholders, in their capacities as such, are not contractually liable to indemnify any person for any of the above liabilities, including taxes any person may incur on our behalf. If, however, a court assesses any of such liabilities against a Unitholder, then those liabilities will be enforceable only against and be satisfied only out of the assets of PET. PET will be liable to the Unitholders and indemnify the Unitholders, to the extent of its assets, from liability arising as a result of the Unitholders not having such limited liability. The PET Trust Indenture provides that every written contract we enter into must include a provision substantially to the effect that any obligation created under such contract will not be binding upon Unitholders personally.

         Notwithstanding the terms of the PET Trust Indenture, Unitholders, in their capacities as such, may not have the same protection from PET’s liabilities that a shareholder would have from the liabilities of a corporation. Unitholders may face personal liability for claims against PET, including contract claims, tort claims, environmental claims, claims for taxes and possibly other statutory liabilities. Unlike many other royalty trusts and income funds, our structure does not include the interposition of a limited liability entity such as a corporation or limited partnership which would provide further limited liability protection to Unitholders.

         We intend to conduct our business so as to avoid as far as reasonably possible any material risk of liability to the Unitholders for claims against us. We intend to obtain insurance, where available and appropriate, for the operations of POT and the Administrator. However, the amounts and types of insurance obtained may not be sufficient to provide full coverage.

Distributions

         We will distribute cash to the Unitholders out of the income and other amounts we receive from all royalties payable by any entity to PET, including the POT Royalty (the “Royalties”), indebtedness of POT to PET, our other assets and other investments, less expenses and any other amounts we are permitted to deduct or must withhold or pay to third parties.

         We expect that the material sources of PET’s cash flow will be initially limited to:

(a)	royalty income it receives on the POT Royalty, which comprises, generally, 99% of POT’s net revenue from its petroleum and natural gas properties, less permitted deductions with respect to debt payments, capital expenditures and certain other amounts;
(b)	interest and principal POT pays respecting indebtedness of POT to PET from time to time to finance its operations; and
(c)	trust income POT distributes to PET as its sole beneficiary.

         We expect PET’s expenses will initially be substantially limited to:

(a)	interest, principal and fees paid to its lenders and PRL;
(b)	trustee fees and expenses;
(c)	expenses related to printing and other matters in connection with communicating with and sending distributions to the Unitholders; and
(d)	general and administrative expenses.

         POT may apply some or all of its cash flow to capital expenditures to develop POT’s oil and natural gas properties or to acquire additional oil and natural gas properties. This would effectively reduce the amounts POT pays to PET under the POT Royalty as well as reduce POT’s distributions to PET as its sole beneficiary and PET’s distributions

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to Unitholders. Under the terms of our credit facility, if our lenders determine our borrowing base has been exceeded, we will be precluded from providing distributions on the Trust Units until our borrowing base is no longer in a shortfall position. Our lenders may also restrict our ability to pay distributions in circumstances when we are in breach or default of our agreements with them. See “Bank Financing and Guarantees”, page 65.

         We expect to make an initial distribution of distributable income of PET for the period from •, 2002 to •, 2002 to Unitholders of record on •, 2003 and we expect to pay the distribution on •, 2003. Thereafter, we anticipate that we will pay monthly distributions of cash to the Unitholders of record on the last day of each month. We will pay such cash distributions on the 15th day of each month or, if such day is not a business day, the next following business day. Each Unitholder has the right to enforce payment of any distribution at the time the amount becomes payable. Any of PET’s income (as computed under the Tax Act) or net realized capital gains not otherwise distributed to Unitholders in a calendar year shall, without any further action on the part of the Administrator, be due and payable to Unitholders of record at the close of business on December 31 in each year. Absent a demand from a Unitholder to enforce payment, such amounts will be paid to Unitholders on or before February 15 of the following year. Upon the Administrator’s written direction, the Trustee may change the dates on which we pay distributions, at any time, subject to having given the Unitholders not less than 60 days’ prior written notice. Additionally, upon the Administrator’s written direction, the Trustee may change the record date for the payment of distributions at any time, upon compliance with any requirements of applicable law or the rules of any stock exchange.

         Where:

(a)

between record dates for distributions, we have paid cash in respect of Trust Units tendered for redemption (see “Description of Trust Units and Special Voting Units — Redemption Right”), page 89, we may, on the next distribution date, reduce the cash amount of the aggregate distribution at that time by the cash amount paid for the redemptions and include a distribution to Unitholders of additional Trust Units in place of that amount; and

(b)

we determine we do not have sufficient cash to pay the full distribution to be made on a distribution date (or on any other date on which any other distribution is payable under the PET Trust Indenture), or if any cash distribution would be contrary to, or would not allow the Trustee to comply with, our credit facilities, the distribution may, at the option of the Administrator, include a distribution to Unitholders of additional Trust Units having a value equal to the cash shortfall and the amount of cash distributed will be reduced by the cash shortfall.

         After any such distribution we may consolidate the Trust Units so that each Unitholder has the same number of Trust Units as they held immediately prior to such distribution except where tax is required to be withheld in respect of the Unitholder’s share of the distribution. The value of such additional Trust Units will be based on the closing trading price thereof on the principal stock exchange on which they are listed on the applicable distribution date or otherwise as the Trustee determines. The net effect of the foregoing is that Unitholders would not receive all or a portion of the cash which would have been distributed to them, with no corresponding increase in their ownership percentage in PET. Where amounts so distributed represent income, Unitholders who are neither resident nor deemed to be resident in Canada for the purposes of the Tax Act, including any Unitholder that is a partnership, any member of which is neither resident nor deemed to be resident in Canada for the purposes of the Tax Act (“Non-Resident Unitholders”), will be subject to withholding tax and the consolidation will not result in such Non-Resident Unitholders holding the same number of Trust Units. Such Non-Resident Unitholders will be required to surrender the certificates (if any) representing their original Trust Units in exchange for a certificate respecting their post-consolidation Trust Units.

         The PET Trust Indenture provides that the Trustee may deduct or withhold from any amounts payable to Unitholders, including payments or deliveries due to Unitholders who have exercised redemption rights, amounts required by law to be withheld from those payments. If withholding is required on any distributions (including distributions of Trust Units) or redemption amounts and the Trustee is or was unable to withhold, or otherwise did not withhold, taxes from a particular payment, the Trustee is permitted to withhold the applicable amounts from other distributions to the

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Unitholder or sell such number of Trust Units being distributed to Unitholders as are necessary to satisfy the Trustee’s withholding tax obligations with respect to the Unitholder and all of the Trustee’s reasonable expenses with respect thereto.

Redemption Right

         Unitholders may redeem their Trust Units at any time by delivering Unit Certificates to the Trustee, together with a properly completed notice requesting redemption in a form acceptable to us. Once we have received all required documents, Unitholders have no rights with respect to the Trust Units tendered for redemption, other than a right to receive the redemption amount, which amount per Trust Unit will be the lesser of 90% of the weighted average trading price of the Trust Units on the principal market on which they are traded for the 10 day period after the Trust Units have been validly tendered for redemption and the “closing market price” of the Trust Units. The redemption amount will be payable on the last day of the following calendar month. The “closing market price” will be the closing price of the Trust Units on the principal market on which they are traded on the date on which they were validly tendered for redemption, or, if there was no trade of the Trust Units on that date, the average of the last bid and ask prices of the Trust Units on that date.

         In the event that the aggregate redemption value of Trust Units tendered for redemption in a calendar month exceeds $100,000 and the Administrator does not exercise its discretion to waive such $100,000 limit, we will not use cash to pay the redemption amount for any of the Trust Units tendered for redemption in that month. Instead, we will pay the redemption amount for those Trust Units, subject to compliance with applicable laws and the receipt of all applicable regulatory approvals, by the issuance of promissory notes of PET (referred to in this section as the “Notes”) to the tendering Unitholders on the last day of the next calendar month. The Notes will have an aggregate principal amount equal to the aggregate redemption amount of the Trust Units tendered by the Unitholder for redemption. If applicable laws prevent the issuance of these Notes to a Unitholder, the Trustee will authorize the payment of the redemption amount to that Unitholder in future months. Under the terms of our proposed credit facility, if our lenders determine our borrowing base has been exceeded or we are in breach or default of our agreements with them, we will be precluded from paying cash for redemptions of our Trust Units.

         Notwithstanding the above, if, at the time Trust Units are tendered for redemption:

(a)	in the discretion of the Administrator, the trading price of the Trust Units on the stock exchange on which the Trust Units are listed does not represent the fair market value of the Trust Units; or
(b)	the normal trading of the Trust Units on the stock exchange on which they are listed is suspended or halted on the date the Trust Units are tendered for redemption or for more than five trading days during the ten trading day period after that date;

then the redemption amount for each of those Trust Units will be equal to 90% of the fair market value thereof as determined by the Administrator. We will pay such redemption amount on the last day of the third month following the month in which those Trust Units were tendered for redemption. At the option of PET, we will pay the redemption amount in cash or, subject to compliance with applicable laws, and the receipt of all applicable regulatory approvals, the delivery to the Unitholder of Notes of PET having an aggregate principal amount equal to the aggregate redemption amount of the Trust Units tendered by the Unitholder for redemption.

         The Notes delivered as set out above will be unsecured, bear interest at a market rate of interest to be determined at the time of issuance by the Administrator’s board of directors, based on the advice of an independent financial advisor, with the interest to be payable monthly. The Notes will be subordinated and in certain circumstances postponed to all our indebtedness. Subject to prepayment, the Notes will be due and payable 5 years after issuance.

         The Notes will be issued under and subject to the terms of a note indenture, to be entered into prior to their issuance, which indenture may provide for the issuance of Notes in series or otherwise. The trustee under the note

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indenture will be obligated under an agreement with our lenders to subordinate and in certain circumstances to postpone the payment of such Notes. Such Notes may not be qualified investments for trusts governed by registered retirement savings plans, registered retirement income funds, registered education savings plans and deferred profit savings plans if PET ceases to qualify as a mutual fund trust under the Tax Act or its Trust Units cease to be listed.

         The Trustee has the discretion to designate a portion of any redemption payment to be an income distribution from PET.

         We expect that the redemption right will not be the primary mechanism for holders of Trust Units to dispose of their Trust Units. We will not list the Notes referred to above on any stock exchange and no market will exist for them. The Notes may be subject to resale restrictions under applicable securities laws.

Non-Resident Unitholders

         In order for PET to maintain its status as a mutual fund trust under the Tax Act, PET must not be established or maintained primarily for the benefit of persons who are non-residents of Canada for the purposes of the Tax Act (“Non-Residents”). The PET Trust Indenture contains restrictions on the ownership of Trust Units by Unitholders who are Non-Residents. We may require Unitholders to provide a declaration (a “Residence Declaration”) specifying whether or not they are Non-Residents. If, at any time, the Trustee determines that the beneficial owners of 49% or more of the Trust Units are or may be Non-Residents or that such a situation is imminent, the Trustee may announce publicly such determination. After such determination the Trustee will refuse any subscription or transfer not accompanied by a Residence Declaration confirming Canadian residence. If the Trustee determines that Non-Residents hold a majority of the Trust Units, the Trustee may send a notice to Non-Residents requiring them to sell all or a portion of their Trust Units within 60 days. The Trustee will send notices only to as many Non-Resident Unitholders and with respect to only so many Trust Units as may be reasonably necessary to ensure that the number of Trust Units held by Non-Residents would be reduced, as far as the Trustee is aware, to no greater than 48% of the Trust Units then outstanding. The Trustee will use reasonable commercial efforts to ensure that its actions in this regard will not reduce the number of Trust Units held by Unitholders who are or may be Non-Residents, so far as the Trustee is aware, to less than 40% of the Trust Units outstanding. Following the 60 days, the Trustee may sell Trust Units on the Non-Residents’ behalf unless the Non-Residents provide satisfactory evidence that they are Canadian residents. Until the Trustee sells such Trust Units, the Trustee will suspend the voting and distribution rights associated with those Trust Units. The Trustee will sell the Trust Units on any stock exchange on which the Trust Units are then listed. Such Trust Units will be sold on the basis of an inverse order to the order of acquisition by such Non-Residents until the Trustee, in its sole discretion, determines that the restrictions on ownership imposed on PET are no longer in danger of being violated. The Trustee will pay the net proceeds of such sale to the Non-Resident upon the Non-Resident’s surrender of its Unit Certificate.

THE PET TRUST INDENTURE

         The following information summarizes the material information contained in the PET Trust Indenture. The PET Trust Indenture provides for the governance of PET. While this summary discusses all material information, it is not exhaustive and may not contain all of the information that is important to you. See “Where You Can Find More Information”, page 125.

General

         PET was established for the purposes of issuing Trust Units and acquiring and holding royalties and other investments including the entire beneficial interest in POT and the POT Royalty. See “The PET Trust Indenture — Investment Powers”, page 92.

         Subject to the provisions of applicable law, the PET Trust Indenture contains an acknowledgement that the directors and officers of the Administrator may be engaged directly or indirectly in the oil and gas industry and gas advisory and consulting businesses in Canada and elsewhere. Nothing in the PET Trust Indenture prohibits such persons

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from undertaking such engagements. The PET Trust Indenture specifies that the Administrator is required to disclose to the Trustee any conflict of the interests of such persons with the interests of PET within a reasonable period of time.

         Under Canadian securities legislation, there are reporting obligations placed on persons who acquire more than a certain percentage of the securities of PET. Generally, no obligations are triggered until a threshold of 10% or more of the outstanding class of securities is acquired. The provisions dealing with the reporting obligations are complex and persons approaching such threshold should consult with their professional advisors. We also have provisions restricting non-Canadian ownership of our securities. See “Description of the Trust Units and Special Voting Units — Non-Resident Unitholders”, page 91.

Investment Powers

         Under the PET Trust Indenture, PET has broad powers to invest funds not distributed to Unitholders, including the power:

(a)	to fund POT or any subsidiary of PET to enable them to further develop their oil and natural gas assets or to acquire, directly or indirectly, further hydrocarbon producing assets and facilities of any kind related thereto; and
(b)	to make any other investments of any kind or nature including loan advances to, and acquiring shares and/or beneficial interests in, other entities,

provided that the Administrator has covenanted to use reasonable commercial efforts to ensure that PET does not acquire any investment which:

(i)	is defined as “foreign property” under any provision of the Tax Act if such acquisition would cause the Trust Units to be foreign property under the Tax Act; or
(ii)	would result in PET not being considered either a “unit trust” or a “mutual fund trust” for purposes of the Tax Act at the time such investment was acquired.

Meetings and Resolutions of Unitholders

         Meetings of Unitholders will be called at least annually. By a resolution passed at a meeting of Unitholders by more than 50% of the votes cast (an “Ordinary Resolution”), Unitholders will vote on:

(a)	the appointment of the Trustee;
(b)	the appointment or removal of our auditors; and
(c)	the election or removal of the Administrator’s directors.

         A special resolution of at least 66 2/3% of the votes cast by Unitholders at a validly called meeting (a “Special Resolution”) is necessary for, among other things:

(a)	removal of the Trustee;
(b)	amending the PET Trust Indenture (except as described under “The PET Trust Indenture — Amendments to the PET Trust Indenture”, page 96);
(c)	subdivision or consolidation of the Trust Units (unless otherwise provided for in the PET Trust Indenture — see “Description of the Trust Units and Special Voting Units — Distributions”, page 88);

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(d) sale of all or substantially all of PET’s assets other than:

(i)	a sale to an entity wholly-owned, directly or indirectly, by PET; or
(ii)	a sale pursuant to any enforcement or realization proceedings by any person that has been granted a security interest over all or part of the assets of PET;

(e) assignment, transfer or sale of any Royalty in whole or in part other than:

(i)	a sale to an entity wholly-owned, directly or indirectly, by PET;
(ii)	a sale made in conjunction with the sale of the corresponding interest in the oil and gas properties of POT to which such Royalty relates, subject to necessary approvals of the board of directors of the Administrator and Unitholders, if any, under that Royalty. See “The POT Royalty Agreement — Disposition of Properties”, page 101; or
(iii)	a sale made pursuant to or in connection with any enforcement or realization proceedings of lenders to PET or POT upon security interests granted to them;

(f)	termination or winding-up of the affairs of PET; and
(g)	appointment of an inspector to investigate the Trustee’s performance.

         Meetings of Unitholders shall be held in the City of Calgary, or at such other place as the Trustee designates. In addition to annual meetings, the Trustee may require further meetings, or Unitholders holding not less than 5% of the outstanding Trust Units or the Administrator may requisition a meeting.

         Unitholders may attend and vote at all meetings of Unitholders either in person or by proxy and a proxyholder need not be a Unitholder. A quorum for any meeting shall be two or more persons, present in person or represented by proxy, holding in the aggregate not less than 5% of the votes attaching to all outstanding Trust Units. We will include holders of Special Voting Units for the purposes of calculating a quorum.

The Trustee

         The PET Trust Indenture appoints Computershare Trust Company of Canada as PET’s trustee. The Trustee may exercise all rights, powers and privileges that could be exercised by a beneficial owner of PET’s assets.

         The Trustee’s initial appointment is until the first annual meeting of the Unitholders. The Trustee shall be reappointed or changed at every annual meeting of Unitholders and will continue to hold the office of Trustee until the Unitholders appoint a successor.

         The Trustee may resign from the office on giving not less than 60 days’ notice in writing. The Trustee may be removed by notice in writing delivered by the Administrator to the Trustee at any time the Trustee no longer satisfies the financial or other qualification requirements under the PET Trust Indenture. Such resignation or removal becomes effective upon the acceptance or appointment of a successor trustee. The Trustee, the Administrator or any Unitholder may make application to a court with appropriate jurisdiction to appoint a successor trustee if one has not been put in place within certain time periods as detailed in the PET Trust Indenture.

         We will pay the Trustee fees and reimburse the Trustee for reasonable expenses it incurs in connection with the administration of PET. The Trustee shall have a lien on PET’s assets with priority over the interests of the Unitholders to enforce payment of its fees and these expenses.

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Delegation of Authority, Administration and Trust Governance

         The Trustee may grant or delegate to the Administrator or other persons such power and authority as the Trustee may deem necessary or desirable to perform any of the duties of the Trustee. The Trustee has effectively delegated to the Administrator all significant management, administrative and governance functions pertaining to PET, including matters related to:

(a)	any sale or surrender of any Royalty;
(b)	any demand under, or sale or surrender, of any debt instruments;
(c)	any sale or surrender of any interest that PET holds in POT or in any other entity it controls, directly or indirectly;
(d)	any acquisition or disposition of permitted investments;
(e)	any offering of securities;
(f)	any terms and any amendment to any Royalty Agreement, the POT Trust Indenture and any agreement from time to time entered into between PET and any entity controlled directly or indirectly by PET providing for terms and conditions governing that entity (the “PET Material Agreements”);
(g)	any underwriting agreement;
(h)	any exercise of rights, powers and privileges relating to a response to an offer for Trust Units or for all or substantially all of the assets of PET, or of any its subsidiaries;
(i)	any redemption of Trust Units;
(j)	credit facilities, borrowings, hedging, security for indebtedness (including guarantees) or other agreement to facilitate our borrowing;
(k)	any financial statements and tax filings;
(l)	any compliance with PET’s legal or listing obligations;
(m)	any calculation of distributions; and
(n)	any meetings of Unitholders.

         The Administrator may further delegate the powers and authorities that the Trustee delegated to it under the terms of the PET Trust Indenture.

         The Trustee cannot delegate the following rights, duties and obligations:

(a)	without limiting the duties and obligations of the Transfer Agent, (hereinafter defined), the countersigning, transferring and cancelling of certificates representing Trust Units and the maintenance of registers of Unitholders;
(b)	the payment and delivery of distributions to Unitholders;

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(c)	amending the provisions of the PET Trust Indenture other than making changes or corrections that legal counsel to the Trustee advises are necessary or desirable and are not materially adverse to the interests of the Unitholders or the Administrator;
(d)	waiving the performance or breach of the provisions of the PET Trust Indenture;
(e)	terminating the PET Trust Indenture and the PET Material Agreements; and
(f)	indemnifying the Administrator, any entity PET controls directly or indirectly, and the directors, officers, employees and agents of those entities in connection with services they perform for PET or the Trustee.

Limitations on Liability of the Trustee and the Administrator

         The Trustee, the Administrator and their respective directors, officers, employees and agents shall not be liable to any Unitholder (in its capacity as such), in tort, contract or otherwise, in connection with any matter pertaining to PET including, without limitation:

(a)	any error in judgment;
(b)	any action taken or suffered or omitted to be taken in good faith in reliance on either any document that is prima facie properly executed or any Ordinary Resolution or Special Resolution;
(c)	any dealing with any asset that resulted in the depreciation of or loss to PET;
(d)	any reliance on any evaluation or assessment provided by an appropriately qualified person;
(e)	any reliance in good faith on any communication from the Administrator to the Trustee or from the Trustee to the Administrator as to any matter, fact or opinion; and
(f)	any other action or failure to act.

         The Trustee, the Administrator and any of their respective directors, officers, employees or agents remain liable for their own gross negligence, wilful misconduct or fraud. The PET Trust Indenture provides that, in addition to any other indemnity provided by contract or at law, the Trustee, each of its directors, officers, employees and agents and each of their respective heirs, executors, successors and assigns (collectively in this paragraph, the “indemnified parties”) are to be indemnified out of the assets of PET in respect of all liabilities, losses, costs, charges, damages, penalties and expenses (collectively in this paragraph, the “liabilities”) suffered or incurred in respect of any claims or proceedings that are proposed or commenced against any indemnified party in respect of acting as or on behalf of PET or the Trustee, any act, omission or error in respect of PET or the carrying out of any Trustee’s duties or responsibilities under the PET Trust Indenture (including any such liabilities relating to environmental matters and issues). However, such indemnification will not be applicable to an indemnified party to the extent that any of such liabilities is suffered or incurred as a result of the indemnified party’s own gross negligence, wilful misconduct or fraud.

         The Trustee and its directors, officers, employees and agents have a lien on the assets of PET to enforce payment of the indemnification provided to them. This lien has priority over the interests of Unitholders in PET. The Administrator has a lien to enforce payment of the indemnification provided to it. This lien has priority over the interests of the Unitholders in PET, but will be subordinated and postponed to any security interests granted to lenders of PET. The indemnities to the directors, officers, employees and agents of the Administrator are unsecured obligations and do not constitute a lien on the assets of PET. The Trustee may, however, grant a security interest in the assets of PET to secure any such indemnity obligation to any such person if that person delivers a subordination and postponement satisfactory to the lenders of PET.

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         The PET Trust Indenture provides that, in the exercise of the powers provided to it, the Trustee will be deemed to be acting as trustee of the assets of PET and will not be subject to any personal liability for any liabilities or obligations against or with respect to PET or its assets. The Trustee will have no liability for any matters delegated to or actions taken by the Administrator.

         The PET Trust Indenture does not hold the Administrator or any of its directors, officers, employees or agents or respective successors to the standard of a trustee in respect of matters delegated to the Administrator. The PET Trust Indenture provides that, in addition to any other indemnity provided by contract or at law, the Administrator, each of its directors, officers, employees and agents and each of their respective heirs, executors, successors and assigns (collectively in this paragraph, the “indemnified parties”) are to be indemnified out of the assets of PET in respect of all liabilities, losses, costs, charges, damages, penalties and expenses (collectively in this paragraph, the “liabilities”) suffered or incurred in respect of any claims or proceedings that are proposed or commenced against any indemnified party in respect of acting or not acting in connection with matters delegated to the Administrator, any act, omission or error in respect of PET or the carrying out of any of the matters delegated to the Administrator under the PET Trust Indenture (including any such liabilities relating to environmental matters and issues). However, such indemnification will not be applicable to an indemnified party to the extent that any of such liabilities is suffered or incurred as a result of the indemnified party’s own gross negligence, wilful misconduct or fraud.

         The PET Trust Indenture provides that none of the Unitholders, PET or the Trustee, in their respective capacities, shall have any right of action against the Administrator or any of the directors, officers, employees or agents of the Administrator or any of their respective heirs, executors, successors and assigns, for acts of the Administrator or any of the directors, officers, employees or agents of the Administrator, where such action is based on any allegation that the Administrator or any director, officer, employee or agent of the Administrator was a trustee for, or acting in a fiduciary capacity (or any other basis similar thereto) with respect to, the Unitholders, PET or the Trustee, in their respective capacities as such, in respect of matters delegated to the Administrator under the PET Trust Indenture.

         The PET Trust Indenture provides that the Administrator will have no liability for any matters delegated by it to third persons for the actions of those third persons. The Administrator will be entitled to the indemnities provided to it in respect of that delegation and actions provided the Administrator has monitored the performance of the third party in accordance with the appropriate standard of care.

Expenses of the Administrator

         PET will reimburse the Administrator for reasonable expenditures and costs the Administrator incurs in the management and administration of PET. This reimbursement is not intended to provide the Administrator, directly or indirectly, with any financial gain or loss. The Administrator has agreed that such reimbursement will be only to the extent necessary to reimburse the Administrator for actual costs incurred, including any costs of capital in respect of carrying any such costs, together with any goods and services taxes applicable thereto, until reimbursement. The Administrator has a lien on the assets of PET to enforce payment of the costs and expenses and other amounts PET must pay or reimburse to the Administrator. The Administrator’s lien has priority over the interests of Unitholders, but is subordinated and postponed to any security interests granted to any lender.

Amendments to the PET Trust Indenture

         The Trustee may amend any of the provisions of the PET Trust Indenture at any time, without the consent, approval or ratification of any of the Unitholders or any other person, for the purpose of:

(a)	ensuring that PET will comply with any applicable laws or requirements of any governmental agency or authority of Canada or of any province;
(b)	ensuring that PET will satisfy the provisions of each of subsections 108(2) and 132(6) of the Tax Act as from time to time amended or replaced;

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(c)	ensuring that such additional protection is provided for the interests of Unitholders as the Trustee may consider expedient;
(d)	removing or curing any conflicts or inconsistencies between the provisions of the PET Trust Indenture or any PET Material Agreement, or any applicable law or regulation of any jurisdiction, provided that in the opinion of the Trustee the rights of the Trustee, the Administrator and of the Unitholders are not prejudiced thereby;
(e)	making changes for any other purpose not inconsistent with the terms of the PET Trust Indenture and any agreement between PET and any entity providing for the payment of a royalty to PET, including the POT Royalty Agreement (the “Royalty Agreements”), including curing, correcting or rectifying any ambiguities, defective or inconsistent provisions, errors, mistakes or omissions, provided that in the opinion of the Trustee, the rights of the Trustee, the Administrator and of the Unitholders are not prejudiced thereby; and
(f)	providing for the electronic delivery by PET to the Unitholders (including Special Unitholders) of documents relating to PET (including annual and quarterly reports and financial statements and proxy-related materials) in accordance with applicable law from time to time.

         Notwithstanding any other provision of the PET Trust Indenture, the Trustee may, at any time on or before the date of the execution of the POT Royalty Agreement, amend and/or restate any of the provisions of the PET Trust Indenture, as directed in writing by the Administrator, without the approval of the Unitholders.

Takeover Bids

         The PET Trust Indenture provides that if an offeror makes a takeover bid for the Trust Units and acquires 90% or more of the Trust Units (other than Trust Units held at the date of the takeover bid by or on behalf of the offeror or associates or affiliates of the offeror) the offeror may acquire the Trust Units of Unitholders who did not accept the takeover bid, without the consent or approval of such Unitholders, on the offeror’s terms under the takeover bid.

Termination of PET

         PET will terminate on December 31, 2102. The Unitholders may vote by Special Resolution to terminate PET at an earlier date only if:

(a)	holders of not less than 20% of the issued and outstanding Trust Units request in writing that PET be terminated and a quorum constituted by the holders of not less than 50% of the issued and outstanding Trust Units is present in person or by proxy at the meeting at which the Special Resolution is adopted; or
(b)	the Trust Units have become ineligible for investment by Canadian registered retirement savings plans, registered retirement income funds, registered education savings plans and deferred profit sharing plans.

         Upon the Unitholders’ vote to terminate PET, the Trustee shall commence to wind-up the affairs of PET. The Trustee will sell and convert into money, or otherwise dispose of, the Royalties and other assets in accordance with the directions, if any, of the Unitholders and the Administrator. PET will not be wound-up until the Trustee has disposed of all Royalties and other investments.

         The Trustee will liquidate all of PET’s assets, satisfy or provide for PET’s obligations and then distribute any remaining proceeds to Unitholders. Unitholders must tender their Unit Certificates to receive their share of the proceeds. PET will terminate when the Trustee has disposed of all of PET’s assets and satisfied or provided for all of PET’s obligations. In no event is the winding-up of the affairs of PET to exceed ten years.

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Auditors of PET, Reporting to Unitholders

         PET’s auditors must be an independent recognized firm of chartered accountants with an office in Calgary, Alberta. KPMG LLP, Chartered Accountants, are the first auditors and will hold office until the first annual meeting of Unitholders. Unitholders will appoint auditors at each successive annual meeting. The Trustee, with the approval of the Unitholders, may remove the auditors and appoint new auditors.

         PET will be subject to the continuous disclosure obligations under applicable securities legislation including the obligation to file quarterly and annual financial reports. PET’s year-end will be December 31.

THE POT TRUST INDENTURE

         All of the beneficial interest in POT is held by the Administrator, as the trustee of POT, for the benefit of and on behalf of PET. See “Formation of Trust Structure and Structuring Transactions”, page 29.

Power and Authority of the Administrator as trustee of POT

         The POT Trust Indenture provides the Administrator, as trustee of POT, with the widest possible latitude and discretion in carrying out its rights and duties as trustee of POT, including, the power and capacity to:

(a)	sell, transfer, assign and convey all or any part of POT’s property;
(b)	retain any investments in real or personal property which come into its possession as trustee;
(c)	invest and reinvest any property coming into its hands as trustee in its sole discretion without being limited by any statute covering investments by trustees;
(d)	vote any securities;
(e)	act as the absolute representative of PET in respect of matters pertaining to the administration of the assets of POT;
(f)	invest POT’s property and assets in investments of every nature;
(g)	borrow money from or lend money to any person on such terms and conditions as the Administrator considers appropriate;
(h)	assume debt, and pledge, mortgage or otherwise encumber POT’s properties;
(i)	guarantee, indemnify or act as a surety or become jointly and severally liable with respect to the payment or performance of any indebtedness, liabilities or obligations of any person (including the beneficiary of POT, being PET) and to pledge, mortgage or otherwise encumber POT’s properties (including all legal and beneficial interests therein) in respect of those guarantees, indemnities, suretyships or liabilities;
(j)	join, directly or indirectly, in any syndicate, partnership or joint venture contributing all or part of the properties of POT as the contribution of POT thereto;
(k)	explore, develop, purchase, hold, operate, market and divest petroleum, hydrocarbons, crude bitumen, oil sands, natural gas, coal bed methane, natural gas liquids, related hydrocarbons and any and all other substances producible in association therewith and related facilities and other miscellaneous interests;
(l)	institute, prosecute, and defend any suit, action, arbitration proceeding or other proceeding affecting the Administrator or POT’s properties;

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(m)	engage in rate swap transactions and derivatives for hedging purposes; and
(n)	employ and pay any other person or persons to transact any business or to do any act of any nature in relation to POT’s assets and properties.

         The Administrator may resign as POT’s trustee on giving not less than 30 days’ written notice to PET. PET may remove the Administrator as trustee only on provision of a full release from liability for the Administrator and its directors, officers, employees and agents in respect of the administration of POT, except in respect of gross negligence, fraud or wilful misconduct. In addition, the Administrator shall cease to act as POT’s trustee if it:

(a)	enters into a liquidation, whether compulsory or voluntary, except a voluntary liquidation for the purpose of amalgamation or reconstruction;
(b)	is found not to have the capacity to act as a trustee or is found to be in breach of applicable legislation governing the activities of bodies corporate as trustees; or
(c)	is declared bankrupt or insolvent.

         The Administrator is entitled to charge POT for all expenses the Administrator reasonably incurs in carrying out its duties as trustee. The Administrator will allocate such expenses and other amounts as income or capital on POT’s assets as it sees fit.

POT Beneficiary and PET Unitholder Limited Liability

         The POT Trust Indenture provides that no beneficiary of POT (being PET) nor any of the beneficiaries of such beneficiaries (the Unitholders), in their capacity as such, will incur or be subject to any liability in connection with the assets of POT or the obligations or the affairs of POT, including acts or omissions of the Administrator. In addition, the beneficiary of POT (being PET) and its beneficiaries (being the Unitholders), in their respective capacities as such, are not contractually liable to indemnify any person for any of the above liabilities, including taxes any person may incur on behalf of POT. If, however, a court assesses any of such liabilities against PET, as beneficiary of POT, or any of the Unitholders, then those liabilities will be enforceable only against and be satisfied only out of the assets of POT. POT will indemnify PET, as beneficiary of POT, and the Unitholders, to the extent of POT’s assets, from liability arising as a result of PET or the Unitholders not having such limited liability.

         Every written contract POT enters into, unless otherwise agreed to by the Administrator, must include a provision substantially to the effect that the obligations thereunder will not be personally binding upon the Administrator, or POT’s beneficiary (being PET), including its own beneficiaries, the Unitholders, in their respective capacities as such.

         Notwithstanding the terms of the POT Trust Indenture and the PET Trust Indenture, the beneficiary of POT (being PET) and the Unitholders, in their capacities as such, may not be protected from liabilities of POT to the same extent a shareholder is protected from the liabilities of a corporation. Personal liability may also arise in respect of claims against POT (to the extent that POT does not satisfy claims) including contract claims, tort claims, environmental claims, claims for taxes and certain other statutory liabilities. Unlike many other royalty trusts and income funds our structure does not include the interposition of a limited liability entity such as a corporation or limited partnership which would provide further limited liability protection to Unitholders.

         The Administrator will conduct POT’s business so as to avoid as far as reasonably possible any material risk of liability to POT’s beneficiary (being PET) and the Unitholders, in their respective capacities as such. We intend to obtain insurance where available and appropriate for the operations of POT and the Administrator, however, the amounts and types of insurance we obtain may not be sufficient to provide full coverage.

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Distributions of POT

         POT is required to distribute all of its income for tax purposes each year to PET. If any such distribution or a part thereof is contrary to any credit facility of POT, the Administrator may include in the distribution to PET, a demand subordinated, unsecured promissory note with a face amount equal to the amount of the distribution not permitted to be delivered to PET. Such notes will be subordinated and postponed to liabilities to lenders of POT and to lenders of PET whose obligations have been guaranteed by POT.

Approval Requirements of Beneficiary

         The POT Trust Indenture provides that POT’s beneficiary (being PET) must approve certain matters including:

(a)	the sale of any assets of POT to the Administrator;
(b)	the amendment of any terms of the POT Trust Indenture;
(c)	certain matters relating to the Administrator; and
(d)	the termination of POT.

Limitations of Liability of the Administrator

         The POT Trust Indenture provides the Administrator, in its capacity as POT’s trustee, with similar limitations on its liability to PET, as are provided in the PET Trust Indenture to the Administrator in connection with the powers and authorities delegated to it thereunder. The Administrator, as trustee of POT, is also provided with indemnities similar to that provided in the PET Trust Indenture to the Administrator in connection with the powers and authorities delegated to it thereunder. The POT Trust Indenture provides that the indemnities provided under the POT Trust Indenture are all unsecured claims and do not constitute a lien on the assets of POT. See “The PET Trust Indenture – Limitations on Liability of the Trustee and the Administrator”, page 95.

Prohibited Amendments to POT Trust Indenture

         The POT Trust Indenture prohibits amendments that result in any of the following:

(a)	a change to a discretionary power of any mandatory duty imposed on the Administrator as trustee, unless the Administrator consents; or
(b)	distributions of income or capital of POT among the beneficiaries of POT other than in accordance with the pro rata share of each such beneficiary, unless they otherwise consent.

THE POT ROYALTY AGREEMENT

Grant of Royalty

         Under the POT Royalty Agreement, POT grants the POT Royalty to PET with respect to the Initial Assets, the applicable interest in Additional Assets and all other petroleum and natural gas properties POT may acquire from time to time. Pursuant to the POT Royalty, PET is entitled to receive 99% of POT’s net revenue from its petroleum and natural gas properties, less permitted deductions with respect to debt payments, capital expenditures and certain other amounts.

         The POT Royalty does not constitute an interest in land. PET generally is not entitled to take its share of production in kind or to separately sell or market its share of petroleum substances produced from POT’s petroleum and natural gas properties, but can do so subject to certain conditions in the case of POT’s insolvency.

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Payment of Royalty Income

         The royalty income POT pays to PET pursuant to the POT Royalty Agreement with respect to a particular payment period will be paid in cash on the 15th day (or the next business day if the 15th is not a business day) of the following month. The POT Royalty Agreement allows the board of directors of the Administrator to elect payment periods and they have determined to make distributions on a monthly basis. The POT Royalty Agreement obligates POT to pay all Alberta Crown charges that are not deductible for income tax purposes in respect of its petroleum and natural gas properties and requires PET to reimburse POT for 99% of such charges. At POT’s option, such reimbursement may be set-off against amounts POT is obliged to pay PET under the POT Royalty Agreement.

Deferred Purchase Price Obligation

         The POT Royalty attaches to all petroleum and natural gas properties POT acquires from time to time. In recognition of this feature of the POT Royalty, the POT Royalty Agreement requires PET to make certain royalty purchase payments in addition to the payment made upon the grant of the POT Royalty. These payments are referred to in the POT Royalty Agreement as “Deferred Royalty Purchase Payments” and are generally required in three circumstances. First, when POT acquires petroleum or natural gas properties, PET must pay POT as a Deferred Royalty Purchase Payment, 99% of the intangible cost of such properties that is not financed with indebtedness POT incurs or assumes. Second, when PET raises equity by way of issuing Trust Units, POT may require PET to make a Deferred Royalty Purchase Payment of up to the lesser of the net proceeds of that issuance and 99% of POT’s debt that reasonably relates to petroleum or natural gas properties previously acquired or in respect of which POT has incurred capital expenditures for which PET has not already paid a Deferred Royalty Purchase Payment. Third, POT may require PET to fund, as a Deferred Royalty Purchase Payment, 99% of capital expenditures that POT proposes to incur in respect of the intangible costs associated with petroleum or natural gas properties, to the extent such expenditures are not financed with indebtedness.

         As a result of the Deferred Royalty Purchase Payments and loans that PET will from time to time make to POT, PET will provide POT with 99% of the funding it requires to acquire petroleum and natural gas properties. POT will bear the remaining 1% of the cost of such properties and the entire cost of tangible equipment relating to any such properties utilizing its own working capital or funds it borrows for such purposes.

Acquisition of Properties

         The POT Royalty Agreement permits POT to acquire petroleum or natural gas properties that have a reserve value that is 20% or less of the reserve value of all of POT’s petroleum and natural gas properties without approval of the Administrator’s board of directors. Acquisitions in excess of this amount must be approved by the Administrator’s board of directors. The Administrator’s board of directors may add to or change the foregoing restrictions on the acquisition of such properties.

Disposition of Properties

         The POT Royalty Agreement permits POT to sell tangible and other properties related to its petroleum and natural gas properties and to license geological or other data it has rights to, so long as it acts reasonably and in accordance with prudent oil and gas industry practice. Generally, these properties will not be subject to the POT Royalty.

         The POT Royalty Agreement permits POT to dispose of petroleum and natural gas properties that are subject to the POT Royalty and requires PET to release the POT Royalty with respect to such dispositions provided that three conditions are met: (a) POT is of the reasonable opinion that such sale is in the best interest of PET; (b) if the sale is comprised of assets having a reserve value of 20% or more of the reserve value of all of POT’s petroleum and natural gas properties, the Administrator’s board of directors has approved the sale; and (c) if the sale is comprised of assets having a reserve value of 50% or more of the reserve value of all of POT’s petroleum and natural gas properties, Unitholders have approved the sale by Special Resolution. Notwithstanding the foregoing, the POT Royalty Agreement provides that if our

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lenders act upon their security, they may dispose of our petroleum and natural gas properties and the associated POT Royalty without obtaining the approvals referred to above.

         If POT sells any petroleum or natural gas rights, 99% of the net proceeds of the sale will, subject to the following, be allocated to PET with respect to the POT Royalty, and 1% will be allocated to POT. POT will hold the proceeds of disposition allocated to PET in trust for PET and may either pay such funds to PET, set such funds off against any Deferred Royalty Purchase Payment PET owes to POT, or use such funds to acquire additional properties or maintain and develop existing properties.

Term of POT Royalty Agreement

         The POT Royalty Agreement will continue in force for so long as POT owns any properties that are subject to such agreement, or holds any proceeds of disposition in trust for PET.

Credit Facilities

         POT is authorized to borrow funds and grant security both with respect to its own borrowing and with respect to certain third party obligations it may from time to time guarantee, such as PET’s debts, for the purpose of obtaining the credit necessary to acquire, develop and operate its properties.

THE ADMINISTRATOR

         All of the issued and outstanding shares of the Administrator are held in the name of the Trustee for the benefit of, and on behalf of, PET. The Administrator was formed primarily to act as trustee of POT and to operate, administer and manage the oil and gas business operations POT carries on.

Share Capital of the Administrator

         The share capital of the Administrator consists of an unlimited number of Class A common shares, an unlimited number of Class B common shares and an unlimited number of preferred shares issuable in series with the rights, privileges, conditions and restrictions of such preferred shares as the Administrator’s board of directors determines. As at the date hereof only one Class A common share is outstanding. Such share has been held by the Trustee for and on behalf of PET since June 28, 2002.

Directors and Officers

         Unitholders will vote on the election of directors of the Administrator on an annual basis by instructing the Trustee to cast votes or withhold from voting on the slate of directors proposed by management of the Administrator. None of the constating documents of the Administrator restrict the directors’ ability to vote compensation to themselves or any members of their body provided a regular quorum is present at a meeting of directors. The Administrator’s bylaws grant broad borrowing powers to the board of directors which the board may delegate to any one or more directors or officers of the Administrator. We do not have any mandatory retirement age for members of our board of directors and do not require them to own any Trust Units to be qualified to act as a director. The names, municipalities of residence, present positions with the Administrator and principal occupations during the past five years of the directors and officers of the Administrator are set out in the table below and in the text which follows thereafter:

Name and Municipality			Offices held with
of Residence	Age		the Administrator	Director Since	Principal Occupation
Clayton H. Riddell(4)(11) Calgary, Alberta		65	Chairman of the Board, Chief Executive Officer and Director	June 28, 2002	Chairman of the Board of PRL and Chief Executive Officer of PRL

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Name and Municipality			Offices held with
of Residence	Age		the Administrator	Director Since	Principal Occupation
Susan L. Riddell Rose(3)(10) Calgary, Alberta		37	President, Chief Operating Officer and Director	June 28, 2002	President and Chief Operating Officer of the Administrator
Cameron R. Sebastian Calgary, Alberta		39	Vice-President, Finance and Chief Financial Officer	-	Vice-President, Finance and Chief Financial Officer of the Administrator since June 28, 2002
Gary C. Jackson Calgary, Alberta		48	Vice-President, Land, Legal and Acquisitions	-	Vice-President, Land, Legal and Acquisitions of the Administrator since June 28, 2002
Myra Jones Calgary, Alberta		56	Corporate Secretary	-	Corporate Secretary of the Administrator since June 28, 2002
Kevin Marjoram Calgary, Alberta		46	Vice-President, Operations	-	Vice-President, Operations of the Administrator since July 1, 2002
Donald J. Nelson(1)(3)(4)(7) Calgary, Alberta		54	Director	June 28, 2002	Private Businessman
John W. (Jack) Peltier(1)(2)(3) (7)(12) Calgary, Alberta		62	Director	June 28, 2002	President of Ipperwash Resources Ltd.
Karen A. Genoway(2)(4)(7)(8) Calgary, Alberta		46	Director	June 28, 2002	Vice-President, Land, Onyx Energy Inc.
Howard R. Ward(1)(2)(7)(9) Calgary, Alberta		57	Director	June 28, 2002	Counsel with McCarthy Tetrault LLP, Barristers and Solicitors

Notes:

(1)	Member of the Audit and Reserves Committee.
(2)	Member of the Corporate Governance Committee.
(3)	Member of the Environment Committee.
(4)	Member of the Compensation Committee.
(5)	The Administrator does not have an executive committee.
(6)	The terms of office of all directors of the Administrator will expire on the date of the next annual shareholders’ meeting of the Administrator.
(7)	Mr. Nelson, Mr. Peltier, Ms. Genoway and Mr. Ward are public or outside directors. Outside directors will receive directors’ fees of $10,000 per year plus $1,000 per meeting.
(8)	Ms. Genoway and her spouse collectively own 7,950 PRL Common Shares, entitling them to 1,325 Dividend Units and 3,975 Rights.
(9)	Mr. Ward beneficially owns 2,000 PRL Common Shares, entitling him to 333 Dividend Units and 999 Rights.
(10)	Ms. Riddell Rose and her spouse collectively own 110,311 PRL Common Shares, entitling them to 18,385 Dividend Units and 55,155 Rights.

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(11)	Mr. Riddell owns 87,000 PRL Common Shares in his registered retirement savings plan and exercises control over an additional 28,856,770 PRL Common Shares through his control of POG, entitling him to an aggregate of 4,823,961 Dividend Units and 14,471,883 Rights.
(12)	Mr. Peltier and his spouse collectively own 12,000 PRL Common Shares, entitling them to 2,000 Dividend Units and 6,000 Rights.

         Assuming no PRL stock options are exercised, after the payment of the Dividend, the directors and officers of the Administrator, as a group, will beneficially own, directly or indirectly, or exercise control or direction over, including through POG and its subsidiaries, an aggregate 4,840,859 Trust Units representing 48.85% of the then outstanding Trust Units. The directors and officers will also receive Rights pursuant to the Rights Offering and they have advised that it is their intention to acquire all Trust Units available to them under the Initial Subscription Privilege. Such persons may also subscribe under the Additional Subscription Privilege. As a result of the above stated intentions, unless all Rights issued pursuant to the Rights Offering are exercised, the percentage of the outstanding Trust Units owned directly or indirectly by the directors and officers of the Administrator as a group, will increase as a result of the Rights Offering. If these persons acquire additional Trust Units by exercising their Additional Subscription Privilege, this would further increase their percentage interest ownership of PET. See “Details of the Rights Offering — Intentions of Insiders and Others to Exercise Rights”, page 69 and “Principal Holders of Securities”, page 109.

         The following is a brief description of the background of each of the Administrator’s senior officers and directors:

Clayton H. Riddell, Chairman, Chief Executive Officer and Director

         Clayton H. Riddell graduated from the University of Manitoba with a Bachelor of Science, Honours Degree in Geology. Mr. Riddell has been the Chairman of the Board and Chief Executive Officer of PRL since 1978. Until June 20, 2002 he was also the President of PRL. Mr. Riddell is a member of the Association of Professional Engineers, Geologists and Geophysicists of Alberta, the Canadian Association of Petroleum Producers, the Canadian Society of Petroleum Geologists, the Independent Petroleum Association of Canada, the American Association of Petroleum Geologists and the Canadian Geoscience Council. Mr. Riddell is or has been a director of the following publicly traded entities during the periods indicated: Newalta Corporation (July 1988 – present); Berkley Petroleum Corp. (1993 – March 2001); and Big Rock Brewery Ltd. (March 2001 – present). Mr. Riddell is the father of Ms. Susan L. Riddell Rose.

Susan L. Riddell Rose, President, Chief Operating Officer and Director

         Susan L. Riddell Rose graduated from Queen’s University, Kingston, Ontario with a Bachelor of Science in Geological Engineering (1986). Ms. Riddell Rose has been the President and Chief Operating Officer of the Administrator since June 28, 2002. From 1990 until June of 2002 she was employed by PRL culminating in the position of Corporate Operating Officer. Prior thereto she was a geological engineer with Shell Canada Limited. She has been a director of PRL since 2000. She is a member of the Association of Professional Engineers, Geologists and Geophysicists of Alberta, the Canadian Society of Petroleum Geologists and the American Association of Petroleum Geologists. Ms. Riddell Rose is the daughter of Mr. Clayton H. Riddell.

Cameron R. Sebastian, Vice-President, Finance and Chief Financial Officer

         Cameron R. Sebastian graduated in 1986 from the University of Calgary with a Bachelor of Commerce. Mr. Sebastian has been Vice-President, Finance and Chief Financial Officer of the Administrator since June 28, 2002. Prior thereto he was Vice-President, Finance of Summit Resources Limited from June 2000 to June 2002. Prior thereto he was Vice-President, Finance of Pursuit Resources Corp. (an oil and gas exploration and development company) from March 1997 to April 2000. Prior thereto, he was controller of Summit Resources Limited from December 1994 to March 1997. Mr. Sebastian is a member of the Canadian and Alberta Institutes of Chartered Accountants, the Canadian Petroleum Tax Society and the Treasury Management Association of Canada.

Gary C. Jackson, Vice-President Land, Legal and Acquisitions

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         Gary C. Jackson graduated in 1977 from the University of Calgary with a Bachelor of Arts in Economics and Commerce. Mr. Jackson has been the Vice-President, Land, Legal and Acquisitions of the Administrator since June 28, 2002. Prior thereto he was Vice-President, Land of Summit Resources Limited from May 2000 to June 28, 2002. Prior thereto, he was Manager of Acquisitions and Divestitures, Joint Venture – Midstream and Land Services at Petro-Canada Oil and Gas (an oil and gas exploration and development company) from October 1996 to May 2000. Mr. Jackson is a member of the Canadian Association of Petroleum Landmen and the Petroleum Acquisition and Disposition Association.

Myra Jones, Corporate Secretary

         Ms. Jones has been corporate secretary of the Administrator since June 28, 2002. From October of 1987 to June of 2002 she was corporate secretary for Summit Resources Limited (an oil and gas exploration and development company).

Kevin Marjoram, Vice-President of Operations

         Mr. Marjoram graduated from the University of Calgary with a Bachelor of Science Degree in Chemical Engineering in 1983. Mr. Marjoram has been the Vice-President of Operations of the Administrator since July 1, 2002. Prior thereto he was Area Engineering Manager, N.E. Alberta – West Side for PRL from July 2000 to June 2002. Prior thereto he held positions in an operations managerial capacity for Spire Energy Ltd. and Northrock Resources Ltd. (both public oil and gas companies). Mr. Marjoram is a member of the Association of Professional Engineers, Geologists and Geophysicists of Alberta.

John W. (Jack) Peltier, Director

         Mr. Peltier graduated from the Royal Military College of Canada with a Bachelor of Science degree and Queen’s University at Kingston with an M.B.A. Mr. Peltier received his Chartered Financial Analyst designation in 1974 and is a member of the Association for Investment Management and Research. Since 1978 he has been President of Ipperwash Resources Ltd. and predecessor companies, a private company providing management and financial consulting services. From March 2001 he was a trustee and, most recently, Chairman of the Board of Trustees of Request Income Trust until its acquisition by Pulse Data Inc. in January 2002. From 1986 to June 2001 he was a member and, most recently, Chairman of the board of directors of Enermark Inc. and concurrently of the Board of Trustees of Enermark Income Fund. From May 2000 to June 2001 he was a member of the board of directors of Enerplus Resources Corporation, and concurrently a member of the Board of Trustees of Enerplus Resources Fund. The aforementioned entities merged to continue as Enerplus Resources Fund in June 2001. Mr. Peltier was Chief Financial Officer of Thunder Energy Ltd. from October 1995 to September 2000 where he has been a director from October 1995 to present. From July 1995 to October 1996 he was the Chief Financial Officer of Bow Valley Energy Ltd. where he was a director from 1996 to February 2002. In the past 5 years Mr. Peltier has held numerous directorships in public entities in addition to those described above as follows: Belfast Petroleum Ltd., director (1995 to July 1999); Courage Energy Inc., director (November 2000 to July 2001); Westbrook Energy Corporation, director (November 1997 to October 1999); Manhattan Resources Ltd. (acquirer of Westbrook Energy Corporation), director (October 2001 to present); and Highridge Exploration Inc., director (June 1995 to July 1999). Mr. Peltier is a member of the Investment Committee of The Calgary Foundation. Mr. Peltier was a director and president of a publicly traded company, Granisko Resources Inc., from April 3, 1995 to August 11, 1995, having been appointed under a management services contract, which included indemnification provisions, as operational manager (with the approval of Granisko’s major creditor). He was appointed by a special investigative committee of Granisko’s board of directors established by Granisko’s major creditor after the occurrence of defaults under Granisko’s loan agreements. Before debt restructuring could be approved by shareholders, additional defaults occurred and the major creditor took steps to have a court of competent jurisdiction appoint a receiver/manager. Mr. Peltier resigned on August 11, 1995, the same date the receiver/manager was appointed. A cease trade order respecting the securities of Granisko was subsequently issued by the securities regulatory authorities.

Donald J. Nelson, Director

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         Mr. Nelson holds a diploma in Computer Technology from the Southern Alberta Institute of Technology, Calgary, Alberta (1969) and graduated from Notre Dame University, Nelson, British Columbia with a Bachelor of Science degree in Mathematics (1972). He is currently a private businessman. Mr. Nelson was with Summit Resources Limited from July 1996 until its acquisition by PRL in June of 2002, where he held the position of Vice-President Operations from July 1996 to September 1998 and President and Director from September 1998 to June of 2002. He is a member of the Association of Professional Engineers, Geologists and Geophysicists of Alberta and of the Society of Petroleum Engineers.

Karen A. Genoway, Director

         Karen Genoway is a professional landman (an individual who is responsible for the acquisition, administration and disposition of mineral or surface rights and who on a voluntary basis, has achieved such designation from the Canadian Association of Petroleum Landmen through a combination of qualifying experience, academic achievement and the successful completion of an examination) with over 23 years experience in the oil and natural gas industry. Previously, she has held the position of Land Manager for Strand Oil & Gas Ltd., and more recently, held the position of Senior Vice-President within the Enerplus Group of Companies. She was with these firms for 8 and 13 years respectively. Currently, she is the Vice-President, Land for the private company Onyx Energy Inc. From February 2001 to January 2002, she was Vice-President of Request Management Inc., manager of Request Income Trust. She is also an active member of The Canadian Association of Petroleum Land Administration, The Petroleum Joint Venture Association, The Petroleum Acquisition and Divestment Association as well as The Canadian Association of Petroleum Landmen, an organization in which she previously acted as a director. Ms. Genoway is also currently a director of Kale Investments Inc., Onyx Energy Inc. and Onyx Oil & Gas Ltd., each of which is a private company.

Howard R. Ward, Director

         Mr. Ward holds a Bachelor of Arts Degree (1967) and a Bachelor of Law Degree (1969) from the University of New Brunswick. He has been a member of the Law Society of Alberta since 1975 and is a member of the Canadian Bar Association and the Calgary Bar Association. From 1978 to 2000 he was a partner of Burstall Ward, Barristers and Solicitors. From 2000 to June of 2002 he was counsel with Donahue & Partners LLP. He was an independent member of the Power Pool Council and Market Surveillance Administrator for the Power Pool of Alberta. He is or has been a director of the following publicly traded entities during the time frames indicated: Blue Sky Resources Ltd., director (July 1999 to July 2000); Cabre Exploration Ltd., director (June 1981 to December 2000); Jet Energy Corp., director (August 1995 to November 1999); Kacee Exploration Inc. (Questar Exploration), director (May 1993 to December 1997); Fibre-Klad Industries Ltd., director (November 1992 to May 1994); and Tuscany Resources Ltd., director (October 1997 to October 2001).

         Each of the senior officers listed above, other than Mr. Riddell propose to devote their full time efforts to POT, PET and the Administrator. Mr. Riddell will remain the Chairman of the Board and President of PRL. Mr. Riddell anticipates devoting approximately 50% of his business time on efforts pertaining to POT, PET and the Administrator. Ms. Riddell Rose is currently on a maternity leave of absence and plans to return to full time employment in December 2002. Mr. Riddell will assume the role of acting President and Chief Operating Officer during Ms. Riddell Rose’s absence.

The Audit and Compensation Committees

         We have established a mandate for our Audit Committee which requires them to adhere to certain standards. The Audit Committee shall consist of not less than two outside directors and is responsible for, among other things, the review of the financial statements of both PET and POT, for the monitoring and proper selection of accounting principles and practices and the review of internal controls. It is required to report to the board of directors of the Administrator on a regular basis. The Audit Committee currently consists of Donald J. Nelson, John W. Peltier and Howard R. Ward, each of whom is an outside director.

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         Our Compensation Committee shall be comprised of three members. The Compensation Committee is responsible for reviewing salaries, employee benefits and incentive compensation for the employees of the Administrator including the President and Vice-President and making recommendations to the board of directors in respect of all compensation issues. Once in each fiscal year, the Committee will review with the President the performance, development and succession of management of the Corporation. The Compensation Committee currently consists of Clayton H. Riddell, Donald J. Nelson and Karen A. Genoway. Under the ABCA, a director of the Administrator is entitled to vote on any contract relating primarily to his or her compensation.

Employees

         On August 1, 2002, the Administrator retained approximately 85 full and part-time employees, some of which have come from PRL and some of which have come from Summit, for the purposes of operating POT’s oil and gas operations. We will reimburse PRL for the services of any PRL employees for the month of July, 2002. Our employees will also render services to the Trustee and PET. Our employees consist of approximately 55 field employees and approximately 30 office personnel, and we expect to have approximately 19 independent contractors. Concurrent with retention of these employees we entered into an agreement (the “Administrative Services Agreement”) with PRL under which PRL provides to POT certain administrative, financial, accounting, land management, engineering and other technical services for a transitional period to end on April 1, 2003 and the Administrator on POT’s behalf provides to PRL certain administrative, financial, accounting, land management, engineering and other technical services relating to the Initial Assets and the Additional Assets and the business and affairs of PRL for a transitional period to end on April 1, 2003. POT will reimburse PRL, and PRL will reimburse POT, for the reasonable expenditures and costs that either incur in rendering such services, including general and administrative costs and expenses. Neither party will charge fees over and above such costs and expenditures. The technical staff at PRL who have been responsible for managing the Initial Assets and Additional Assets for a number of years are employed by the Administrator for and on behalf of POT and will be responsible for the ongoing management of these properties on behalf of POT. The continuity of this technical team should ensure the continued efficient exploitation of our asset base.

Executive Compensation

         We have employment agreements with the following executive officers:

Susan L. Riddell Rose, President and Chief Operating Officer

• annual compensation (including allowances) — $225,000

• Unit Incentive Rights – 200,000 Incentive Rights

• reviewable annually

Clayton H. Riddell, Chairman, Chief Executive Officer

• annual compensation (including allowances) — $175,000

• Unit Incentive Rights – 200,000 Incentive Rights

• reviewable annually

Cameron R. Sebastian, Vice-President, Finance and Chief Financial Officer

• annual compensation (including allowances) — $180,648

• Unit Incentive Rights – 80,000 Incentive Rights

• retention bonus payable on or after December 31, 2002 — $50,000

• reviewable annually

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Gary C. Jackson, Vice-President, Land, Legal and Acquisitions

• annual compensation (including allowances) – $183,561

• Unit Incentive Rights – 100,000 Incentive Rights

• reviewable annually

• right to terminate in favor of employee upon written notice on or prior to February 1, 2003 which will obligate us to make a lump sum payment of $123,000 less applicable taxes and to extend 6 months of benefits coverage

• termination payment, in the event of termination without cause, material reduction in salary, benefits or status of employee or POG selling more than 60% of its Trust Units, equal to the greater of one and one-half year’s salary and benefits or industry standard severance compensation

Kevin Marjoram, Vice-President, Operations

• annual compensation (including allowances) – $139,000

• Unit Incentive Rights – 80,000 Incentive Rights

• reviewable annually

UNIT INCENTIVE PLAN

         Subject to regulatory approval, PET has adopted a unit incentive plan (the “Unit Incentive Plan”) which permits the Administrator’s board of directors to grant non-transferable rights to purchase Trust Units (“Incentive Rights”) to our employees, officers, directors and other service providers. The purpose of the Unit Incentive Plan is to provide an effective long term incentive to eligible participants and to reward them on the basis of our long term performance and distributions.

         The Administrator’s board of directors will administer the Unit Incentive Plan and determine participants in the Unit Incentive Plan, numbers of Incentive Rights we grant and the terms of vesting of Incentive Rights. The grant price of the Incentive Rights (the “Grant Price”) shall be equal to the per Trust Unit closing price on the trading date immediately preceding the date of grant, unless otherwise permitted. The holder of the Incentive Rights may elect to reduce the strike price of the Incentive Rights (the “Strike Price”). Upon such election the Administrator would reduce the Strike Price by deducting from the Grant Price the aggregate amounts of all distributions on a per Trust Unit basis that PET pays Unitholders after the date of grant which represent a return of more than 2.5% per quarter on PET’s consolidated net fixed assets on its balance sheet at each calendar quarter end. We will adjust on a quarterly basis and in no case may the Strike Price be less than $0.001 per Trust Unit. For example if PET distributes a return of 3% in a quarter on PET’s consolidated net fixed assets at that quarter end, the Strike Price may be reduced by 0.5% (3% minus 2.5%) of PET’s per Trust Unit value determined at that quarter end by dividing PET’s consolidated net fixed assets by the number of Trust Units then outstanding.

         Incentive Rights are exercisable for a maximum of 10 years from the date of the grant thereof and are subject to early termination upon the holder ceasing to be an eligible participant, or upon the death of the holder. In the case of early termination, a holder is entitled, from the date the holder ceased to be an eligible participant to the earlier of 60 days and the end of the exercise period, to exercise vested Incentive Rights. The holder may exercise such Incentive Rights at the Strike Price in effect at the time the holder ceased to be an eligible participant. In the case of death, the estate of the holder is entitled, from the date of death to the earlier of 6 months and the end of the exercise period, to exercise vested Incentive Rights at the Strike Price in effect at the date of death. Incentive Rights not vested at the date of termination of the holder or at date of the holder’s death are immediately null and void.

         Subject to applicable regulatory approval, we have reserved 3,963,906 Trust Units for issuance under the Unit Incentive Plan, or such lesser number of Trust Units equal to 10% of the number of Trust Units outstanding following the closing of the Rights Offering. We may only increase the number of Trust Units reserved for issuance under the Unit Incentive Plan with the Unitholders’ approval and any necessary regulatory approval. The Unit Incentive Plan contains provisions for adjustments to the number of Trust Units issuable thereunder and the Strike Price therefor in the event of a subdivision, consolidation, reclassification or change to the Trust Units. The Unit Incentive Plan further provides for accelerated vesting of Incentive Units if there is a change of control of PET, POT or the Administrator.

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         Prior to payment of the Dividend, we intend to grant Incentive Rights to purchase an aggregate of 970,000 Trust Units at Grant Prices of $5.05 per Trust Unit, expiring 5 years from the date of grant as follows:

Incentive Right Holder	Grant Price		Number of Incentive Rights
C.H. Riddell	$	5.05		200,000
S.L. Riddell Rose	$	5.05		200,000
Gary C. Jackson	$	5.05		100,000
Cameron R. Sebastian	$	5.05		80,000
Kevin Marjoram	$	5.05		80,000
Howard R. Ward	$	5.05		15,000
Karen A. Genoway	$	5.05		15,000
John W. Peltier	$	5.05		15,000
Donald J. Nelson	$	5.05		15,000
All Other Employees	$	5.05		250,000
Total				970,000

DISTRIBUTION REINVESTMENT AND OPTIONAL UNIT PURCHASE PLAN

         Subject to the receipt of certain applicable exemptive relief from the securities commissions in the provinces and territories of Canada, we intend to establish a Distribution Reinvestment and Optional Unit Purchase Plan (the “Plan”). The Plan will only be available to Unitholders who are residents of Canada.

         Upon the implementation of the Plan, eligible Unitholders may, at their option, purchase additional Trust Units (the “DRIP Units”) by directing the Plan Agent (defined below) to apply cash distributions on their existing Trust Units (the “Cash Distributions”) to the purchase of DRIP Units (the “Distribution Reinvestment Option”) or by making optional cash payments (the “Cash Payment Option”). Computershare Trust Company of Canada (the “Plan Agent”) will purchase DRIP Units from our treasury, subject to certain limitations, at a price determined by reference to 95% of average market prices as described in the Plan. Under the Cash Payment Option, a participant may, through the Plan Agent, purchase DRIP Units up to a stipulated maximum dollar amount per month and subject to a minimum amount per remittance. The aggregate number of DRIP Units that may be purchased in any financial year of PET will be limited based on the number of Trust Units issued and outstanding at the start of the financial year. Participants will not have to pay any brokerage fees or service charges in connection with the purchase of DRIP Units.

         We reserve the right to determine the number of DRIP Units available for purchase under the Plan for any distribution payment date. In respect of any distribution payment date, if fulfilling all of the elections under the Plan would result in our exceeding the limitations on the number of DRIP Units issuable under the Plan, then we will accept elections for the purchase of DRIP Units on such distribution payment: (i) first, from participants electing the Distribution Reinvestment Option; and (ii) second, from participants electing the Cash Payment Option. If we are unable to accept all elections in a particular category, then we will prorate purchases of DRIP Units on the applicable distribution payment date among all participants in that category according to the number of DRIP Units they seek to purchase.

PRINCIPAL HOLDERS OF SECURITIES

         As at October 21, 2002, based upon the list maintained by PRL’s transfer agent, 48,066,727 PRL Common Shares (approximately 80.8% of the issued and outstanding PRL Common Shares) are held of record by persons with addresses in Canada. Based upon the same list PRL had 71 shareholders of record in the United States holding an aggregate of 11,388,786 PRL Common Shares (approximately 19.2% of the issued and outstanding PRL Common Shares).          As at October 31, 2002, the directors and senior officers of the Administrator, as a group, beneficially owned, directly and indirectly, or exercised control or direction over, 29,043,231 PRL Common Shares (48.85% of the issued and

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outstanding PRL Common Shares). None of these individuals or entities has control or direction over greater than 5% of the PRL Common Shares with the exception of C.H. Riddell, who directly and indirectly, through POG and its subsidiaries Treherne and 409790, exercises control and direction over 28,943,770 PRL Common Shares (48.68% of the issued and outstanding PRL Common Shares). C.H. Riddell is the controlling shareholder of POG. S.L. Riddell Rose is also a shareholder of POG.

         Following payment of the Dividend, assuming one Dividend Unit will be issued for each six PRL Common Shares, we expect that directors and senior officers of the Administrator as a group will beneficially own, directly or indirectly, or exercise control or direction over 4,840,859 Trust Units (48.85% of PET), including through POG which will exercise control and direction over 4,809,461 Trust Units (48.53% of PET). The principal holders of our Trust Units will not be entitled to any voting rights not generally available to all other holders of our Trust Units. Certain of these persons have indicated their intention to subscribe for Trust Units under the Initial Subscription Privilege. To the extent that all of the Rights are not exercised, and such persons subscribe for additional Trust Units under the Additional Subscription Privilege, they will increase their percentage interest ownership of PET. See “Details of the Dividend”, page 63 and “Details of the Rights Offering – Intentions of Insiders and Others to Exercise Rights”, page 68.

         The following table illustrates the direct and indirect Trust Unit holdings of our officers and directors after the Dividend and based upon various Rights exercise scenarios.

				Number and			Number and			Number and
				percentage of Trust			percentage of Trust			percentage of Trust
	Number and			Units following the			Units following the			Units following the
	percentage of			Dividend and			Dividend and			Dividend and
	Trust Units			assuming the			assuming the			assuming the
	following the			exercise of 50% of			exercise of 75% of			exercise of 100% of			Number of Incentive
	Dividend			the Rights(1)			the Rights(1)			the Rights(1)			Rights(2)
Clayton H. Riddell(3)		4,823,961/48.7	%		19,295,844/77.9	%		19,295,844/59.9	%		19,295,844/48.7	%		200,000
Susan L. Riddell Rose(4)		18,385/0.2	%		73,540/0.3	%		73,540/0.2	%		73,540/0.2	%		200,000
Cameron R. Sebastian		—			—			—			—			80,000
Gary C. Jackson		—			—			—			—			100,000
Myra Jones		—			—			—			—			—
Kevin Marjoram		—			—			—			—			80,000
Donald J. Nelson		—			—			—			—			15,000
John W. Peltier(7)		2,000/0.0	%		8,000/0.0	%		8,000/0.0	%		8,000/0.0	%		15,000
Karen Genoway(5)		1,325/0.0	%		5,300/0.0	%		5,300/0.0	%		5,300/0.0	%		15,000
Howard Ward(6)		333/0.0	%		1,332/0.0	%		1,332/0.0	%		1,332/0.0	%		15,000

Notes:

(1)	Assumes the exercise of all Rights held by directors and officers but excludes Incentive Rights which do not vest until one year after issuance.
(2)	The Incentive Rights vest over l years commencing one year after issuance, are at a Grant Price of $5.05 per Trust Unit and expire 5 years after issuance. At the election of a holder, the Grant Price may be reduced depending upon the achievement of certain performance thresholds by PET. See “Unit Incentive Plan”, page 108.
(3)	Mr. Riddell owns 87,000 PRL Common Shares in his registered retirement savings plan and exercises control over an additional 28,856,770 PRL Common Shares through his control of POG, entitling him to an aggregate of 4,823,961 Dividend Units and 14,471,883 Rights.
(4)	Ms. Riddell Rose and her spouse collectively own 110,311 PRL Common Shares, entitling them to 18,385 Dividend Units and 55,155 Rights.
(5)	Ms. Genoway and her spouse collectively own 7,950 PRL Common Shares, entitling them to 1,325 Dividend Units and 3,975 Rights.
(6)	Mr. Ward beneficially owns 2,000 PRL Common Shares, entitling him to 333 Dividend Units and 999 Rights.

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(7) Mr. Peltier and his spouse collectively own 12,000 PRL Common Shares, entitling them to 2,000 Dividend Units and 6,000 Rights.

         To the knowledge of the directors and officers of the Administrator, the only person or corporation who will beneficially own, directly or indirectly, or exercise control or direction over, Trust Units of PET carrying more than 5% of the voting rights attached to such Trust Units as at the occurrences specified below will be:

				Number of Trust Units
		Number of Trust Units		Held After Rights
		Held After Dividend and		Offering and
Name and Municipality	Type of Ownership/Control	Percentage		Percentage
Paramount Oil & Gas Ltd.(2)(3)(4) Calgary, Alberta	Beneficial (direct and indirect)		4,809,461 (48.53%)	19,237,844(1)(3) (48.53%)
Fidelity Management & Research Company and Fidelity Management Trust Company Boston, Massachusetts USA(5)	Beneficial		892,000 (9.0%)	—(6)

Notes:

(1)	Assumes full subscription under the Initial Subscription Privilege but not under the Additional Subscription Privilege and that one Dividend Unit is issued for each six PRL Common Shares.
(2)	C.H. Riddell exercises control and direction over POG.
(3)	On payment of the Dividend, POG will hold 4,217,195 Trust Units directly, 452,700 Trust Units will be held by POG’s subsidiary 409790 Alberta Ltd. and 139,566 Trust Units will be held by POG’s subsidiary Treherne Resources Ltd.
(4)	C.H. Riddell will hold an additional 14,500 Trust Units in his registered retirement savings plan.
(5)	As at October 16, 2002, Fidelity exercises control through accounts and funds managed by it over 5,352,000 PRL Common Shares which entitles it to 892,000 Trust Units on payment of the Dividend.
(6)	Fidelity has not indicated its intention to subscribe for Trust Units under the Rights Offering.

GOVERNMENT REGULATIONS

         Various levels of government impose extensive controls and regulations on the oil and natural gas industry. Some of the more significant aspects are outlined below.

Regulatory Rulings

         In April of 2001, the AEUB issued an order shutting-in 146 natural gas wells in the Surmont area of northeast Alberta on the basis that natural gas production would likely have a detrimental effect on recovery of the underlying bitumen. PRL owns working interests in 65 of the shut-in wells. The application that resulted in the order was made by another resource company which successfully argued that it would not be in the public interest to put the recovery of bitumen at risk by allowing continued natural gas production. As a result of an agreement subsequently reached among the relevant parties and the Province of Alberta, compensation was paid to the owners of the shut-in wells, including PRL, which received approximately $47 million. None of such shut-in wells is included in the Initial Assets or the Additional Assets. A further hearing (the “Chard/Leismer Hearing”) is currently before the AEUB involving many applications, including one by a bitumen lease holder for the shutting-in of a further 40 natural gas wells in the Chard area of northeast Alberta and three by PRL for approval to produce natural gas from four wells in the Leismer area of northeast Alberta. The AEUB granted an interim order shutting-in 10 of the 40 wells in the Chard area. None of the 10 shut-in wells are included in the Initial Assets or the Additional Assets; however, 18 of the remaining 30 wells and the four wells for which

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PRL is making application are included in the Additional Assets. PRL’s current share of production from the 18 wells is approximately two mmcf/d of natural gas. Revenue from these wells was approximately $4.5 million in the fiscal year ended December 31, 2001 and net earnings from these wells was approximately $3.2 million during the same period. At issue in the Chard/Leismer Hearing is the effect, if any, of natural gas production on production of underlying bitumen. Other issues at the hearing include the appropriate criteria to be used by the AEUB in determining whether to approve future applications to produce natural gas and in determining whether to approve future applications to shut-in existing natural gas wells in northeast Alberta. The Initial Assets and the Additional Assets are all located in northeast Alberta. Depending upon the decision on the Chard/Leismer Hearing and the criteria utilized by the AEUB in reaching its decision, further applications could be made to shut-in production of natural gas overlying bitumen in other areas of northeast Alberta, potentially including production from the Initial Assets and the Additional Assets. In such case, we cannot ensure that POT will be able to negotiate adequate compensation for having to shut-in any such production. This could have a material adverse effect on the amount of income available for distribution to our Unitholders.

The North American Free Trade Agreement

         We are bound by the energy terms of the North American Free Trade Agreement (“NAFTA”), among the governments of Canada, the United States and Mexico. Canada is able to restrict exports or energy resources if the export restrictions do not: (i) reduce the proportion of energy resources exported relative to the total supply of the energy resource (based upon the proportion prevailing in the most recent 36 month period), (ii) impose an export price higher than the domestic price, or (iii) disrupt normal channels of supply. All three countries are prohibited from imposing minimum export or import price requirements. NAFTA contemplates the reduction of Mexican restrictive trade practices in the energy sector and prohibits discriminatory border restrictions and export taxes. NAFTA contemplates a fair implementation of regulatory changes and minimal disruption of contractual arrangements.

Land Tenure

         The governments of the western provinces of Canada own most of the crude oil and natural gas located in such provinces. These provincial governments grant rights to explore for and produce oil and natural gas for varying terms and on conditions set forth in legislation. Oil and natural gas located in such provinces can also be privately owned. Private owners may grant rights to explore for and produce oil and natural gas on negotiated terms.

Royalties and Incentives

         In addition to federal regulation, the province of Alberta has legislation and regulations which govern land tenure, royalties, production rates, environmental protection and other matters. The royalty regime is a significant factor in the profitability of oil and natural gas production. Negotiations between the mineral owner and the lessee determines royalties payable on production from lands other than Crown lands. Government regulation determines Crown royalties which are generally calculated as a percentage of the gross production. The rate of Crown royalties payable depends in part on the prescribed reference prices, well productivity, geographical location, field discovery date, the method of recovery and the type or quality of the petroleum product. The governments of Canada and Alberta have established incentive programs including royalty rate reductions, royalty holidays and tax credits for the purpose of encouraging oil and natural gas exploration or enhanced production projects.

         Regulations made pursuant to the Mines and Minerals Act (Alberta) provide various incentives for exploring and developing oil reserves. Oil produced from horizontal extensions commenced at least five years after the well was originally spud may qualify for a royalty reduction. An “8,000 cubic metre” exemption is available for production from a well that has not produced for a 12 month period, if production is resumed after September 30, 1992 and prior to February 1, 1993, or for a 24 month period if production is resumed after January 31, 1993. Oil produced from pools discovered after September 30, 1992 is generally eligible for a 12 month royalty holiday, subject to a $1,000,000 cap. Royalty reductions apply to oil produced from low productivity wells, enhanced recovery schemes (such as injection wells) and experimental projects.

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         Subject to various incentives, the Alberta Crown reserves a royalty to itself of between 15% and 30% in the case of new gas and between 15% and 35% in the case of old gas, depending upon a prescribed or corporate average reference price. A royalty exemption applies to gas produced from qualifying exploratory gas wells spud or deepened after July 31, 1985 and before June 1, 1988 up to a prescribed maximum amount.

         The ARTC program provides a producer of oil or natural gas from certain properties with a credit against the royalties payable to the Crown. The ARTC program is based on a price-sensitive formula and is a function of the Royalty Tax Credit reference price (“RTCRP”). The Department of Energy sets the value for the RTCRP quarterly based on the oil and gas par prices for the previous quarter. The ARTC rate varies between 75% (when the RTCRP falls below $100 per cubic metre), and 25% (when the RTCRP exceeds $210 per cubic metre). The ARTC rate is currently applied to a maximum of $2,000,000 of Alberta Crown Royalties payable for each producer or associated group of producers. If a property is acquired from a corporation that has claimed the maximum entitlement to ARTC, production from that property will not be eligible for ARTC. Neither the wells currently drilled on the properties comprising the Initial Assets nor the Additional Assets are eligible for ARTC.

Environmental Regulation

         The oil and natural gas industry is subject to environmental regulation pursuant to local, provincial and federal legislation. Environmental legislation provides for restrictions and prohibitions on releases or emissions of various substances produced in association with certain oil and natural gas industry operations. Such legislation can affect the location and operation of wells and other facilities and the extent to which exploration and development is permitted. Such legislation requires that well and facility sites be abandoned and reclaimed to the satisfaction of provincial authorities. A breach of such legislation may result in fines or clean-up orders. The Environmental Protection and Enhancement Act (Alberta) imposes strict environmental standards, stringent compliance, reporting and monitoring obligations and penalties.

CERTAIN CANADIAN FEDERAL INCOME TAX CONSIDERATIONS

         It is the opinion of Felesky Flynn LLP, special Canadian tax counsel to PRL and PET, and Stikeman Elliott, Canadian legal counsel to the Dealer Managers, that the following is a summary of all material Canadian federal income tax considerations generally applicable to PET and to holders of PRL Common Shares who are neither resident in Canada nor deemed to be resident in Canada and who receive Dividend Units and Rights and who, at all relevant times, for the purposes of the Tax Act, deal at arm’s length, and are not affiliated, with PRL or PET. This summary is based on the provisions of the Tax Act in force as of the date hereof, all proposed amendments thereto publicly released by the Minister of Finance (Canada) prior to the date of this prospectus, and counsels’ understanding of the current published administrative and assessing practices of the CCRA. This summary is not exhaustive of all possible Canadian federal income tax considerations. Except for the proposed amendments referred to above, this summary does not take into account or anticipate any changes in law, or in administrative or assessing practices, whether by legislative, governmental or judicial action, nor does it take into account provincial, territorial or foreign income tax legislation or considerations which may differ from the Canadian federal income tax considerations described in this prospectus. No advance income tax ruling has been requested from the CCRA with respect to the transactions described herein.          This summary is of a general nature only and is not intended to be, nor should it be construed to be, legal, business or tax advice to any particular holder. Counsel recommends that holders consult their own tax advisors regarding the income tax considerations applicable to them in their particular circumstances.

Status of PET

         This summary assumes that PET will qualify as a “unit trust” and a “mutual fund trust” within the meaning of the Tax Act at the time the Dividend Units are distributed under the Dividend and at all relevant times thereafter. In order to qualify as a unit trust, Trust Units must have conditions attached thereto that include conditions requiring PET to accept, at the demand of the Unitholders and at prices determined in accordance with the conditions, the surrender of the Trust

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Units. In order to qualify as a mutual fund trust, there must be at least 150 unitholders each of whom owns not less than one “block” of Trust Units having a fair market value of not less than $500. This summary assumes that PET will satisfy this minimum distribution requirement immediately after the time the Dividend Units are distributed, so that it may elect to be deemed to be a mutual fund trust from the date it was established until such time, and that it will continuously satisfy the minimum distribution requirement thereafter. In addition, PET cannot reasonably be considered to be established or maintained primarily for the benefit of non-resident persons. Furthermore, the undertaking of PET must be restricted to the investing of its funds in property (other than real property or an interest in real property), the acquiring, holding, maintaining, improving, leasing or managing of any real property (or interest in real property) that is capital property of PET, or a combination of these activities. This summary assumes that these requirements will be satisfied so that PET will qualify as a mutual fund trust at all relevant times.

         In the event that PET were not to qualify as a mutual fund trust, PET would be required to pay a special tax under Part XII.2 of the Tax Act of, generally, 36% of its “designated income” each year, which would include income from the Royalties and certain taxable capital gains, but would not include interest income. The payment of such tax by PET may have adverse income tax consequences in particular for Unitholders who are neither resident, nor deemed to be resident, in Canada. In addition to other consequences specific to Canadian resident holders, Trust Units would constitute taxable Canadian property if PET were not to qualify as a mutual fund trust, the implications of which are discussed below

Taxation of PET

         PET is subject to taxation in each taxation year on its taxable income for that year including interest and all amounts in respect of the Royalties, 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 will end on December 31 of each year.

         Costs incurred by PET on the issuance of Trust Units 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, pro rated where PET’s taxation year is less than 365 days. 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 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.

Non-Residents of Canada

         The following portion of this summary generally is applicable to a PRL Shareholder who at all relevant times, for the purposes of the Tax Act, is neither resident nor deemed to be resident in Canada, and does not use or hold, and is not deemed to use or hold, Dividend Units, Rights or other Trust Units in connection with carrying on a business in Canada.

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Special rules, which are not discussed herein, may apply to a non-resident that is an insurer carrying on business in Canada and elsewhere.

Dividend-in-Kind

         A non-resident PRL Shareholder who receives Dividend Units as a dividend-in-kind will be considered to have received a taxable dividend equal to the fair market value of the Dividend Units at the time of receipt (the “Dividend Payment Time”). Under the Tax Act, dividends paid or credited to a non-resident are subject to withholding tax at the rate of 25% of the gross amount of the dividends, unless such rate is reduced pursuant to the terms of an applicable income tax convention between Canada and the recipient’s jurisdiction of residence. Residents of the United States generally will be entitled to have the withholding rate reduced to 15%.

         Dividend Units received by a PRL Shareholder (including any Dividend Units sold on the holder’s behalf to pay the withholding tax for which the holder is liable) will have a cost to the holder for the purposes of the Tax Act equal to the fair market value of such Dividend Units at the Dividend Payment Time. A portion of the Dividend Units paid to a non-resident PRL Shareholder will be sold on the non-resident’s behalf in order to pay any withholding tax for which the holder is liable. Such PRL Shareholders will be treated as if they had received the Dividend Units and had disposed of them for the amount received on the sale on such holders’ behalf. Consequently, such holders may realize capital gains or capital losses, as discussed below.

Rights Offering

         The Canadian income tax consequences of the receipt of Rights issued by PET are not certain. However, the CCRA’s administrative position is that where a trust grants an option to acquire units of the trust that are to be issued by the trust there are no income tax consequences to either the trust or the recipient of the option. On the basis of this administrative position, the issuance of Rights to a non-resident holder will not be subject to Canadian withholding tax. No capital gain or loss would be realized by the holder upon the exercise of Rights.

Distributions by PET

         A distribution of income of PET to a Unitholder not resident in Canada will be subject to Canadian withholding tax at a rate of 25%, unless such rate is reduced under the provisions of an income tax convention between Canada and the Unitholder’s jurisdiction of residence. Residents of the United States generally will be entitled to have the rate of withholding reduced to 15% of the amount of any income distribution.

Disposition of Rights or Trust Units

         A non-resident holder will not be subject to tax under the Tax Act in respect of any capital gain realized on a disposition of Rights or of Trust Units (whether on redemption, by virtue of capital distributions in excess of a Unitholder’s adjusted cost base or otherwise) unless the property disposed of constitutes “taxable Canadian property” of the non-resident holder and the non-resident holder is not entitled to relief under an applicable income tax convention. Rights or Trust Units of a holder generally will not be considered to be “taxable Canadian property” unless either: (i) at any time during the 60 month period immediately preceding the disposition of Rights or Trust Units by such holder, not less than 25% of the issued Trust Units were owned by the holder, by persons with whom the holder did not deal at arm’s length or by any combination thereof; or (ii) at the time of disposition, PET is not a “mutual fund trust” as defined in the Tax Act.

         If a non-resident holder disposes of Rights or Trust Units that are taxable Canadian property of the holder, the holder will be required to calculate a capital gain (or capital loss) from that disposition equal to the amount by which the holder’s proceeds of disposition exceed (or are exceeded by) the aggregate of the holder’s adjusted cost base (calculated under the Tax Act) of such Rights or Trust Units, as the case may be, and reasonable disposition costs. Such a non-resident holder will be subject to tax under the Tax Act in respect of any such capital gain (subject to relief under an

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applicable income tax convention between Canada and the holder’s jurisdiction of residence) and will be required to file a Canadian income tax return reporting such disposition. The Canada-U.S. Tax Convention generally would not provide any relief from such tax to holders who are residents of the United States for the purposes of that convention. In addition, if the Rights or Trust Units, as the case may be, are taxable Canadian property as a result of PET not qualifying as a mutual fund trust at the time of the disposition, the non-resident holder would be required to obtain a clearance certificate from the CCRA at the time of, and in respect of, the disposition (which generally would require that the holder pay an amount at that time in respect of the holder’s putative Canadian tax liability), failing which the purchaser would be entitled to withhold an amount in respect of the purchase price.

CERTAIN UNITED STATES FEDERAL INCOME TAX CONSIDERATIONS

         The following discussion summarizes the material U.S. federal income tax consequences of the Dividend and Rights Offering applicable to a U.S. Holder of PRL Common Shares and the ownership and disposition of Trust Units and Rights by a U.S. Holder. This description is based on the United States Internal Revenue Code of 1986, as amended (the “Code”), Treasury regulations promulgated thereunder, and judicial and administrative interpretations thereof, all as in effect on the date hereof and all of which are subject to change either prospectively or retroactively. The tax treatment of a U.S. Holder may vary depending upon his or her particular situation. Certain owners (including persons who acquired PRL Common Shares pursuant to an exercise of employee stock options or rights or otherwise as compensation for the performance of services, banks, insurance companies, tax-exempt organizations, financial institutions, persons whose functional currency is not the United States dollar, persons subject to the alternative minimum tax and broker-dealers) may be subject to special rules not discussed below. The following summary is limited to U.S. Holders who hold PRL Common Shares (and Dividend Units) as “capital assets” within the meaning of the Code at all relevant times. The discussion below does not address the effect of U.S. federal estate and gift tax or any state, local or foreign tax law on an owner of PRL Common Shares or Trust Units.

         You are urged to consult with your own tax advisors as to the particular tax consequences of the Dividend and Rights Offering to you, including the applicability and effect of any state, local or foreign laws, and the effect of possible changes in applicable tax laws.

         For purposes of this summary, a U.S. Holder is a beneficial owner that, for U.S. federal income tax purposes, is:

• an individual who is a citizen or, for U.S. federal income tax purposes, a resident of the United States;

• a partnership or corporation created or organized in or under the laws of the United States or any political subdivision thereof;

• an estate whose income is subject to U.S. federal income tax regardless of its source; or

• a trust if: (1) such trust validly elects to be treated as a United States person, or (2) (a) a court within the United States is able to exercise primary supervision over administration of the trust, and (b) one or more United States persons have the authority to control all substantial decisions of the trust.

Tax Treatment of Dividend and Rights Offering

         In the opinion of Carter, Ledyard & Milburn, special U.S. tax counsel to PRL and PET, the Dividend should qualify for treatment under Section 355 of the Code and the Rights Offering should qualify for treatment under Section 305, or (alternatively) 355, of the Code, and, accordingly:

• A U.S. Holder of PRL Common Shares, Dividend Units, or other Trust Units should not recognize any income, gain or loss for U.S. federal income tax purposes as a result of the Dividend or the Rights Offering, respectively.

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• A U.S. Holder’s aggregate tax basis for his or her PRL Common Shares on which the Dividend Units are distributed should be allocated among such PRL Common Shares and the Dividend Units received by such holder in proportion to their relative fair market values at the Dividend Payment Time. A U.S. Holder’s aggregate tax basis for his or her Dividend Units on which the Rights are distributed should then be allocated among such Dividend Units and the Rights received by such holder in proportion to their relative fair market values on the date of issuance of the Rights. A U.S. Holder’s aggregate tax basis for his or her other Trust Units on which the Rights are distributed should likewise be allocated among such other Trust Units and the Rights received by such holder in proportion to their relative fair market values on the date of issuance of the Rights.

• A U.S. Holder’s holding period for Dividend Units should include the holding period for the PRL Common Shares on which the Dividend is paid. A U.S. Holder’s holding period for the Rights received in respect of Dividend Units should similarly include the holding period for the Dividend Units on which the Rights are issued (which would include the holding period for the PRL Common Shares on which such Dividend Units were distributed). A U.S. Holder’s holding period for the Rights received in respect of other Trust Units should include the holding period for such other Trust Units on which the Rights are issued.

• If any of the Dividend Units that a U.S. Holder is otherwise entitled to receive are sold on such holder’s behalf in order to satisfy Canadian withholding tax obligations, such holder should be treated as having received such Dividend Units and then having sold such Dividend Units. Accordingly, such holder should recognize gain or loss equal to the difference between the proceeds from the sale of those Dividend Units and the portion of the tax basis in such holder’s PRL Common Shares that is allocable to such Dividend Units. Such gain or loss should be capital gain or loss, and a long-term capital gain or loss if such holder has held his or her PRL Common Shares for more than one year at the Dividend Payment Time. See discussion below entitled “Tax Consequences of Holding Trust Units – Sale or Redemption of Trust Units”, page 118.

         The opinion of Carter, Ledyard & Milburn is subject to certain assumptions and the accuracy and completeness of certain factual representations and statements made by PRL and PET, including representations specifically made for purposes of such opinion by officers of PRL and the Administrator. Some of these assumptions and representations concern future events as to which there can be no certainty. If any assumption, representation or statement is incorrect in any material respect, the conclusions reached in the opinion may not apply. However, neither PRL nor PET is aware of any present facts or circumstances that would cause such assumptions, representations or statements to be untrue or incomplete. No ruling has been or will be sought from the Internal Revenue Service with respect to the U.S. federal income tax consequences of the Dividend or the Rights Offering. The opinion of Carter, Ledyard & Milburn represents only its view of existing tax law, as to which there is some uncertainty. Such opinion will not be binding on the Internal Revenue Service and no assurance can be given that the Internal Revenue Service or the courts will agree with Carter, Ledyard & Milburn’s opinion.

         If it should be determined that the Dividend did not qualify for tax-free treatment under Section 355 of the Code, each U.S. Holder of PRL Common Shares would be treated as receiving a distribution in an amount equal to the fair market value of the Dividend Units at the Dividend Payment Time. Any such distribution would be taxed first as a dividend to the extent of such U.S. Holder’s pro rata share of PRL’s current and accumulated earnings and profits, and then as a non-taxable return of capital to the extent of such U.S. Holder’s tax basis in his or her PRL Common Shares, with any remaining amount being taxed as capital gain. A U.S. Holder’s tax basis in the Dividend Units would be equal to the fair market value of the Dividend Units at the Dividend Payment Time. A U.S. Holder’s subsequent receipt of Rights pursuant to the Rights Offering would not be subject to tax. A U.S. Holder’s aggregate tax basis for his or her Dividend Units on which the Rights are distributed would be allocated among such Dividend Units and the Rights received by such holder in proportion to their relative fair market values on the date of issuance of the Rights.

         The Treasury Regulations require each holder of PRL Common Shares who receives Dividend Units pursuant to the Dividend to attach to his or her U.S. federal income tax return for the year in which the Dividend is paid a detailed statement setting forth such data as may be appropriate in order to show the applicability of Section 355 of the Code to the transaction.

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         As further described in the discussion of Certain Canadian Federal Income Tax Considerations (see section entitled “Non-Residents of Canada — Dividend-in-Kind”, page 114), a U.S. Holder will be considered to have received a taxable dividend for Canadian income tax purposes equal to the fair market value of the Dividend Units distributed pursuant to the Dividend at the Dividend Payment Time, and such dividend will be subject to Canadian withholding tax. U.S. Holders of Trust Units generally will have the option of claiming the amount of any Canadian income taxes withheld at source either as a deduction from gross income or as a dollar-for-dollar credit against their U.S. federal income tax liability. The amount of foreign income taxes that may be claimed as a credit in any year is subject to complex limitations and restrictions, the applicability of which must be determined on an individual basis by each U.S. Holder. These limitations include rules that limit foreign tax credits allowable with respect to specific classes of foreign source income to the U.S. federal income taxes otherwise payable with respect to each such class of income. Canadian income taxes withheld upon the Dividend may not be creditable for U.S. federal income tax purposes since the Dividend will not produce any foreign source income for a U.S. Holder of PRL Common Shares if it is tax-free for U.S. federal income tax purposes. A U.S. Holder may in some circumstances deduct (as an itemized deduction) foreign taxes in computing taxable income for the taxable year, but only if such U.S. Holder does not elect to claim a foreign tax credit in respect of any foreign taxes paid by such holder during such year.

Tax Consequences of Holding Trust Units

Classification of PET

         PET will elect to be treated as an association taxable as a corporation for U.S. federal tax purposes. As a corporation for U.S. federal tax purposes, PET would be subject to U.S. corporate tax on its net income attributable to earnings that are effectively connected with a U.S. trade or business. If PET is subject to U.S. corporate tax, it will be required to file a U.S. federal corporate income tax return. It is not anticipated, however, that PET will be engaged in a U.S. trade or business.

Taxation of Cash Distributions from PET

         Subject to the passive foreign investment company rules discussed below, a U.S. Holder of Trust Units will be required to include in gross income as ordinary income the gross amount of any distribution, including any Canadian taxes withheld from the amount paid, to the extent the distribution is paid out of PET’s current or accumulated earnings and profits as determined for U.S. federal income tax purposes. Such dividends will not be eligible for the dividends-received deduction otherwise allowed to U.S. corporations in respect of dividends received from other U.S. corporations.

         To the extent that the amount of any distribution exceeds PET’s current and accumulated earnings and profits, it will be treated first as a tax-free return of the U.S. Holder’s tax basis in his or her Trust Units, to the extent thereof, and then as capital gain.

         Amounts considered to be dividends which are paid in Canadian dollars will be included in the U.S. Holder’s gross income in a U.S. dollar amount calculated by reference to the exchange rate in effect on the day such dividends are received. A U.S. Holder who receives a dividend paid in Canadian dollars and converts Canadian dollars into U.S. dollars at an exchange rate other than the rate in effect on the date of receipt of the dividend may have a foreign currency exchange gain or loss that would be treated as ordinary income or loss. We recommend that U.S. Holders consult their own tax advisors concerning the U.S. tax consequences of acquiring, holding and disposing of Canadian dollars.

         Subject to the limitations described above, U.S. Holders of Trust Units generally will have the option of claiming the amount of any Canadian income taxes withheld at source either as a deduction from gross income or as a dollar-for-dollar credit against their U.S. federal income tax liability. Distributions of current or accumulated earnings and profits generally will be foreign source “passive” income or, in the case of certain holders, “financial services” income for U.S. foreign tax credit purposes.

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Sale or Redemption of Trust Units

         Any sale or redemption (except as described below) of Trust Units, including sales of Trust Units deemed to be received pursuant to the Dividend to pay Canadian withholding taxes thereon, generally will result in the recognition of gain or loss by a U.S. Holder for U.S. federal income tax purposes in an amount equal to the difference between the amount realized on the sale or redemption and the U.S. Holder’s adjusted tax basis in the Trust Units. Subject to the passive foreign investment company rules discussed below, such gain or loss generally will be capital gain or loss and will be long-term capital gain or loss if the Trust Units were held for more than one year (including the carryover, if any, of the holding period for PRL Common Shares) at the time of the sale or redemption. For purposes of the foreign tax credit, any gain that is recognized on the sale or redemption of the Trust Units generally will be U.S. source income, and any losses recognized generally will be applied to reduce U.S. source income. Deduction of capital losses is subject to certain limitations under the Code.

         In the case of a cash basis U.S. Holder who receives Canadian dollars in connection with the sale or redemption of Trust Units, the amount realized will be based on the U.S. dollar value of the Canadian dollars received with respect to the Trust Units as determined on the settlement date, in the case of a sale, or on the date on which the redemption price is paid by PET, in the case of a redemption. A U.S. Holder who receives payment in Canadian dollars and converts Canadian dollars into United States dollars at a conversion rate other than the rate in effect on the settlement date, or the date on which the redemption price is paid by PET, as the case may be, may have a foreign currency exchange gain or loss that would be treated as ordinary income or loss.

         An accrual basis U.S. Holder who receives Canadian dollars in connection with the sale or redemption of Trust Units may elect the same treatment required of cash basis taxpayers with respect to a sale or redemption of Trust Units, provided that the election is applied consistently from year to year. Such election may not be changed without the consent of the Internal Revenue Service. In the event that an accrual basis U.S. Holder does not elect to be treated as a cash basis taxpayer (pursuant to the Treasury regulations applicable to foreign currency transactions), such U.S. Holder may have a foreign currency gain or loss for U.S. federal income tax purposes because of differences in the U.S. dollar value of the currency received on the trade date and the settlement date, or on the date on which notice of redemption is given to PET and the date on which the redemption price is paid by PET, in the case of a redemption. Any such currency gain or loss would be treated as ordinary income or loss and would be in addition to gain or loss, if any, recognized by such U.S. Holder on the sale or disposition of such Trust Units.

         In certain circumstances, amounts received upon redemption of Trust Units may be treated as a dividend, rather than as a payment in exchange for the Trust Units which results in recognition of capital gain or loss, as described above. In these circumstances, the redemption payment would be treated as ordinary dividend income to the extent that such payment is made out of PET’s current or accumulated earnings and profits, as calculated for United States federal income tax purposes. The determination of whether a redemption will be treated as a dividend rather than as payment in exchange for the Trust Units will depend upon whether and to what extent the redemption reduces the U.S. Holder’s percentage stock ownership interest in PET. A redemption will be treated as an exchange of stock that produces a capital gain or loss if the redemption either (1) completely terminates the U.S. Holder’s interest in PET under section 302(b)(3) of the Code, (2) is “substantially disproportionate” with respect to the U.S. Holder under section 302(b)(2) of the Code, or (3) is “not essentially equivalent to a dividend” under section 302(b)(1) of the Code.

         A redemption will completely terminate a U.S. Holder’s interest in PET if, as a result of the redemption, such holder no longer owns any Trust Units, directly or constructively after application of the attribution rules of sections 302(c) and 318 of the Code. A redemption generally will be “substantially disproportionate” with respect to a U.S. Holder if (1) the ratio of the Trust Units owned by such holder (including Trust Units attributed to the holder under sections 302(c) and 318 of the Code) immediately after the redemption to all the Trust Units of PET is less than 80% of the same ratio for the Trust Units owned by the holder immediately before the redemption, and (2) the holder owns less than 50% of the combined voting power of the Trust Units immediately after the redemption. Whether a redemption is “not essentially equivalent to a dividend” with respect to a U.S. Holder will depend upon the holder’s particular circumstances. The Internal Revenue Service has ruled that a redemption of a minority shareholder in a publicly held corporation whose

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relative stock interest is minimal and who exercises no control with respect to corporate affairs is “not essentially equivalent to a dividend” if such shareholder has any reduction in his percentage stock ownership. In determining whether any of the foregoing tests have been satisfied, the U.S. Holder is deemed, under the constructive ownership rules of sections 302(c) and 318 of the Code, to own any Trust Units owned by certain related persons and entities and any Trust Units which the holder or certain related persons and entities have an option to acquire. However, because of the complexities in applying the foregoing rules, we recommend that a U.S. Holder consult with his or her own tax advisor to determine whether in the holder’s own particular case a redemption of Trust Units will be treated as a dividend or as a payment in exchange for the Trust Units.

Passive Foreign Investment Company

         For U.S. federal income tax purposes, PET will be considered a passive foreign investment company (“PFIC”) for any taxable year in which either (1) 75% or more of its gross income is passive income, or (ii) at least 50% of the average value of all of its assets for the taxable year produce or are held for the production of passive income. For this purpose, passive income generally includes dividends, interest, royalties, rents, annuities and the excess of gains over losses from the disposition of assets which produce passive income. Based on PET’s current and projected income, assets and activities, and disregarding the separate existence of POT, PET’s management believes PET would not presently be treated as a PFIC. PET’s status in future years will depend on its assets and activities (and those of POT) in those years. PET’s management has no reason to believe that its assets or activities (and those of POT) will change in a manner that would cause it to be classified as a PFIC, but there can be no assurance that PET will not be considered a PFIC for any taxable year.

         If PET is a PFIC for any taxable year, then, unless a U.S. Holder is eligible to elect and does elect to treat his or her investment in the Trust Units as an investment in a “qualified electing fund” (a “QEF election”) or to “mark-to-market” his or her Trust Units, as described below,

• such U.S. Holder would be required to allocate income recognized upon receiving certain dividends, or gain recognized upon the sale or redemption of Trust Units, ratably over the holder’s entire holding period for such Trust Units,

• the amount allocated to each year during which PET is considered a PFIC other than the year of the dividend payment, or sale or redemption, would be subject to tax at the highest individual or corporate tax rate, as the case may be, and an interest charge would be imposed with respect to the resulting tax liability allocated to each such year, and

• gain recognized upon the sale or redemption of Trust Units would be taxable as ordinary income.

         If a U.S. Holder makes a timely QEF election in respect of its Trust Units, such U.S. Holder would not be subject to the rules described above. Instead, such U.S Holder would be required to include in his or her income for each taxable year his or her pro rata share of PET’s ordinary earnings as ordinary income and his or her pro rata share of PET’s net capital gain as long-term capital gain, whether or not such amounts are actually distributed. However, U.S. Holders would not be eligible to make a QEF election unless PET complied with certain applicable information reporting requirements, and PET has not determined whether it would comply with the accounting, record keeping and reporting requirements necessary for U.S. Holders to make QEF elections should it become a PFIC.

         Alternatively, assuming the Trust Units qualify as “marketable stock” within the meaning of section 1296(e) of the Code, if a U.S. Holder elects to “mark-to-market” his or her Trust Units, such U.S Holder generally would include in income any excess of the fair market value of his or her Trust Units as of the close of each tax year over his or her adjusted basis in the Trust Units. If the fair market value of the Trust Units had depreciated below the U.S. Holder’s adjusted basis as of the close of the tax year, the U.S. Holder generally could deduct the excess of the adjusted basis of the Trust Units over its fair market value at that time. However, such deductions generally would be limited to the “mark-to-market” gains, if any, that the U.S. Holder included in income with respect to such Trust Units in prior years. Income

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recognized and deductions allowed under the “mark-to-market” provisions, as well as any gain or loss on the disposition of Trust Units with respect to which the “mark-to-market” election is made, would be treated as ordinary income or loss.

         If PET is a PFIC for any taxable year, U.S. Holders would be required to file an annual return on IRS Form 8621.

U.S. Taxation of U.S. Tax-Exempt Unitholders

         In the case of Trust Units held by any U.S. tax-exempt organization (“U.S. TEO Unitholder”), including an employee benefit plan which is exempt from U.S. federal income tax under Sections 401(a) and 501(a) of the Code, the U.S. TEO Unitholder generally would not be subject to U.S. federal income tax on income realized from its holding of Trust Units, except to the extent such U.S. TEO Unitholder’s Trust Units constitute “debt-financed property” within the meaning of section 514(b) of the Code. A U.S. TEO Unitholder whose Trust Units constitute debt-financed property will to that extent be subject to U.S. federal income taxation under rules summarized above. We recommend each U.S. TEO Unitholder consider with its tax advisor the possible application of these rules.

Tax Consequences of Holding Rights

Sale or Exchange of Rights

         On the sale or exchange of a Right, a U.S. Holder will recognize gain or loss in an amount equal to the difference between the amount realized upon the sale or exchange and the tax basis of the Right. Subject to the passive foreign investment company rules discussed above, any gain or loss from the sale or exchange will be a capital gain or loss, and will be a long-term capital gain or loss if the holding period for the Right (determined as discussed above) is more than one year.

Expiration of Rights

         If the issuance of Rights pursuant to the Rights Offering is treated as a nontaxable distribution under section 305(a) of the Code, a U.S. Holder would not recognize a loss upon the expiration of Rights without exercise. Instead, the holder’s basis in such Rights would revert to the Trust Units with respect to which the Rights were issued.

         If the issuance of Rights pursuant to the Rights Offering were treated as a nontaxable distribution under section 355 of the Code, a U.S. Holder would recognize a loss upon the expiration of Rights without exercise, in an amount equal to the tax basis of the Rights. Any loss from the expiration would be a capital loss, and will be a long-term capital loss if the holding period for the Rights (determined as discussed above) is more than one year.

Exercise of Rights

         A U.S. Holder will not recognize gain or loss upon exercise of a Right. The tax basis of each Trust Unit acquired upon exercise of a Right will equal the sum of the Rights Exercise Price and the tax basis of the Right exercised. The holding period of any Trust Unit acquired through the exercise of a Right will begin with the date of exercise.

U.S. Information Reporting and Backup Withholding Tax

         United States backup withholding tax and information reporting requirements generally would apply to certain distributions on, and to payments of proceeds from the sale or redemption of, Trust Units made within the United States to a holder of Trust Units, other than distributions or payments to an exempt recipient, including a corporation, a payee that is not a United States person that provides an appropriate certification, and certain other persons. A payor will be required to withhold backup withholding tax from any distributions on, or payment of the proceeds from the sale or redemption of, Trust Units within the United States to a holder other than an exempt recipient, if such holder fails to furnish its correct taxpayer identification number or otherwise fails to comply with, or establish an exemption from, such backup

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withholding tax requirements. The backup withholding tax rate, under current law, is 30% for years 2002 and 2003, 29% for years 2004 and 2005, and 28% for 2006 through 2010.

         Backup withholding tax is not an additional tax. Amounts withheld under the backup withholding tax rules may be credited against a U.S. Holder’s U.S. federal income tax liability, and a U.S. Holder may obtain a refund of any excess amounts withheld under the backup withholding tax rules by filing the appropriate claim for refund with the Internal Revenue Service.

         Any U.S. holder who holds or acquires 10% or more in vote or value of the Trust Units will be subject to certain additional United States information reporting requirements.

RELATIONSHIP BETWEEN PET, POT AND PRL AND THE DEALER MANAGERS AND FINANCIAL ADVISOR

         BMO Nesbitt Burns Inc., CIBC World Markets Inc. and FirstEnergy Capital Corp. are the Dealer Managers for the Rights Offering. Both BMO Nesbitt Burns Inc. and CIBC World Markets Inc. are directly or indirectly subsidiaries of major Canadian chartered banks, both of which are lenders to PRL (“PRL’s lenders”). As referred to below, we have entered into a commitment letter for the establishment of credit facilities with certain lenders including PRL’s lenders for the acquisitions of the Initial Assets and the Additional Assets. In connection with our acquisition of the Initial Assets, we will guarantee a portion of PRL’s indebtedness to PRL’s lenders. PET may be considered a “connected issuer” of BMO Nesbitt Burns Inc. and CIBC World Markets Inc. and POT may be considered a “related issuer” of PET and PRL in connection with the Rights Offering under applicable securities laws. An issuer is a “connected issuer” if a reasonable person would question the independence between the issuer in a distribution and the registrant providing services to that issuer. A person or entity is a “related issuer” of another person or entity if one is an influential securityholder of the other or each is a related issuer of the same third person or entity.          As at November 4, 2002, PRL was indebted to PRL’s lenders in the amount of $540.1 million. PRL has advised us that it is currently in compliance with all material terms of the agreements governing such credit facilities and PRL’s lenders have not waived any material breach of the agreements. The credit facilities are secured by a fixed and floating charge over all of the assets of PRL. Neither the financial position of PRL nor the value of the security under the credit facilities has changed substantially since the establishment of the credit facilities.          We have a commitment letter from our lenders for the provision of a credit facility in the maximum amount of $100,000,000. We will use the available levels of funding under the credit facility and the proceeds from the Rights Offering, assuming the maximum number of Trust Units are subscribed for, to repay the $30,000,000 we will owe to PRL arising from the acquisition of the Initial Assets and to purchase an interest in the Additional Assets. PET is in compliance with all material terms of the commitment letter with our lenders and our lenders have not waived any material breach of the agreements. The credit facility will be secured by first charges over all of our assets. Neither the financial position of PET nor the value of the security to be provided under the credit facility has changed substantially since PET established the credit facility. Pursuant to the Trust Structuring, it is proposed that PET and POT will provide a $20,000,000 guarantee and related guarantee security in respect of the obligations of PRL to PRL’s lenders. PRL’s lenders have advised, provided PRL is not in default under its credit facilities with its lenders, that they will release the guarantee upon the exercise of all the Rights held by or on behalf of POG, 409790 and Treherne, the repayment of the $30,000,000 of debt we will owe to PRL arising from the acquisition of the Initial Assets and the completion of the acquisition of the applicable interest in the Additional Assets. See “Bank Financing and Guarantees”, page 65.          PRL, on behalf of PET, POT, the Administrator and itself, and BMO Nesbitt Burns Inc., on behalf of the Dealer Managers, negotiated the terms and conditions of the Rights Offering. While PRL’s lenders did not have any involvement in this negotiation, we have kept them fully apprised of the significant terms of the Rights Offering. BMO Nesbitt Burns Inc. and CIBC World Markets Inc. will each receive its share of the fees payable to the Soliciting Dealer Group in connection with the Rights Offering. We will pay all or a significant portion of the gross proceeds of the Rights Offering to PRL in accordance with the terms and conditions of the Take-Up Agreement. See “Use of Proceeds”, page 55.

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         Additionally, Scotia Capital Inc. is directly or indirectly a subsidiary of a major Canadian chartered bank which is currently a lender to PRL and will be a lender to us. PRL will also use a portion of the proceeds we pay to them for the Additional Assets to reduce their outstanding indebtedness to such lender. PRL has retained Scotia Capital Inc. as financial advisor to the Special Committee of the board of directors of PRL in connection with this offering.

PROMOTER

         PRL may be considered the promoter of PET in that it took the initiative to found and organize PET, POT and the Administrator. See “Formation of Trust Structure and Proposed Transactions”, page 29.

EXPERTS

         Information appearing in this prospectus regarding the estimated quantities of reserves of the Initial Assets and Additional Assets, the future of net revenues and their present value was prepared by McDaniel & Associates Consultants Ltd., independent oil and gas reservoir engineers of Calgary, Alberta. We have included this information in the prospectus and elsewhere in the registration statement in reliance on the independent engineering evaluation of the Initial Assets and the Additional Assets set forth in a report dated July 10, 2002. As at the date hereof, the principals of McDaniel, as a group, do not beneficially own, directly or indirectly, any PRL Common Shares and will not receive any of the Dividend Units or Rights.

         KPMG LLP, independent Chartered Accountants, 1200, 205 – 5th Avenue S.W., Calgary, Alberta, T2P 4B9 Canada, have audited the Consolidated Balance Sheet of PET as at June 30, 2002 and the PRL’s Northeast Alberta Properties Financial Statements which include the Initial Assets and the Additional Assets expected to be acquired by a trust beneficially owned by PET for each of the years in the three-year period ended December 31, 2001. We have included these financial statements in this prospectus in reliance on KPMG LLP’s reports thereon, given on their authority as experts in accounting and auditing.

CONFLICTS OF INTEREST

         There may be situations in which the interests of our management will conflict with those of the Unitholders. Our management owns oil and natural gas properties that do not form part of the properties held by POT. Our management may also acquire interests in energy-related businesses for its own account and on behalf of persons other than the Unitholders. In addition, C.H. Riddell, the Chairman of the Board, Chief Executive Officer and a director of the Administrator, is also the Chairman of the Board, Chief Executive Officer and a director of PRL. S.L. Riddell Rose, the President and a director of the Administrator, is also a director of PRL. C.H. Riddell is the controlling shareholder of POG and S.L. Riddell Rose is also a shareholder of POG and director of PRL. The C.H. Riddell Family beneficially owns or exercises control or direction over, directly or indirectly, including through POG, 49.77% of the outstanding PRL Common Shares and will upon completion of the Dividend and the Rights Offering constitute the largest Unitholder group. Additionally, some of our directors are directors of other industry participants who might be our competitors. See “The Administrator”, page 102.

         Our management will carry on their activities on behalf of the Unitholders and may at times act in contradiction to or in competition with the interests of the Unitholders when acting on behalf of others. We have executed indemnity agreements with each of the directors and officers of the Administrator containing such terms and conditions as are standard in such agreements.

         In resolving conflicts, management will deal fairly and in good faith with all interested parties. The Administrator’s board of directors will require the facts and substances of any particular conflict be fully disclosed and will use all reasonable efforts to resolve conflicts in a manner that will treat PET or POT, as the case may be, and the other interested party fairly. All of our ongoing and future affiliated transactions will be made or entered into on terms that are no less favourable to us than those that we can obtain from unaffiliated third parties. All ongoing and future

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affiliated transactions and any forgiveness of loans must be approved by a majority of the independent disinterested members of the Administrator’s board of directors.

         We will resolve conflicts between us and our officers and directors, including conflicts relating to corporate opportunities, in accordance with all applicable legislation and on the advice of counsel as required. Under the ABCA a director is entitled to vote on any matter relating to his compensation but is required to disclose to the board any interest in any contract that the Administrator enters into.

         Members of the Administrator’s board of directors may serve as directors or officers of entities which compete with us. We cannot assure that such board members will provide us with opportunities they identify.

INTERESTS OF INSIDERS AND OTHERS IN MATERIAL TRANSACTIONS

         PRL took the initiative in founding and organizing PET, POT and the Administrator and their respective businesses. The Initial Assets and Additional Assets are natural gas properties and associated assets that POT is acquiring from PRL. PET is the sole beneficiary of POT and the sole beneficial shareholder of the Administrator. The Administrator manages PET and is the trustee of POT and is reimbursed for its expenses. POT has granted the POT Royalty to PET of 99% of POT’s net revenue from its petroleum and natural gas properties less certain deductions with respect to debt payments, capital expenditures and certain other amounts. POT retains a 1% residual interest in the net income from its assets. POG beneficially owns directly and indirectly, 48.53% of the outstanding PRL Common Shares and, as a result, upon completion of the Dividend, will own 48.53% of the outstanding Trust Units and will receive the same percentage of Rights pursuant to the Rights Offering. C.H. Riddell, the Chairman of the board of directors and the Chief Executive Officer of both PRL and the Administrator, is the controlling shareholder of POG. S.L. Riddell Rose, a director of PRL and the President, Chief Operating Officer and a director of the Administrator is also a shareholder of POG. Any transactions with PRL, the Administrator, their respective officers and directors or holders of 5% or more of our Trust Units will be on terms no less favorable to us than could be obtained from unaffiliated independent third parties. See “Formation of Trust Structure and Structuring Transactions”, page 29, “Details of the Dividend”, page 64, “Bank Financing and Guarantees”, page 65, “Details of the Rights Offering — Intention of Insiders and Others to Exercise Rights”, page 69, “The POT Royalty Agreement”, page 100 and “The Administrator”, page 102.

LEGAL PROCEEDINGS

         We are not a party to any pending or, to our knowledge, threatened legal proceedings nor are we aware of any claims against us. We are aware of certain regulatory proceedings which may affect the Initial Assets and the Additional Assets currently underway at the AEUB respecting bitumen deposits as described under “Risk Factors”, page 8.

AUDITORS, REGISTRAR AND TRANSFER AGENT

         Our auditors are KPMG LLP, Chartered Accountants, 1200, 205 – 5th Avenue S.W., Calgary, Alberta, T2P 4B9.

         Computershare Trust Company of Canada at its principal office in Calgary, Alberta is the registrar and transfer agent (the “Transfer Agent”) for the Trust Units.

LEGAL MATTERS

         Certain legal matters relating to the validity of the Trust Units and Rights will be passed upon for us by Gowling Lafleur Henderson LLP, 1400, 700–2^nd Street South West, Calgary, Alberta, T2P 4V5 and for the Dealer Managers by Stikeman Elliott, 4300, 888 – 3^rd Street South West, Calgary, Alberta, T2P 5C5. Certain legal matters pertaining to United States securities law will be passed upon for us by Carter, Ledyard & Milburn, 2 Wall Street, New York, New York, 10005 and for the Dealer Managers by White & Case LLP, 1155 Avenue of the Americas, New York, New York, 10036–2787. Carter, Ledyard & Milburn and Stikeman Elliott as well as Felesky Flynn LLP, 3400, 350–7^th Avenue South West, Calgary, Alberta, T2P 3N9 have passed upon certain income tax considerations discussed herein. As of the

124

date hereof, the counsel, partners and associates, as a group, of each of Gowling Lafleur Henderson LLP, Stikeman Elliott, Carter, Ledyard & Milburn , White & Case LLP and Felesky Flynn LLP owned, directly or indirectly, less than 1% of the issued and outstanding PRL Common Shares and will receive less than 1% of the Dividend Units and Rights. As at •, 2002 Scotia Capital Inc. owned directly or indirectly, less than •% of the issued and outstanding PRL Common Shares and will receive less than 1% of the Dividend Units and Rights.

WHERE YOU CAN FIND MORE INFORMATION

         We have filed with the SEC a registration statement on Form F-1 under the Securities Act. This prospectus does not contain all of the information set forth in the registration statement, parts of which have been omitted in accordance with the rules and regulations of the SEC. For further information about us, the Trust Units, the Dividend or the Rights Offering, please refer to the registration statement, which you may inspect, without charge, at the offices of the SEC or www.freeedgar.com, or obtain at prescribed rates from the Public Reference Section of the SEC as the address set forth below.

         Upon completion of the Rights Offering, we will be subject to the informational requirements of the Securities and Exchange Act of 1934, as amended (the “Exchange Act”), as they apply to a foreign private issuer, and will file reports and other information with the SEC. As a foreign private issuer, we will be exempt from the Exchange Act rules regarding the content and furnishing of proxy statements to security holders and rules relating to short swing profits reporting and liability. The reports and other information can be inspected at public reference facilities of the SEC located at Room 1024, Judiciary Plaza, 450 Fifth Street, N.W., Washington, D.C. 20549 and online at www.freeedgar.com. You may also obtain copies of such material from the Public Reference Section of the SEC at Room 1024, Judiciary Plaza, 450 Fifth Street, N.W., Washington, D.C. 20549, at prescribed rates. You may obtain more information concerning the operation of the Public Reference Section of the SEC by calling the SEC at 1-800-SEC-0330 or visiting online at www.sec.org.

         Inquiries relating to the Rights Offering and this prospectus should be addressed to the Subscription Agent:

Computershare Trust Company of Canada
100 University Avenue, 9^th Floor
Toronto, Ontario, M5J 2Y1

Telephone: (416) 981-9633
Toll free: 1-800-564-6253
Email: caregistryinfo@computershare.com

125

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS

Report of KPMG LLP	F-2
Consolidated Balance Sheet as at June 30, 2002	F-3
Notes to Consolidated Balance Sheet	F-4

INDEX TO PARAMOUNT RESOURCES LTD. — NORTHEAST ALBERTA PROPERTIES
FINANCIAL STATEMENTS

Auditors’ Report of KPMG LLP	F-7
Paramount Resources Ltd. — Northeast Properties Financial Statements for the six months ended June 30, 2002 and 2001 (unaudited) and for the years ended December 31, 2001, 2000 and 1999	F-8
Notes to Paramount Resources Ltd. — Northeast Properties Financial Statements	F-11

INDEX TO PRO FORMA FINANCIAL STATEMENTS

Compilation Report of KPMG LLP	F-24
Pro Forma Consolidated Balance Sheet as at June 30, 2002	F-25
Pro Forma Consolidated Statement of Earnings for the Six Months Ended June 30, 2002	F-26
Pro Forma Consolidated Statement of Earnings for the Year Ended December 31, 2002	F-27
Notes to the Pro Forma Financial Statements	F-28

F-1

AUDITORS’ REPORT

To the Trustee of Paramount Energy Trust

We have audited the consolidated balance sheet of Paramount Energy Trust (“PET”) as at June 30, 2002. This consolidated balance sheet is the responsibility of PET’s management. Our responsibility is to express an opinion on this consolidated balance sheet based on our audit.

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

In our opinion, the consolidated balance sheet presents fairly, in all material respects, the financial position of PET as at June 30, 2002 in accordance with Canadian generally accepted accounting principles.

Generally accepted Canadian accounting principles vary in certain significant respects from accounting principles generally accepted in the United States. Application of accounting principles generally accepted in the United States would have affected the consolidated balance sheet as of June 30, 2002, to the extent summarized in the notes to the consolidated balance sheet.

/s/ KPMG LLP

Chartered Accountants
Calgary, Canada
November 4, 2002

F-2

PARAMOUNT ENERGY TRUST
Consolidated Balance Sheet

June 30, 2002
(dollar amounts in Cdn $)

Assets
Cash	$	200
Total Assets	$	200
Liabilities and Equity
Unitholders’ Equity (Note 3 – Authorized unlimited number of Trust Units and Special Voting Units; issued – 1 Trust Unit)	$	200
Total Liability and Equity	$	200

See accompanying notes to consolidated balance sheet.

On behalf of Paramount Energy Trust by Paramount Energy Operating Corp. (as agent and attorney in fact for Computershare Trust Company of Canada, trustee of Paramount Energy Trust)

/s/ Susan L. Riddell Rose	Director
/s/ John W. Peltier	Director

F-3

PARAMOUNT ENERGY TRUST
Notes to Consolidated Balance Sheet

June 30, 2002
(dollar amounts in Cdn $)

1. The Paramount Energy Trust:

         Paramount Energy Trust (“PET”) is an unincorporated trust formed under the laws of the Province of Alberta pursuant to a trust indenture dated June 28, 2002, as amended, and whose trustee is Computershare Trust Company of Canada. The beneficiaries of PET are the holders of the Trust Units of PET (the “Unitholders”). PET was established for the purposes of issuing Trust Units and acquiring and holding royalties and other investments. The consolidated assets of PET consist of cash of $200 held directly and through 100 percent ownership of Paramount Energy Operating Corp. (the “Administrator”) and the ownership of 100 percent of the beneficial interests of Paramount Operating Trust (“POT”). PET will utilize a calendar fiscal year end for financial reporting purposes.

         The Administrator was incorporated primarily to act as trustee of POT. As trustee of POT, the Administrator will hold legal title to the properties and assets of POT on behalf of and for the benefit of POT and will administer, manage and operate the oil and gas business of POT. In addition, the Administrator will provide certain management and administrative services for PET and its trustee pursuant to a delegation of power and authority to it under the PET indenture.

         Subject to and following the issuance of a receipt for a prospectus, PET, POT, the Administrator and Paramount Resources Ltd. (“PRL”) will complete a series of transactions pursuant to which PET, on a consolidated basis, will acquire oil and gas properties and related assets with an estimated value of $301,000,000 from PRL assuming PET raises equity of approximately $150,000,000 from the exercise of rights and obtains bank financing of $100,000,000, as follows:

• PRL will, effective July 1, 2002, sell its interest in certain assets (the “Initial Assets”) to POT for consideration consisting of a promissory note in PRL’s favor of approximately $81,000,000. Interest on the $81,000,000 purchase price will accrue at a rate of 6.5% per annum. At that time, a secured guarantee will be given by both POT and PET in respect of $20,000,000 of PRL’s indebtedness to PRL’s lenders. At the same time PRL and POT will execute the Take-Up Agreement which requires PRL to sell and POT to purchase up to 100 percent of PRL’s interest in certain additional assets (the “Additional Assets”). Assuming the acquisition of 100% of PRL’s interest in the Additional Assets, the purchase price will be approximately $220,000,000. POT will pay a $5,000,000 deposit on the purchase price of these assets through the issuance of a non-interest bearing promissory note;

• POT will, effective July 1, 2002, grant to PET a royalty of 99 percent of the net revenue less permitted deductions with respect to debt payments, capital expenditures and certain other amounts from the Canadian resource properties comprised in the Initial Assets and all after-acquired Canadian resource properties of POT including the Additional Assets described below (the “Royalty”) in exchange for consideration consisting of $64,152,000 to be paid in accordance with an agreement between POT, PET and PRL whereby PET will issue and deliver to PRL a first promissory note in the amount of $30,000,000 and a second promissory note in the amount of $34,152,000. The first promissory note will bear annual interest equal to the prime rate of a major Canadian chartered bank from time to time plus 1.875%. This payment will reduce the amount of indebtedness that POT owes to PRL to approximately $16,848,000, which will be represented by a promissory note that will bear annual interest from the date of issue equal to the prime rate of a major Canadian chartered bank from time to time plus 1.875%. PET will grant a security interest to PRL in PET’s assets as security for its indebtedness under the first promissory note and

F-4

PARAMOUNT ENERGY TRUST
Notes to Consolidated Balance Sheet

June 30, 2002
(dollar amounts in Cdn $)

	POT will grant a guarantee to PRL for such indebtedness and will grant to PRL a security interest over its assets for the guarantee. Because PET is not a party to the sale agreement between PRL and POT for the Initial Assets and PRL is not a party to the royalty agreement between PET and POT for the Royalty, promissory notes were necessary in order to complete the sale agreement as an intermediary step to give title to POT so POT could create the Royalty;
•	PET will issue 6,636,045 Trust Units to PRL in full repayment of the indebtedness under the second promissory note;
•	PET will purchase from PRL the remaining $16,848,000 indebtedness owed by POT to PRL in exchange for the issuance and delivery to PRL of an additional 3,273,721 Trust Units;
•	PRL will, by way of a dividend, distribute all of the PET Trust Units held by PRL, being all 9,909,767 of the Trust Units that PRL will then hold, to the holders of PRL common shares;
•	PET will issue to the holders of the Trust Units distributed by PRL, three rights to subscribe for additional PET Trust Units. Each right will entitle the holder to purchase one additional PET Trust Unit at a subscription price of $5.05 per Trust Unit; and
•	PRL will, effective July 1, 2002, sell to POT up to 100 percent of PRL’s interest in the Additional Assets for an aggregate consideration (assuming the acquisition of 100 percent) of approximately $220,000,000. If all of the rights are exercised, proceeds of $150,132,970 (before issue costs) will be raised under the offering and these proceeds, together with bank financing of $100,000,000 will be used to repay the $30,000,000 promissory note to PRL and to complete the acquisition of the Additional Assets.

2. Basis of Presentation:

         The consolidated balance sheet of PET, together with these accompanying notes, have been prepared in accordance with Canadian generally accepted accounting principles which for purposes of this consolidated opening balance sheet of PET are similar in all material respects with generally accepted accounting principles in the United States.

         The consolidated balance sheet includes the accounts of PET and its wholly-owned subsidiaries.

3. Unitholders’ Equity:

         The authorized capital of PET consists of an unlimited number of Trust Units and an unlimited number of Special Voting Units. At June 30, 2002, one (1) Trust Unit and no Special Voting Units were outstanding.

         In order to qualify as a “unit trust” within the meaning of the Tax Act, the Trust Units must have conditions that require PET to accept, at the demand of the Unitholders and at prices determined in accordance with the conditions, the surrender of the Trust Units. Unitholders may redeem their Trust Units at any time by delivering the unit certificates to the Trustee. The redemption amount per Trust Unit properly delivered to the Trustee will be the lesser of 90% of the weighted average trading price of the Trust Units on the principal market on which they are

F-5

PARAMOUNT ENERGY TRUST
Notes to Consolidated Balance Sheet

June 30, 2002
(dollar amounts in Cdn $)

traded for the 10 day period after the Trust Units have been validly tendered and the “closing market price”. The “closing market price” will be the closing price of the Trust Units on the principal market on which they are traded on the date on which they were validly tendered for redemption, or, if there was no trade of the Trust Units on that date, the average of the last bid and ask prices of the Trust Units on that date.

         In the event that the aggregate redemption value of Trust Units tendered for redemption in a calendar month exceeds $100,000, the administrator of the Trust may elect to pay the redemption amounts by the issue of promissory notes of PET with an aggregate principal amount equal to the aggregate redemption amount. The promissory notes will be unsecured, will bear interest at a market rate to be determined at the time of issuance, and will be due and payable 5 years after the date of issuance.

         The Trust Units are considered to be an equity instrument, even though the issuer has an obligation to redeem it under certain circumstances, because it constitutes a residual claim on equity subordinate to all other interests in the assets of the Trust. The amounts will be recorded as a financial liability, if and when the holder elects to redeem the Trust Units.

         Under US GAAP, the amount included on the balance sheet for unitholders’ equity will be reduced by an amount equal to the redemption value of the units as at the balance sheet date. If the Trust Units are trading at prices at or above the Rights exercise price of $5.05 per unit as at the balance sheet date, substantially all of the amount included in unitholders’ equity will be reclassified as a liability. Accordingly, in future periods the amount recorded for permanent equity will be limited to the excess or deficiency of cumulative earnings over cumulative distributions less the difference between the excess of the redemption value of the units over the amount otherwise recorded. In addition, if the aggregate redemption value of the outstanding Trust Units is in excess of the amount of unitholders equity recorded on the balance sheet, it will be necessary to increase the balance to eliminate the difference with an offsetting entry to permanent equity. The charge during a period will be reflected in computing earnings available to unitholders.

F-6

AUDITORS’ REPORT

To the Trustee of Paramount Energy Trust
And To the Board of Directors of Paramount Resources Ltd.

At the request of the Trustee of Paramount Energy Trust, we have audited the balance sheet of the Paramount Resources Ltd. Northeast Alberta Properties (see note 1 to the financial statements) as at December 31, 2001, 2000 and 1999 and the statements of earnings and changes in investment by Paramount Resources Ltd. and cash flows for each of the years in the three year period ended December 31, 2001. These financial statements are the responsibility of the Administrator of Paramount Energy Trust. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits in accordance with Canadian and United States generally accepted auditing standards. Those standards require that we plan and perform an audit to obtain reasonable assurance whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. In our opinion, these financial statements present fairly, in all material respects, the financial position of the Paramount Resources Ltd. Northeast Alberta Properties as at December 31, 2001, 2000 and 1999 and the results of its operations and cash flows for each of the years in the three-year period ended December 31, 2001 in accordance with Canadian generally accepted accounting principles.

Generally accepted Canadian accounting principles vary in certain significant respects from accounting principles generally accepted in the United States. Application of accounting principles generally accepted in the United States would have affected the financial statements for each of the years in the three-year period ended December 31, 2001 to the extent summarized in the notes to the financial information.

/s/ KPMG LLP
Chartered Accountants
Calgary, Canada
November 4, 2002

F-7

PARAMOUNT RESOURCES LTD. — Northeast Alberta Properties
Balance Sheet
(Cdn$000)
(See note 1: Basis of Presentation)

		June 30			December 31			December 31			December 31
		2002			2001			2000			1999
		(unaudited)
ASSETS
Current Assets
	Accounts receivable	$	11,227		$	11,148		$	31,260		$	10,643
	Prepaid expenses		3,617			4,352			1,655			2,251
	Deferred hedging loss (note 5)		3,449			8,003			—			—
			18,293			23,503			32,915			12,894
Property, plant and equipment
	Petroleum and natural gas properties, at cost		497,828			489,194			443,355			397,713
	Accumulated depletion and depreciation		(235,051	)		(212,844	)		(174,637	)		(149,514	)
			262,777			276,350			268,718			248,199
		$	281,070		$	299,853		$	301,633		$	261,093
LIABILITIES AND EQUITY
Current Liabilities
	Accounts payable and accrued liabilities	$	16,949		$	12,054		$	23,244		$	8,716
			16,949			12,054			23,244			8,716
Future site restoration and abandonment costs			5,732			5,289			4,232			3,491
Deferred revenue (note 5)			11,348			612			1,316			2,254
Future income taxes			125,011			109,785			77,756			32,135
			142,091			115,686			83,304			37,880
Equity
	Investment by Paramount Resources Ltd		122,030			172,113			195,085			214,497
			122,030			172,113			195,085			214,497
		$	281,070		$	299,853		$	301,633		$	261,093

/s/ Susan L. Riddell Rose
     Director - Paramount Resources Ltd. /s/ Clayton H. Riddell
     Director - Paramount Resources Ltd.

See accompanying notes to financial statements

F-8

PARAMOUNT RESOURCES LTD. — Northeast Alberta Properties
Statements of Earnings and Changes in Investment by Paramount Resources Ltd.
(Cdn$000)
(See note 1: Basis of Presentation)

		Six Months Ended June 30						Year ended December 31
		2002			2001			2001			2000			1999
		(unaudited)
Revenue
	Petroleum and natural gas sales	$	56,385		$	174,775		$	235,641		$	195,927		$	131,805
	Hedging (note 5)		10,953			(17,346	)		9,123			(449	)		1,085
	Royalties (net of Alberta Royalty Tax Credit)		(9,692	)		(31,427	)		(47,319	)		(38,793	)		(28,501	)
			57,646			126,002			197,445			156,685			104,389
Expenses
	Operating		16,190			17,160			33,955			25,341			20,940
	Surmont compensation – net (note 4)		(37,960	)		—			—			—			—
	General and administrative		1,961			2,184			5,529			4,877			5,528
	Dry holes		218			327			507			—			334
	Lease rentals		1,228			967			2,175			1,736			1,457
	Geological and geophysical		367			854			848			—			—
	(Gain) Loss on sale of property and equipment		134			134			134			—			—
	Provision for future site restoration and abandonment costs		442			672			1,057			741			771
	Depletion and depreciation		24,001			14,256			37,459			25,123			29,024
			6,581			36,554			81,664			57,818			58,054
Earnings before income taxes			51,065			89,448			115,781			98,867			46,335
Income and other taxes
	Current		943			12,117			15,838			1,421			1,492
	Future income taxes		15,226			25,957			32,029			45,621			17,524
			16,169			38,074			47,867			47,042			19,016
Net earnings		$	34,896		$	51,374		$	67,914		$	51,825		$	27,319
Investment by Paramount Resources Ltd., beginning of period			172,113			195,085			195,085			214,497			226,127
Net earnings			34,896			51,374			67,914			51,825			27,319
Distributions to Paramount Resources Ltd.			(84,978	)		(79,942	)		(90,886	)		(71,237	)		(38,949	)
Investment by Paramount Resources Ltd., end of period		$	122,030		$	166,517		$	172,113		$	195,085		$	214,497

See accompanying notes to financial statements

F-9

PARAMOUNT RESOURCES LTD. — Northeast Alberta Properties
Statements of Cash Flows
(Cdn$000)
(See note 1: Basis of Presentation)

		Six Months Ended June 30						Year ended December 31
		2002			2001			2001			2000			1999
		(unaudited)
Operating Activities
Net earnings		$	34,896		$	51,374		$	67,914		$	51,825		$	27,319
Add (deduct) non-cash items
	Depletion and depreciation		24,001			14,256			37,459			25,123			29,024
	(Gain) Loss on sale of property and equipment		134			134			134			—			—
	Provision for future site restoration and abandonment costs		442			672			1,057			741			771
	Future income taxes		15,226			25,957			32,029			45,621			17,524
Add items not relating to operating activities
	Dry hole costs		218			327			507			—			334
	Surmont compensation		(47,096	)		—			—			—			—
			27,821			92,720			139,100			123,310			74,972
Add (deduct) non-cash items
	Change in accounts receivable		(79	)		16,496			20,112			(20,617	)		9,120
	Change in prepaid expenses		735			(867	)		(2,697	)		596			(210	)
	Change in deferred hedging loss		4,554			—			(8,003	)		—			—
	Change in accounts payable		3,859			(13,007	)		(8,504	)		11,746			(13,508	)
	Change in deferred revenue		10,736			20,591			(704	)		(938	)		(1,224	)
			47,626			115,933			139,304			114,097			69,150
Financing Activities
Distributions to Paramount Resources Ltd			(84,977	)		(79,942	)		(90,886	)		(71,237	)		(38,949	)
			(84,977	)		(79,942	)		(90,886	)		(71,237	)		(38,949	)
Investing Activities
Petroleum and natural gas property expenditures			(10,563	)		(36,010	)		(45,225	)		(45,642	)		(30,070	)
Dry hole costs			(218	)		(327	)		(507	)		—			(334	)
Surmont compensation			47,096			—			—			—			—
Change in non-cash working capital			1,036			346			(2,686	)		2,782			203
			37,351			(35,991	)		(48,418	)		(42,860	)		(30,201	)
Change in cash			—			—			—			—			—
Cash at beginning of period			—			—			—			—			—
Cash at end of period		$	—		$	—		$	—		$	—		$	—

See accompanying notes to financial statements

F-10

Paramount Resources Ltd. – Northeast Alberta Properties

Notes to Financial Statements
(Cdn$000 except as noted)

1. Basis of Presentation

         Paramount Resources Ltd. (“PRL”) is a Canadian energy company. PRL explores for, develops, processes, transports and markets petroleum and natural gas. From its inception in 1978 until 1993, PRL concentrated on the exploration and development of shallow gas in northeastern Alberta. Commencing in 1993, PRL diversified from its traditional area of focus and added new core areas in central Alberta, northwest Alberta and the Liard Basin in northeast British Columbia and the southern Northwest Territories. On May 12, 2002 PRL announced that it would create a new energy trust (“Paramount Energy Trust” or “PET”) that would hold substantially all of PRL’s northeast Alberta natural gas properties.

         These financial statements have been prepared to present the financial position, results of operations and cash flows for PRL’s activities in northeastern Alberta. While certain of PRL’s properties in northeastern Alberta are not among the properties that are being acquired by PET, these financial statements have been prepared to include all of the properties in this core area (the “Northeast Alberta Properties”).

         Subsequent to the acquisition of the properties by PET, the management of PET will determine all operating, investing and financing activities applicable to these properties. Accordingly the amounts recorded in these financial statements may not be indicative of the amounts that will result in future periods.

         Each of PRL’s core areas, including the Northeast Alberta Properties, has distinct operating staff, capital budgets and targets. PRL also has shared services such as drilling, facilities, and construction, accounting, land administration and corporate compliance. Historically, PRL has maintained accounting records necessary to support its consolidated financial statements and for other internal or tax reporting purposes. PRL has not previously prepared separate complete financial statements for the Northeast Alberta Properties or for any of its other core areas. While the amounts applicable to the Northeast Alberta Properties for certain revenues, expenses, assets and liabilities can be derived directly from the accounting records of PRL, it has been necessary to allocate certain items in the manner described below.

         These financial statements of the Northeast Alberta Properties have been prepared in accordance Canadian generally accepted accounting policies as applied by PRL, which in the case of these financial statements, differ in certain respects from those in the United States. These differences are described in note 6. These policies include, among other things, the application of the successful efforts method of accounting.

Presentation of the Statement of Earnings

         The amounts for natural gas sales, royalties, operating costs, geological and geophysical costs, dry hole costs and lease rentals have been recorded in the accounting records of PRL on a property by property basis, and the amounts included in these financial statements have been derived directly from the accounting records of PRL. The amounts for depletion and depreciation and the provision for future site restoration and abandonment costs were determined by PRL on the basis of production volumes, estimates of reserves and cumulative costs applicable to each area. The amounts applicable to the Northeast Alberta Properties have been included in these financial statements.

F-11

Paramount Resources Ltd. – Northeast Alberta Properties

Notes to Financial Statements
(Cdn$000 except as noted)

         General and administrative costs incurred by PRL are considered a corporate cost. For purposes of these financial statements, the amounts recorded for general and administrative costs have been allocated for each period on a pro rata basis using production volumes of the Northeast Alberta Properties as a proportion of the aggregate production volumes of PRL.

         Due to the maturity of the properties and the declining level of capital investment in the northeast Alberta area, cumulative cash flow from these properties has exceeded the amounts invested and excess cash flow has been used in conjunction with bank financing to fund the exploration and development in PRL’s other core areas. For these reasons, no amount of the debt, or associated interest costs, have been allocated to the Northeast Alberta Properties.

         PRL periodically uses derivative financial instrument contracts to manage its exposure to petroleum and natural gas prices, the Canadian/US dollar exchange rate and interest rate fluctuations. Hedging activities are considered to be a corporate activity, and are not designated to particular properties. For purposes of these financial statements, gains and losses resulting from the hedging of natural gas prices and Canadian/US dollar exchange rate fluctuations have been allocated for each period on a pro rata basis using applicable cash flows of the Northeast Alberta Properties as a proportion of the aggregate cash flows of PRL. Deferred gains or losses as at the balance sheet dates, such as amounts resulting from the early termination of hedging instruments, have been allocated on a pro rata basis using expected future production of the Northeast Alberta Properties as a proportion of the aggregate expected future production of PRL. Gains or losses applicable to hedging of interest rate hedges have been excluded from these financial statements.

         PRL conducted all of its Canadian activities through one entity for the periods covered by these financial statements. Accordingly, the income tax balances for the costs of acquiring, exploring for and developing the Northeast Alberta Properties, and the costs of associated tangible equipment, are commingled with those of PRL’s other areas. In recent years, while much of the taxable income of PRL before claims of capital costs was from the Northeast Alberta Properties, the majority of the capital expenditures were in other areas. As a result, the capital costs of other areas will have been used to eliminate or reduce taxable income from all areas, including that derived from the Northeast Alberta Properties. For purposes of these financial statements, the amount of future income taxes of PRL as at December 31, 2001 (the most recent date for which tax returns have been prepared and filed) has been allocated to the Northeast Alberta Properties on a pro rata basis using the “equity” of the Northeast Alberta Properties as a proportion of the retained earnings of PRL as a whole. The amounts for future income taxes and current taxes for periods before and after December 31, 2001 have been determined using the effective tax rate for PRL as applied to income before taxes for the Northeast Properties.

Presentation of Financial Position

         The costs of petroleum and natural gas properties, the associated accumulated depletion and depreciation, and the provision for future site restoration and abandonment costs have been accumulated in the accounting records on an area by area basis. The amounts included in these financial statements have been derived directly from the accounting records of PRL.

F-12

Paramount Resources Ltd. – Northeast Alberta Properties

Notes to Financial Statements
(Cdn$000 except as noted)

         For accounts receivable, prepaid expenses and accounts payable and accrued liabilities, the amounts included in the ledgers of PRL have been attributed to the respective core areas or corporate activity on the basis of the nature of the balance or the identity of the counter party. For certain amounts such as when a supplier provides services for several core areas, the amounts have been allocated on the basis of the activity levels during the months preceding the period end.

         Cash, short-term investments and bank loans are considered to be a corporate activity of PRL and have been excluded from these financial statements. For purposes of these financial statements, the activities of the Northeast Alberta Properties are considered to have been financed by advances from the corporate treasury group and retained earnings, net of accumulated repayment of cash flows from operating activities. As the cumulative cash flows from operations of the Northeast Alberta Properties, and repaid to the corporate treasury function, are in excess of the associated investments, no amount has been recorded for interest expense in these financial statements.

Presentation of Statement of Cash Flows

         As discussed above, the cash balances of PRL are maintained on a centralized basis and considered to be a corporate activity and excluded from these financial statements. For purposes of the presentation of the statement of cash flows, cash and disbursements are deemed to be transferred to or from the corporate account concurrent with the respective inflow or outflow of cash.

2. Summary of Significant Accounting Policies

General

         These financial statements are stated in Canadian dollars and have been prepared in accordance with Canadian generally accepted accounting principles, which in the case of these financial statements, differ in certain respects from those in the United States. These differences are described in note 6.

         The preparation of financial statements requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the period. Estimates are used for, but not limited to, volumes of recoverable volumes of petroleum and natural gas reserves and future site restoration and abandonment costs. Actual results could differ from those estimates.

         The unaudited financial statements presented herein include all accruals necessary to present fairly the financial position at June 30, 2002, and the results of operations and cash flows for the six-month periods ended June 30, 2002 and 2001, in conformity with generally accepted accounting principles.

F-13

Paramount Resources Ltd. – Northeast Alberta Properties

Notes to Financial Statements
(Cdn$000 except as noted)

Petroleum and Natural Gas Properties

         PRL follows the successful efforts method of accounting for petroleum and natural gas operations. Under this method, PRL capitalizes only those costs that result directly in the discovery of petroleum and natural gas reserves. Exploration expenses, including geological and geophysical costs, lease rentals and exploratory dry hole costs, are charged to earnings as incurred. Leasehold acquisition costs, including costs of drilling and equipping successful wells, are capitalized. The net cost of unproductive wells, abandoned wells and surrendered leases are charged to earnings in the year of abandonment or surrender. Gains or losses are recognized on the disposition of properties and equipment.

         Depletion and depreciation of petroleum and natural gas properties including well development expenditures, production equipment, gas plants and gathering systems are provided on the unit-of-production method based on estimated proven recoverable reserves of each producing property or project. Depreciation of other equipment is provided on a declining balance method at rates varying from 20 to 30 percent.

         The net amount at which petroleum and natural gas costs on a property or project are carried is subject to a cost-recovery test. Any impairment loss is the difference between the carrying value of the asset and its recoverable amount (undiscounted). The carrying values of capital assets, including the costs of acquiring proven and probable reserves, are subject to uncertainty associated with the quantity of oil and gas reserves, future production rates, commodity prices and other factors.

         Certain of the exploration development and production activities related to the Northeast Alberta Properties are conducted jointly with others. These financial statements reflect only PRL’s proportional interest in such activities.

Revenue Recognition

         Revenue from the sale of petroleum and natural gas is recorded at the time that the product is produced and sold. Natural gas is produced in a substantially marketable state and is sold to purchasers immediately at or near the point of production.

Future Site Restoration and Abandonment Costs

         Estimated future site restoration and abandonment costs are provided for using the unit of production method. This estimate, net of expected recoveries, includes the cost of the equipment removal and environmental cleanup based upon current regulations and economic circumstances at year end. Actual site restoration costs are deducted from the provision in the year incurred.

F-14

Paramount Resources Ltd. – Northeast Alberta Properties

Notes to Financial Statements
(Cdn$000 except as noted)

Financial Instruments

         PRL utilizes derivative financial instrument contracts to manage its exposure to petroleum and natural gas prices and the Canadian/US dollar exchange rate. Gains or losses from foreign exchange and commodity hedge contracts, including amounts realized on the early termination of the contracts, are recognized in the same period as the related production revenue. The fair values of these contracts are not reflected in the financial statements.

3. Acquisition of Northeast Alberta Properties by Paramount Energy Trust

         In accordance with a series of agreements, a trust beneficially owned by PET is expected to initially acquire PRL’s interest in the Legend, Alberta area (the “Initial Assets”) and up to a 100% interest in PRL’s interest in most of its remaining properties in its northeast Alberta core area (the “Additional Assets”). PRL’s properties in its northeast Alberta core area that are not being transferred to PET are referred to as the “Excluded Assets” for purposes of these financial statements.

         The revenues (excluding gains or losses on hedging), royalties and operating expenses of each of the three groups of properties are as follows:

Six Months Ended June 30, 2002		Initial			Additional			Excluded			Northeast
(unaudited)		Assets			Assets			Assets			Alberta Total
Revenue
	Petroleum and natural gas sales	$	11,520		$	43,611		$	1,254		$	56,385
	Royalties		(2,418	)		(6,948	)		(326	)		(9,692	)
			9,102			36,663			928			46,693
Operating Expenses			3,220			12,757			213			16,190
		$	5,882		$	23,906		$	715		$	30,503

Six Months Ended June 30, 2001		Initial			Additional			Excluded			Northeast
(unaudited)		Assets			Assets			Assets			Alberta Total
Revenue
	Petroleum and natural gas sales	$	18,404		$	152,030		$	4,341		$	174,775
	Royalties		(5,063	)		(25,827	)		(537	)		(31,427	)
			13,341			126,203			3,804			143,348
Operating Expenses			2,733			14,226			201			17,160
		$	10,608		$	111,977		$	3,603		$	126,188

		Initial			Additional			Excluded			Northeast
Year Ended December 31, 2001		Assets			Assets			Assets			Alberta Total
Revenue
	Petroleum and natural gas sales	$	28,492		$	199,791		$	7,358		$	235,641
	Royalties		(8,888	)		(36,873	)		(1,558	)		(47,319	)
			19,604			162,918			5,800			188,322
Operating Expenses			4,628			28,242			1,085			33,955
		$	14,976		$	134,676		$	4,715		$	154,367

F-15

Paramount Resources Ltd. – Northeast Alberta Properties

Notes to Financial Statements
(Cdn$000 except as noted)

		Initial			Additional			Excluded			Northeast
Year Ended December 31, 2000		Assets			Assets			Assets			Alberta Total
Revenue
	Petroleum and natural gas sales	$	24,357		$	158,370		$	13,200		$	195,927
	Royalties		(6,366	)		(28,825	)		(3,602	)		(38,793	)
			17,991			129,545			9,598			157,134
Operating Expenses			3,318			20,828			1,195			25,341
		$	14,673		$	108,717		$	8,403		$	131,793

		Initial			Additional			Excluded			Northeast
Year Ended December 31, 1999		Assets			Assets			Assets			Alberta Total
Revenue
	Petroleum and natural gas sales	$	13,426		$	94,149		$	24,230		$	131,805
	Royalties		(2,765	)		(20,008	)		(5,728	)		(28,501	)
			10,661			74,141			18,502			103,304
Operating Expenses			754			17,357			2,829			20,940
		$	9,907		$	56,784		$	15,673		$	82,364

4. Surmont Compensation

         During 2000, the Alberta Energy and Utilities Board (the “AEUB”) issued a decision regarding the Surmont natural gas bitumen co-production issue. The Surmont property is in northeast Alberta, is not to be acquired by PET and is one of the Excluded Assets. As a result of this decision, the AEUB ordered the shut-in of approximately 22 mmcf/d of PRL’s production. On February 28, 2002 PRL and other Surmont gas producers entered into a Memorandum of Understanding with the Province of Alberta effective May 1, 2000. The Memorandum provided for compensation of approximately $85 million to be paid to PRL and the other Surmont producers by the Alberta Crown, as well as granting to the Province of Alberta an 11% gross overriding royalty encompassing certain wells, land and leases affected by the shut-in order of May 1, 2000.

         In June 2002, PRL received approximately $47 million from the Province of Alberta as compensation for its proportionate share of the settlement. The cash settlement, net of the book value of associated wells, lands and leases in the affected area, has been recorded as a gain in net earnings in the current period.

         None of such shut-in wells is included in the Initial Assets or the Additional Assets. A further hearing (the “Chard/Leismer Hearing”) is currently before the AEUB involving many applications, including one by a bitumen lease holder for the shutting-in of a further 40 natural gas wells in the Chard area of northeast Alberta and three by PRL for approval to produce natural gas from four wells in the Leismer area of northeast Alberta. The AEUB granted an interim order shutting-in 10 of the 40 wells in the Chard area. None of the 10 shut-in wells are included in the Initial Assets or the Additional Assets; however, 18 of the remaining 30 wells and the four wells for which PRL is making application are included in the Additional Assets. PRL’s current share of production from the 18  wells is approximately two mmcf/d of natural gas. Revenue from these wells was approximately $4.5 million in the fiscal year ended December 31, 2001 and net earnings from these wells was approximately $3.2 million during the same period.

5. Financial Instruments

         For purposes of these financial statements, gains and losses resulting from the hedging of natural gas prices and Canadian/US dollar exchange rate fluctuations have been allocated for each period on a pro rata basis using applicable cash flows of the Northeast Alberta Properties as a proportion of the aggregate cash flows of PRL. Deferred gains or losses as at the balance sheet dates, such as amounts resulting from the early termination of hedging instruments, have been allocated on a pro rata basis using expected future production of the Northeast Alberta Properties as a proportion of the aggregate expected future production of PRL. Gains or losses applicable to hedging of interest rates have been excluded from these financial statements.

F-16

Paramount Resources Ltd. – Northeast Alberta Properties

Notes to Financial Statements
(Cdn$000 except as noted)

(a) December 31, 2001

(i) Foreign Exchange Hedges

         PRL had entered into the following currency index swap transactions, fixing the exchange rate on receipts of $US 27.8 million for $Cdn 39.7 million over the next three years at $Cdn 1.4264. The $US/$Cdn closing exchange rate was 1.5928 as at December 31, 2001 (2000 – 1.5002).

	US Dollars		Weighted Average Exchange Rate
2002	$	22,920		1.4275
2003		4,570		1.4211
2004		360		1.4206
	$	27,850		1.4264

         At December 31, 2001, the estimated fair value based on PRL’s assessment of available market information was $44.3 million.

(ii) Natural Gas Commodity Price Hedges

         PRL had entered into financial forward sales arrangements on 115 mmcf/d of natural gas as follows:

	Price	Term
AECO
80,000 GJ/d	$4.3825	January 1, 2002 – December 31, 2002
10,000 GJ/d	$3.6850	January 1, 2002 – December 31, 2002
NYMEX
5 mmcf/d	$US3.63	September 1, 2001 – October 31, 2002
10 mmcf/d	$US3.66	September 1, 2001 – October 31, 2002
10 mmcf/d	$US3.67	September 1, 2001 – October 31, 2002

         The pre-tax unrealized gain on these financial contracts at December 31, 2001, totaled $35.4 million. The AECO price at December 31, 2001 was $3.72 per Mcf and the NYMEX price was $US 2.53 per Mcf.

F-17

Paramount Resources Ltd. – Northeast Alberta Properties

Notes to Financial Statements
(Cdn$000 except as noted)

(b) June 30, 2002

(i) Natural Gas Commodity Price Hedges

         PRL had entered into financial forward sales arrangements on 180 mmcf/d of natural gas as follows:

	Price	Term
AECO
10,000 GJ/d	$3.69	January 1, 2002 – December 31, 2002
60,000 GJ/d	$4.38	January 1, 2002 – December 31, 2002
10,000 GJ/d	$5.46	November 30, 2002 – October 31, 2003
20,000 GJ/d	$5.06	November 30, 2002 – October 31, 2003
NYMEX
10 mmcf/d	$US2.83	April 2002 – October 2002
10 mmcf/d	$US2.90	April 2002 – October 2002
10 mmcf/d	$US3.03	April 2002 – October 2002
20 mmcf/d	$US3.83	November 1, 2002 – October 31, 2003
20 mmcf/d	$US3.90	November 1, 2002 – October 31, 2003
10 mmcf/d	$US4.10	November 1, 2002 – October 31, 2003

         The pre-tax unrealized gain on these financial contracts at June 30,2002, totaled $13.1 million.

         PRL periodically settles outstanding commodity hedging contracts. Cash proceeds or payments on settlement are included in deferred revenue or deferred hedging losses and amortized over the life of the initial hedging contract.

(ii) Foreign Exchange Hedges

         Foreign currency index swap transactions entered into by PRL were unchanged from those outstanding at December 31, 2001. At June 30, 2002, the estimated fair value of these hedges based on PRL’s assessment of available market information was a loss of $2.5 million.

(c) Fair Value Of Financial Assets And Liabilities

         Fair values of derivative instruments are determined based on the estimated cash payment or receipt necessary to settle the contract. Cash payments or receipts are based on discounted cash flow analysis using current market rates and prices available to PRL.

F-18

Paramount Resources Ltd. – Northeast Alberta Properties

Notes to Financial Statements
(Cdn$000 except as noted)

6. Accounting Principles Generally Accepted in the United States

         These financial statements have been prepared in accordance with accounting principles generally accepted in Canada (“Canadian GAAP”) which, in most respects, conform to accounting principles generally accepted in the United States (“US GAAP”). Significant differences between Canadian and US GAAP are as follows:

		Six months ended June 30,						Year ended December 31,
		2002			2001			2001			2000		1999
		(unaudited)
Net earnings — Canadian GAAP		$	34,896		$	51,374		$	67,914		$	51,825	$	27,319
Derivative financial instruments	b		12,139			33,735			4,929			—		—
Future Income Taxes	b		(4,856	)		(13,494	)		(1,972	)		—		—
Net earnings — US GAAP		$	42,179		$	71,615		$	70,871		$	51,825	$	27,319

Balance Sheet

	June 30						December 31
	2002						2001						2000						1999
	Cdn GAAP			US GAAP			Cdn GAAP			US GAAP			Cdn GAAP			US GAAP			Cdn GAAP			US GAAP
Deferred Hedging Loss	$	3,449		$	—		$	8,003		$	—		$	—		$	—		$	—		$	—
Accounts Receivable		11,227			15,467			11,148			23,468			31,260			31,260			10,643			10,643
Deferred Revenue		(11,348	)		—			(612	)		—			(1,316	)		(1,316	)		(2,254	)		(2,254	)
Future Income Taxes		(125,011	)		(129,867	)		(109,785	)		(111,757	)		(77,756	)		(77,756	)		(32,135	)		(32,135	)
Investment by PRL	$	(122,030	)	$	(129,313	)	$	(172,113	)	$	(175,070	)	$	(195,085	)	$	(195,085	)	$	(214,497	)	$	(214,497	)

a)	Property, Plant and Equipment
	Under both US and Canadian GAAP, property plant and equipment must be assessed for potential impairments. Under US GAAP, if the sum of the expected future cash flows (undiscounted and without interest charges) is less than the carrying amount of the asset, then an impairment loss (the amount by which the carrying amount of the asset exceeds the fair value of the asset) should be recognized. Fair value is calculated as the present value of estimated future cash flows. Under Canadian GAAP, the impairment loss is the difference between the carrying value of the asset and its net recoverable amount (undiscounted). These differences in the determination of the amount of impairment did not result in any differences in the periods covered by these financial statements.
b)	Accounting for Derivative Financial Instruments
	Under U.S. GAAP, PRL is required commencing January 1, 2001 to account for derivative instruments and hedging activities in accordance with FAS 133 which requires that all derivatives be recognized as assets and liabilities on the balance sheet and measured at fair value. Gains or losses, including unrealized amounts, on derivatives that have not been designated as hedges, or were not effective as hedges, are included in income as they arise.

F-19

Paramount Resources Ltd. – Northeast Alberta Properties

Notes to Financial Statements
(Cdn$000 except as noted)

	For derivatives designated as fair value hedges, changes in the fair value are recognized in earnings together with equal or lesser amounts of changes in the fair value of the hedge item.
	For derivatives designated as cash flow hedges, changes in the fair value of the derivatives are recognized in other comprehensive income until the hedged items are recognized in earnings. Any portion of the change in the fair value of the derivatives that is not effective in hedging the changes in future cash flows is included in earnings each period.
	As PRL did not contemplate the preparation of US GAAP financial statements at the time the derivative instruments were entered into, and the required hedge accounting documentation was not prepared, the derivatives entered into by PRL did not qualify as hedges for US GAAP purposes. Accordingly, the gains and losses, including unrealized amounts, have been included in income as they arise.
c)	Impairment or Disposal of Long-term Assets
	In August 2001, the FASB issued Statement No. 144 “Accounting for the Impairment or Disposal of Long-term assets” (“FAS 144”), which address the financial accounting and reporting for the impairment or disposal of long-lived assets. FAS 144 supersedes but retains the basic principle of Statement No 121 for the impairment of assets to be held and used. Assets to be disposed of though abandonment or an exchange for similar productive assets will be classified as held for use until they cease to be used. FAS 144 established criteria that must be met in order to classify an asset or group as held for sale. Assets classified as held for sale will be measured at the lower of their carrying amount or fair value less cost to sell, and depreciation will cease when the asset or group is classified as held for sale. The changes resulting from the adoption of the FAS 144 did not have any impact on the results of the impairment test as described in a) above.
	FAS 144 broadens the definition of disposals to be presented as discontinued operations to include components of an entity that comprise operating cash flows that can clearly be distinguished, operationally and for financial reporting purposes from the rest of the entity. While FAS 144 may result in differences in future periods, it does not have any impact on these financial statements.
d)	Other Comprehensive Income
	Under US GAAP, certain items such as the unrealized gain or loss on derivative instrument contracts designated and effective as cash flow hedges are included in other comprehensive income. In these financial statements, there are no comprehensive income items other than net income.
e)	Statement of Cash Flows
	There are no differences between Canadian and US GAAP as they apply to statements of cash flows.

F-20

Paramount Resources Ltd. – Northeast Alberta Properties

Notes to Financial Statements
(Cdn$000 except as noted)

f) Known But Not Yet Adopted Changes in Accounting Principles

(i)

Future Removal and Site Restoration

Beginning on January 1, 2003, companies will be required to adopt FASB Statement No. 143 “Accounting for Asset Retirement Obligations” (“FAS 143”), which addresses financial accounting and reporting for obligations associated with the retirement of tangible assets. The standard applies to legal obligations associated with the retirement of long-lived assets that result from the acquisition, construction, development and use of the asset. FAS 143 requires that the fair value of a liability for an asset retirement obligation be recognized in the period in which it is incurred if a reasonable estimate of fair value can be made. The fair value is added to the carrying amount of the associated asset. The liability is accreted at the end of each period through charges to operating expenses. As at the date of adoption of January 1, 2003 the amount recorded as the fair value of the liability is expected to be significantly in excess of the amount recorded under PRL’s existing accounting policies. In addition, the estimated fair value, net of any amounts that would have been depleted or depreciated in previous periods will be recorded as an increase, and expected to be significant, in the carrying amount of the asset. PRL has not quantified the amounts of either of these increases, or the net difference which will be recorded as cumulative catch-up adjustment in earnings.

7. Supplemental Oil and Gas Disclosure (unaudited):

         The following disclosures have been prepared in accordance with FASB Statement No. 69 “Disclosures about Oil and Gas Producing Activities” (“FAS 69”). All of the Initial Assets, Additional Assets and Excluded Assets are situated in Canada and are related to the production of natural gas.

Oil and Gas Reserves

         Users of this information should be aware that the process of estimating quantities of “proved” and “proved developed” reserves is very complex, requiring significant subjective decisions in the evaluation of all available geological, engineering and economic data for each reservoir. The data for a given reservoir may also change substantially over time as a result of numerous factors including, but not limited to, additional development activity, evolving production history and continual reassessment of the viability of production under varying economic conditions. Consequently, material revisions to existing reserve estimates occur from time to time. Although every reasonable effort is made to ensure that reserve estimates reported represent the most accurate assessments possible, the significance of the subjective decisions required and variances in available data for various reservoirs make these estimates generally less precise than other estimates presented in connection with financial statement disclosures.

F-21

Paramount Resources Ltd. – Northeast Alberta Properties

Notes to Financial Statements
(Cdn$000 except as noted)

For purposes of this note:

“Proved” reserves means those reserves estimated as recoverable under current technology and existing economic conditions, from that portion of a reservoir which can be reasonably evaluated as economically productive on the basis of analysis of drilling, geological, geophysical and engineering data, including the reserves to be obtained by enhanced recovery processes demonstrated to be economic and technically successful in the subject reservoir.

“Proved Developed” reserves are reserves that can be expected to be recovered through existing equipment and operating methods. Proved undeveloped reserves means those reserves expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major capital expenditure will be required.

         Canadian provincial royalties are determined based on a graduated percentage scale which varies with prices and production volumes. Future fluctuations in prices, production rates, or changes in political or regulatory environments could cause PET’s share of future production from reserves to be materially different from that presented.

Results of Operations for Producing Activities

         Revenue and direct cost information relating to the oil and gas producing activities of the Initial Assets, Additional Assets and Excluded Assets are set forth in note 3:

Costs Incurred in Oil and Gas Property Acquisition, Exploration and Development Activities

         Costs incurred in oil and gas producing activities for the years ended December 31 are as follows:

		2001						2000						1999
		Initial and				Northeast		Initial and				Northeast		Initial and					Northeast
		Additional		Excluded		Alberta		Additional		Excluded		Alberta		Additional		Excluded			Alberta
		Assets		Assets		Total		Assets		Assets		Total		Assets		Assets			Total
Property Acquisition Costs
	Proved	$	31	$	—	$	31	$	3,072	$	—	$	3,072	$	1,076	$	—		$	1,076
	Unproved		—		—		—		—		—		—		—		—			—
Exploration Costs			29,328		—		12,504		22,426		—		22,426		8,652		—			8,652
Development Costs			12,504		3,362		32,690		17,279		2,865		20,144		20,736		(394	)		20,342
		$	41,863	$	3,362	$	45,225	$	42,777	$	2,865	$	45,642	$	30,464	$	(394	)	$	30,070

F-22

Paramount Resources Ltd. – Northeast Alberta Properties

Notes to Financial Statements
(Cdn$000 except as noted)

Oil and Gas Reserve Information

         The proved developed and undeveloped gas reserves related to the Initial Assets, Additional Assets and Excluded Assets are as follows:

	Initial and												Northeast
	Additional Assets						Excluded Assets						Alberta Total
(bcf)	Gross			Net			Gross			Net			Gross			Net
Proved Developed and Undeveloped Reserves
December 31, 1998		367.8			295.4			49.1			39.6			416.9			334.8
Revisions of Previous Estimates		(51.1	)		(41.1	)		1.9			1.5			(49.2	)		(39.5	)
Purchase/Sale of Reserves		26.5			21.3			—			—			26.5			21.3
Discoveries and Extensions		13.7			11.0			—			—			13.7			11.0
Production		(41.2	)		(33.1	)		(9.4	)		(7.6	)		(50.6	)		(40.6	)
December 31, 1999		315.7			253.5			41.6			33.6			357.3			287.0
Revisions of Previous Estimates		(62.9	)		(50.5	)		1.8			1.4			(61.1	)		(49.1	)
Purchase/Sale of Reserves		2.9			2.3			—			—			2.9			2.3
Discoveries and Extensions		2.7			2.2			—			—			2.7			2.2
Production		(39.3	)		(29.7	)		(4.4	)		(3.6	)		(43.7	)		(33.2	)
December 31, 2000		219.1			177.9			39.0			31.4			258.1			209.2
Revisions of Previous Estimates		3.4			2.7			(35.3	)		(28.4	)		(31.9	)		(25.7	)
Purchase/Sale of Reserves		0.3			0.2			—			—			0.3			0.2
Discoveries and Extensions		—			—			—			—			—			—
Production		(37.5	)		(28.8	)		(1.0	)		(0.8	)		(38.5	)		(29.6	)
December 31, 2001		185.3			152.0			2.7			2.2			188.0			154.2
Proved Developed Reserves
December 31, 1999		271.3			218.2			2.7			2.2			274.0			221.0
December 31, 2000		214.8			174.9			2.7			2.2			217.5			177.1
December 31, 2001		181.7			149.4			2.7			2.2			184.4			151.6

Notes:

“Gross” Reserves are the total of PRL’s working and/or royalty interest share of reserves before deducting royalties owned by others.

“Net” Reserves are the total of PRL’s working and/or royalty interest after deducting the amount attributable to royalties owned by others.

Subsequent to December 31, 2001 no major discovery or other favorable or adverse event is believed to have caused a material change in the estimates of proved or proved developed reserves as of that date.

Standardized Measure of Discounted Future Net Cash Flow Relating to Proved Oil and Gas Reserves

         The following information has been developed utilizing procedures prescribed by FAS 69 and based on natural gas reserve and production volumes estimated in the McDaniel Report. It may be useful for certain comparison purposes, but should not be solely relied upon in evaluating the performance of the Initial Assets, the Additional Assets or the Excluded Assets. Further, information contained in the following table should not be considered as representative of realistic assessments of future cash flows, nor should the standardized measure of discounted future net cash flows be viewed as representative of the current value of the reserves included in the Initial Assets, the Additional Assets and the Excluded Assets.

         The future cash flows presented below are based on prices and costs in existence as of the date of the projections. It is expected that material revisions to some estimates of natural gas reserves may occur in the future, development and production of the reserves may occur in periods other than those assumed, and actual prices realized and costs incurred may vary significantly from those used.

F-23

Paramount Resources Ltd. – Northeast Alberta Properties

Notes to Financial Statements
(Cdn$000 except as noted)

         The computation of the standardized measure of discounted future net cash flows relating to proved natural gas reserves was based on reference natural gas prices of $3.32, $8.23 and $3.52 at December 31, 2001, 2000 and 1999, respectively.

         The following table sets forth the standardized measure of discounted future net cash flows from projected production of gas reserves at December 31, for the years presented:

	2001									2000									1999
	Initial and									Initial and									Initial and
	Additional			Excluded			Northeast			Additional			Excluded			Northeast			Additional			Excluded			Northeast
	Assets			Assets			Alberta Total			Assets			Assets			Alberta Total			Assets			Assets			Alberta Total
Future Cash Inflows	$	509,123		$	7,492		$	516,615		$	1,184,390		$	213,848		$	1,398,238		$	805,703		$	108,238		$	913,941
Future Production and Development Costs		(232,296	)		(3,135	)		(235,431	)		(271,803	)		(48,083	)		(319,886	)		(387,451	)		(51,362	)		(438,813	)
Future Net Cash Flows		276,827			4,357			281,184			912,587			165,765			1,078,352			418,252			56,876			475,128
Deduct: 10% Annual Discount Factor		(77,762	)		(1,224	)		(78,986	)		(256,350	)		(46,564	)		(302,914	)		(117,489	)		(15,977	)		(133,466	)
Standardized Measure of Future Net Cash Flows(1)	$	199,065		$	3,133		$	202,198		$	656,237		$	119,201		$	775,438		$	300,763		$	40,899		$	341,662

Changes in Standardized Measure of Discounted Future Cash Flow Relating to Proved Reserves

         The following table sets forth the changes in the standardized measure of discounted future net cash flows at December 31, for the years presented:

	2001									2000									1999
	Initial and									Initial and									Initial and
	Additional			Excluded			Northeast			Additional			Excluded			Northeast			Additional			Excluded			Northeast
	Assets			Assets			Alberta Total			Assets			Assets			Alberta Total			Assets			Assets			Alberta Total
Future Discounted Net Cash Flows, beginning of year	$	656,237		$	119,201		$	775,438		$	300,763		$	40,899		$	341,662		$	324,180		$	45,677		$	369,856
Sales Net of Production Costs		(149,652	)		(4,715	)		(154,367	)		(123,390	)		(7,134	)		(130,524	)		(66,691	)		(15,673	)		(82,364	)
Net change in Prices, Net of Development and Production Costs		(423,317	)		(77,390	)		(500,707	)		634,694			87,375			722,068			26,218			2,579			28,797
Extensions and Discoveries, Net of Related Costs		—			—			—			8,077			39			8,116			13,074			49			13,122
Revision of Quantity Estimates		3,615			(37,567	)		(33,952	)		(186,325	)		4,470			(181,855	)		(48,717	)		1,635			(47,081	)
Accretion of Discount		65,624			11,920			77,544			30,076			4,090			34,166			32,418			4,568			36,986
Purchase of Reserves in Place		300			—			300			8,469			40			8,509			25,259			94			25,353
Change in Timing of Future Net Cash Flows and Other		46,259			(8,316	)		37,943			(16,127	)		(10,578	)		(26,705	)		(4,978	)		1,971			(3,007	)
Future Discounted Net Cash Flows, end of year	$	199,065		$	3,133		$	202,198		$	656,237		$	119,201		$	775,438		$	300,763		$	40,899		$	341,662

Notes:

(1)	The schedules above are calculated using year-end prices and costs and proved natural gas reserves. The value of exploration properties and probable reserves, future exploration costs, future changes in oil and gas prices and in production and development costs are excluded.
(2)	PET intends to distribute all of its taxable income to unitholders in every year and to deduct those amounts paid (or payable) from its taxable income to ensure that PET generally will not be liable for any material amounts of tax. Accordingly, income tax has been excluded from this supplemental information.

F-24

COMPILATION REPORT

To the Trustee of Paramount Energy Trust

We have reviewed, as to compilation only, the accompanying pro forma consolidated balance sheet of Paramount Energy Trust as at June 30, 2002 and the pro forma consolidated statements of earnings for the year ended December 31, 2001 and the six month period ended June 30, 2002. These pro forma financial statements have been prepared for inclusion in the prospectus. In our opinion, the pro forma consolidated balance sheet and the pro forma consolidated statements of earnings have been properly compiled to give effect to the proposed transactions and assumptions described in the notes thereto.

/s/ KPMG LLP
Chartered Accountants
Calgary, Canada
November 4, 2002

COMMENTS FOR U.S. READERS

The above report, provided solely pursuant to Canadian requirements, is expressed in accordance with standards of reporting generally accepted in Canada. Such standards contemplate the expression of an opinion with respect to the compilation of pro forma financial statements. United States standards do not provide for the expression of an opinion on the compilation of pro forma financial statements. To report in conformity with United States standards on the reasonableness of the pro forma adjustments and their application to the pro forma financial statements requires an examination or review substantially greater in scope than the review we have conducted. Consequently, we are unable to express any opinion in accordance with standards of reporting generally accepted in the United States with respect to the compilation of the accompanying unaudited pro forma financial information.

/s/ KPMG LLP
Chartered Accountants
Calgary, Canada
November 4, 2002

F-25

PARAMOUNT ENERGY TRUST
Pro Forma Consolidated Balance Sheet
June 30, 2002
(Cdn$000)

	PRL
	Northeast		Excluded			Acquisition of							Total After
	Total		Assets			Initial Assets		Adj.					Initial Assets
	(3)		3(a)			3(b)
ASSETS
Current Assets
Cash	$	—	$	—		$	—	$	—				$	—
Accounts receivable and prepaid expenses		14,844		(330	)		—		(14,514	)	3	(g)		—
Deferred hedging loss		3,449		(77	)		—		(3,372	)	3	(h)		—
		18,293		(407	)		—		(17,886	)				—
Property, plant and equipment
Petroleum and natural gas properties		262,777		(11,508	)		81,000		(251,269	)				47,774
									(33,226	)	3	(f)
		262,777		(11,508	)		81,000		(284,495	)				47,774
	$	281,070	$	(11,915	)	$	81,000	$	(302,381	)			$	47,774
LIABILITIES AND EQUITY
Current Liabilities
Accounts payable	$	16,949	$	(223	)	$	—	$	(16,726	)	3	(g)	$	—
Debt		—		—			30,000		—					30,000
		16,949		(223	)		30,000		(16,726	)				30,000
Deferred revenue		11,348		(252	)				(11,096	)	3	(h)		—
Future site restoration and abandonment costs		5,732		(251	)				(5,125	)				356
Future income taxes		125,011		(5,475	)		—		(119,536	)	3	(a)		—
		142,091		(5,978	)		30,000		(135,757	)				30,356
Equity
Unitholders’ equity		—		—			51,000		(33,582	)	3	(f)		17,418
Investment by Paramount Resources Ltd		122,030		(5,714	)		—		(116,316	)				—
		122,030		(5,714	)		51,000		(149,898	)				17,418
	$	281,070	$	(11,915	)	$	81,000	$	(302,381	)			$	47,774

See accompanying notes to pro forma consolidated financial statements

								Pro Forma Consolidated
					Acquisition
			Rights		of Additional								Rights @					Rights @						Rights @
			Offering		Assets			Adj.					100%		Adj.			75%			Adj.			50%
ASSETS	3	(c)						(2)							(2)
Current Assets
Cash			$	149,133	$	(149,133	)	$	—				$	—	$	—		$	—		$	—		$	—
Accounts receivable and prepaid expenses				—		—			—					—		—			—			—			—
Deferred hedging loss				—		—			—					—					—						—
				149,133		(149,133	)		—					—		—			—			—			—
Property, plant and equipment
Petroleum and natural gas properties	3	(f)		—		220,000			(16,505	)	3	(f)		251,269		(38,610	)		215,556			(63,184	)		157,112
																2,897						4,740
				—		220,000			(16,505	)				251,269		(35,713	)		215,556			(58,444	)		157,112
			$	149,133	$	70,867		$	(16,505	)			$	251,269	$	(35,713	)	$	215,556		$	(58,444	)	$	157,112
LIABILITIES AND EQUITY
Current Liabilities
Accounts payable	3	(f)	$	—	$	—		$	—				$	—	$	—		$	—		$	—		$	—
Debt	3	(d)		—		70,867			—					100,867		(1,077	)		99,790			(25,651	)		74,139
				—		—			—					100,867		(1,077	)		99,790			(25,651	)		74,139
Deferred revenue				—		—			—					—		—			—			—			—
Future site restoration and abandonment costs	3	(f)		—		—			5,125					5,481		(1,048	)		4,433			(1,420	)		3,013
Future income taxes				—		—			—					—		—			—			—			—
				—		70,867			5,125					5,481		(1,048	)		(4,433	)		(1,420	)		3,013
Equity	3(f)	3(c)
Unitholders’ equity				149,133		—			(21,630	)				144,921		(36,485	)		111,333			(36,133	)		79,960
																2,897						4,740
Investment by Paramount Resources Ltd				—		—			—					—		—			—			—			—
				149,133		—			(21,630	)				144,921		(33,588	)		111,333			(37,373	)		79,960
			$	149,133	$	70,867		$	(16,505	)			$	251,269	$	(35,713	)	$	215,556		$	(58,444	)	$	157,112

See accompanying notes to pro forma consolidated financial statements

F-26

PARAMOUNT ENERGY TRUST
Pro Forma Consolidated Statement of Earnings
Six Months Ended June 30, 2002
(Cdn$000)
Unaudited

													Total to PET
				Northeast			Excluded						Rights @						Rights @						Rights @
				Alberta Total			Assets			Adjustments			100%			Adjustments			75%			Adjustments			50%
				4(a)			4(a)			4(c)(d)(e)						(2)						(2)
Revenue:
	Sales of natural gas			$	56,385		$	(1,254	)	$	—		$	55,131		$	(7,656	)	$	47,475		$	(12,521	)	$	34,954
	Hedging	4	(b)		10,953			(244	)		—			10,709			(1,487	)		9,222			(2,432	)		6,790
	Royalties				(9,692	)		326			—			(9,366	)		1,220			(8,146	)		1,995			(6,151	)
					57,646			(1,172	)		—			56,474			(7,923	)		48,551			(12,958	)		35,593
Expenses:
	Operating				16,190			(213	)		—			15,977			(2,239	)		13,738			(3,663	)		10,075
	Surmont compensation – net	4	(c)		(37,960	)		37,960			—			—			—			—			—			—
	General and administrative	4	(d)		1,961			(38	)		147			2,070			—			2,070			—			2,070
	Interest				—			—			2,126			2,126			(262	)		1,864			(427	)		1,437
	Dry hole	4	(e)		218			—			(218	)		—			—			—			—			—
	Lease rentals	4	(e)		1,228			(16	)		(1,212	)		—			—			—			—			—
	Geological and geophysical	4	(e)		367			—			(367	)		—			—			—			—			—
	Gain (Loss) on sale of property				134			—			(134	)		—			—			—			—			—
	Depletion and Depreciation	4	(e)		24,001			(461	)		5,276			28,816			(4,472	)		24,344			(7,314	)		17,030
	Site restoration				442			(8	)		1,088			1,522			(258	)		1,264			(421	)		843
					6,581			37,224			6,706			50,511			(7,231	)		43,280			(11,825	)		31,455
Earnings before Taxes					51,065			(38,396	)		(6,706	)		5,963			(692	)		5,271			(1,133	)		4,138
Income and Other Taxes		4	(g)
Current taxes					943			—			(943	)		—			—			—			—			—
Future income taxes					15,226			(11,448	)		(3,778	)		—			—			—			—			—
					16,169			(11,448	)		(4,721	)		—			—			—			—			—
Net Earnings				$	34,896		$	(26,947	)	$	(1,985	)	$	5,963		$	(692	)	$	5,271		$	(1,133	)	$	4,138
Net Earnings per Trust Unit
	Basic												$	0.15					$	0.16					$	0.17
	Diluted	5											$	0.15					$	0.16					$	0.17

See accompanying notes to pro forma consolidated financial statements

F-27

PARAMOUNT ENERGY TRUST
Pro Forma Consolidated Statement of Earnings
Year Ended December 31, 2001
(Cdn$000)
(Unaudited)

													Total to PET
				Northeast			Excluded						Rights @						Rights @						Rights @
				Alberta Total			Assets			Adjustments			100%			Adjustments			75%			Adjustments			50%
				4(a)			4(a)			4(c)(d)(e)						(2)						(2)
Revenue:
	Sales of Natural Gas			$	235,641		$	(7,358	)	$	—		$	228,283		$	(35,072	)	$	193,211		$	(57,363	)	$	135,848
	Hedging	4	(b)		9,123			(285	)		—			8,838			(1,358	)		7,480			(2,221	)		5,259
	Royalties				(47,319	)		1,558			—			(45,761	)		6,473			(39,288	)		10,587			(28,701	)
					197,445			(6,085	)		—			191,360			(29,957	)		161,403			(48,997	)		112,406
Expenses:
	Operating				33,955			(1,085	)		—			32,870			(4,958	)		27,912			(8,108	)		19,804
	General and administrative	4	(d)		5,529			(151	)		(880	)		4,498			—			4,498			—			4,498
	Interest	4	(f)		—			—			4,250			4,250			(797	)		3,453			(797	)		2,656
	Dry hole	4	(e)		507			—			(507	)		—			—			—			—			—
	Lease rentals	4	(e)		2,175			(70	)		(2,105	)		—			—			—			—			—
	Geological and geophysical	4	(e)		848			—			(848	)		—			—			—			—			—
	Gain (Loss) on sale of property				134			—			(134	)		—			—			—			—			—
	Depletion and depreciation	4	(e)		37,459			(1,020	)		27,039			63,478			(10,043	)		53,435			(16,427	)		37,008
	Site restoration				1,057			(29	)		2,370			3,398			(578	)		2,820			(946	)		1,874
					81,664			(2,354	)		29,185			108,494			(16,376	)		92,118			(26,278	)		65,840
Earnings before Taxes					115,781			(3,731	)		(29,185	)		82,866			(13,581	)		69,285			(22,719	)		46,566
Income and Other Taxes		4	(g)
Current taxes					15,838			(510	)		(15,328	)		—			—			—			—			—
Future income taxes					32,029			(1,032	)		(30,997	)		—			—			—			—			—
					47,867			(1,542	)		(46,325	)		—			—			—			—			—
Net Earnings				$	67,914		$	(2,188	)	$	17,140		$	82,866		$	(13,581	)	$	69,285		$	(22,719	)	$	46,566
Net earnings per Trust Unit
	Basic												$	2.09					$	2.15					$	1.88
	Diluted	5											$	2.09					$	2.15					$	1.88

See accompanying notes to pro forma consolidated financial statements

F-28

PARAMOUNT ENERGY TRUST
Notes to Pro forma Consolidated Financial Statements
(dollar amounts in Cdn$ except as noted)

1. Paramount Energy Trust:

         Paramount Energy Trust (“PET”) is an unincorporated trust formed under the laws of the Province of Alberta pursuant to a trust indenture dated June 28, 2002, as amended, and whose trustee is Computershare Trust Company of Canada. The beneficiaries of PET are the holders of the Trust Units of PET (the “Unitholders”). PET was established for the purposes of issuing Trust Units and acquiring and holding royalties and other investments. The consolidated assets of PET consist of cash of $200 held directly and through 100 percent ownership of Paramount Energy Operating Corp. (the “Administrator”) and the ownership of 100 percent of the beneficial interests of Paramount Operating Trust (“POT”). PET will utilize a calendar fiscal year for financial reporting purposes.

         The Administrator was incorporated primarily to act as trustee of POT. As trustee of POT, the Administrator will hold legal title to the properties and assets of POT on behalf of and for the benefit of POT and will administer, manage and operate the oil and gas business of POT. In addition, the Administrator will provide certain management and administrative services for PET and its trustee pursuant to a delegation of power and authority to it under the PET indenture.

         Subject to and following the issuance of a receipt for a prospectus, PET, POT, the Administrator and Paramount Resources Ltd. (“PRL”) will complete a series of transactions pursuant to which PET, on a consolidated basis, will acquire oil and gas properties and related assets with an estimated value of $301,000,000 from PRL assuming PET raises equity of $150,000,000 from the exercise of rights and obtains bank financing of $100,000,000, as follows:

• PRL will, effective July 1, 2002, sell its interest in certain assets (the “Initial Assets”) to POT for consideration consisting of a promissory note in PRL’s favor of approximately $81,000,000. Interest on the $81,000,000 purchase price will accrue at a rate of 6.5% per annum. At that time a secured guarantee will be given by both POT and PET in respect of $20,000,000 of PRL’s indebtedness to PRL’s lenders. At the same time PRL and POT will execute the Take-Up Agreement which requires PRL to sell and POT to purchase up to 100 percent of PRL’s interest in certain additional assets (the “Additional Assets”). Assuming the acquisition of 100% of PRL’s interest in the Additional Assets, the purchase price will be approximately $220,000,000. POT will pay a $5,000,000 deposit on the purchase price of these assets through the issuance of a non-interest bearing promissory note;

• POT will, effective July 1, 2002, grant to PET a royalty of 99 percent of the net revenue less permitted deductions with respect to debt payments, capital expenditures and certain other amounts from the Canadian resource properties comprised in the Initial Assets and all after-acquired Canadian resource properties of POT including the Additional Assets described below (the “Royalty”) in exchange for consideration consisting of $64,152,000 to be paid in accordance with an agreement between POT, PET and PRL whereby PET will issue and deliver to PRL a first promissory note in the amount of $30,000,000 and a second promissory note in the amount of $34,152,000. The first promissory note will bear annual interest equal to the prime rate of a major Canadian chartered bank from time to time plus 1.875%.

F-29

PARAMOUNT ENERGY TRUST
Notes to Pro forma Consolidated Financial Statements
(dollar amounts in Cdn$ except as noted)

	This payment will reduce the amount of indebtedness that POT owes to PRL to approximately $16,848,000 which will be represented by a promissory note that will bear annual interest from the date of issue equal to the prime rate of a major Canadian chartered bank from time to time plus 1.875%. PET will grant a security interest to PRL in PET’s assets as security for its indebtedness under the first promissory note and POT will grant a guarantee to PRL for such indebtedness and will grant to PRL a security interest over its assets for the guarantee. Because PET is not a party to the sale agreement between PRL and POT for the Initial Assets and PRL is not a party to the royalty agreement between PET and POT for the Royalty, promissory notes were necessary in order to complete the sale agreement as an intermediary step to give title to POT so POT could create the Royalty;
•	PET will issue 6,636,045 Trust Units to PRL in full repayment of the indebtedness under the second promissory note;
•	PET will purchase from PRL the remaining $16,848,000 indebtedness owed by POT to PRL in exchange for the issuance and delivery to PRL of an additional 3,273,721 Trust Units;
•	PRL will, by way of a dividend, distribute all of the PET Trust Units held by PRL, being all 9,909,767 of the Trust Units that PRL will then hold, to the holders of PRL common shares;
•	PET will issue to each of the holders of the Trust Units distributed by PRL, three rights to subscribe for additional PET Trust Units. Each right will entitle the holder to purchase one additional PET Trust Unit at a subscription price of $5.05 per Trust Unit; and
•	PRL will, effective July 1, 2002, sell to POT up to 100 percent of PRL’s interest in the Additional Assets for an aggregate consideration (assuming the acquisition of 100 percent) of approximately $220,000,000. If all of the rights are exercised, proceeds of $150,132,970 (before issue costs) will be raised under the offering and these proceeds, together with bank financing of $100,000,000 will be used to repay the $30,000,000 promissory note to PRL and to complete the acquisition of the Additional Assets.

2. Basis of presentation:

         The accompanying pro forma consolidated balance sheet of PET as at June 30, 2002 and the pro forma consolidated statements of earnings of PET for the six month period ended June 30, 2002 and the year ended December 31, 2001 have been prepared by management of the Administrator (as agent for the trustee of PET) on behalf of PET in accordance with Canadian generally accepted accounting principles. In the opinion of management, the unaudited pro forma consolidated balance sheet and statements of earnings include all adjustments necessary for the fair presentation of the proposed transactions in accordance with Canadian generally accepted accounting principles (“Canadian GAAP”).

         The pro forma consolidated financial information may not be indicative of the financial position and results of operations that would have occurred if the transactions described above had been completed on the dates indicated in these pro forma financial statements or the financial position or operating results which may be obtained in the future.

F-30

PARAMOUNT ENERGY TRUST
Notes to Pro forma Consolidated Financial Statements
(dollar amounts in Cdn$ except as noted)

         Canadian GAAP differs in certain respects from those in the United States. These differences, as they are expected to be applicable to PET, are described in note 5.

         These pro forma financial statements are based upon the historic financial statements for PRL’s activities in northeastern Alberta. While certain of PRL’s properties in northeastern Alberta are not among the properties that are being acquired by PET, the historical financial statements of PRL’s oil and gas activities in northeast Alberta have been prepared to include all of the properties in this core area (the “Northeast Alberta Properties”).

         These pro forma financial statements present three scenarios assuming the exercise of 50 percent, 75 percent and 100 percent of the Rights, respectively. Shareholders who will beneficially own or exercise control or direction over, directly or indirectly, 4,931,787 Trust Units issued on the acquisition of the Initial Assets (49.77% of the issued and outstanding Trust Units) have entered into a Rights exercise agreement (“Rights Exercise Agreement”) with PRL’s lenders which obligates such shareholders to exercise all Rights held by or on behalf of them thereby subscribing for all Trust Units available to them under the Initial Subscription Privilege of the Rights Offering. All proceeds of the Rights Offering and estimated available bank financing are assumed to be applied to acquire a portion of PRL’s interest in the Additional Assets in each scenario. To the extent that less than 100 percent of PRL’s interest in the Additional Assets is acquired, PET intends to acquire a pro rata interest in each of the properties comprising the Additional Assets up to available financing. The agreements for the acquisition of the Initial Assets and the Additional Assets provide that cash flows generated from the activities of the properties for the period from July 1, 2002 to the date of the closing of the acquisitions, net of an amount for interest for the same period, accrue to PET. A portion of the excess of such cash flows, if any over the costs incurred by PET has been applied to the acquisition of the Additional Assets if less than 100% of the rights are exercised. However, as these pro forma consolidated financial statements have been prepared as at June 30, 2002 and for periods ending on or before June 30, 2002 no adjustments have been made in respect of these items.

         It is estimated that the proceeds of the Rights Offering, available bank financing and working capital will allow acquisition of 100 percent, 82.5 percent and 53.7 percent of PRL’s interest in the Additional Assets, assuming exercise of 100 percent, 75 percent and 50 percent of the Rights, respectively.

         These pro forma consolidated financial statements have been prepared using the same accounting policies as those applied by PRL during the applicable periods except as described below.

3. Pro forma Consolidated Balance Sheet:

         The pro forma consolidated balance sheet of PET as at June 30, 2002 is based on the historical balance sheet of PRL’s northeast Alberta core area as at June 30, 2002 and has been prepared assuming that the proposed transactions described in note 2 had been completed on June 30, 2002 resulting in the following:

F-31

PARAMOUNT ENERGY TRUST
Notes to Pro forma Consolidated Financial Statements
(dollar amounts in Cdn$ except as noted)

(a)	The acquisition by PET of natural gas properties in PRL’s northeast Alberta area of activity. The acquired properties will comprise substantially all of PRL’s operation in northeast Alberta other than certain exploration properties, producing gas properties in the Cold Lake Elizabeth area and shut-in gas properties in the Surmont area. The properties not acquired from PRL are referred to herein as the “Excluded Properties”.
(b)	The acquisition of the Initial Assets by POT for consideration of $81,000,000 which, subsequent to the dividend transaction described in note 1, will result in a $30,000,000 promissory note payable to PRL and 9,909,767 Trust Units outstanding.
(c)	The completion of a rights offering for proceeds of $150,132,970 (net proceeds of $149,132,970) after deducting issue costs of $1,000,000 assuming exercise of 100 percent of the Rights. The following table outlines Trust Units issued under each of the Rights exercise scenarios described in note 2:

	Rights Exercised at
	100%		75%		50%
Settlement of PET		1		1		1
Repayment of promissory note arising from acquisition of Initial Assets		6,636,045		6,636,045		6,636,045
Acquisition of indebtedness of POT		3,273,721		3,273,721		3,273,721
Rights Offering		29,729,301		22,296,976		14,864,651
		39,639,068		32,206,743		24,774,418

In order to qualify as a “unit trust” within the meaning of the Tax Act, the Trust Units must have conditions that require PET to accept, at the demand of the Unitholders and at prices determined in accordance with the conditions, the surrender of the Trust Units. Unitholders may redeem their Trust Units at any time by delivering the unit certificates to the Trustee. The redemption amount per Trust Unit properly delivered to the Trustee will be the lesser of 90% of the weighted average trading price of the Trust Units on the principal market on which they are traded for the 10 day period after the Trust Units have been validly tendered and the “closing market price”. The “closing market price” will be the closing price of the Trust Units on the principal market on which they are traded on the date on which they were validly tendered for redemption, or, if there was no trade of the Trust Units on that date, the average of the last bid and ask prices of the Trust Units on that date.

In the event that the aggregate redemption value of Trust Units tendered for redemption in a calendar month exceeds $100,000, the administrator of the Trust may elect to pay the redemption amounts by the issue of promissory notes of PET with an aggregate principal amount equal to the aggregate redemption amount. The promissory notes will be unsecured, will bear interest at a market rate to be determined at the time of issuance, and will be due and payable 5 years after the date of issuance.

F-32

PARAMOUNT ENERGY TRUST
Notes to Pro forma Consolidated Financial Statements
(dollar amounts in Cdn$ except as noted)

	The Trust Units are considered to be an equity instrument, even though the issuer has an obligation to redeem it under certain circumstances, because it constitutes a residual claim on equity subordinate to all other interests in the assets of the Trust. The amounts will be recorded as a financial liability, if and when the holder elects to redeem the Trust Units.
(d)	A syndicate of financial institutions have agreed pursuant to the terms and conditions of a commitment letter to provide PET with a demand revolving credit facility in the maximum amount of $100,000,000 including a $10,000,000 working capital component. The exact amount of such credit facility will be determined by PET’s lenders determination of PET’s borrowing base of oil and gas properties at the Rights Expiry Time and one week prior to the Rights Expiry Time they will provide notice of the borrowing base that would be applicable assuming the exercise of 50%, 75% and 100% of the Rights respectively. The provision of funds by PET’s lenders to it is conditional, among other things, upon the execution of industry standard documentation, customary conditions for a financing of this type and a satisfactory due diligence review. In addition, funding is conditional upon the exercise of all Rights under the Rights Exercise Agreement and the concurrent closing of the Take-Up Agreement and repayment of the $30,000,000 POT will owe to PRL.
	Actual borrowings under the credit facility will be limited to a borrowing base as determined from time to time by the lenders and will bear a rate of interest to be negotiated between PET and its lenders from time to time. PET’s lenders provided estimates on October 15, 2002 of the initial credit availability of $100,000,000, $81,250,000 and $62,500,000, assuming exercise of 100%, 75% and 50% of the Rights respectively based on their assessment of applicable factors and assumptions at that time.
(e)	Under the credit facility PET will pay interest rates and commitment fees on undrawn amounts on typical commercial terms.
(f)	In accordance with generally accepted accounting principles, the acquisitions were recorded in the consolidated statements of PET at their corresponding net book values of $251,269,000, $215,556,000 and $157,112,000 in the consolidated financial statements of PRL at the time of the transfer assuming exercise of 100 percent, 75 percent and 50 percent of the Rights, respectively.
	The excess of the consideration paid over the net book value was recorded as a reduction of unitholders’ equity in each scenario.
(g)	The accounts receivable and accounts payable related to the Northeast Alberta Properties as at July 1, 2002 will not be assumed by PET and they have therefore been eliminated from the pro forma consolidated balance sheet.
(h)	PRL’s hedging activities are a corporate activity and none of the existing PRL hedges will be assumed by PET. All hedging items have therefore been eliminated from the pro forma consolidated balance sheet.

F-33

PARAMOUNT ENERGY TRUST
Notes to Pro forma Consolidated Financial Statements
(dollar amounts in Cdn$ except as noted)

(i)

For income tax purposes, PET is able to, and intends to, claim a deduction for all amounts paid or payable to unitholders, and then to allocate remaining taxable income, if any, to the unitholders. Accordingly no current or future income taxes have been included in the pro forma financial statements. As PET and POT are both Unit Trusts under the Tax Act they will not be subject to Canadian Large Corporations Tax. Accordingly such amounts have not been included in the pro forma financial statements.

(j)

PRL follows the successful efforts method of accounting for its petroleum and natural gas operations. In common with substantially all other Canadian oil and gas royalty trusts, PET will adopt the full cost method of accounting.

4. Pro forma Consolidated Statement of Earnings:

         The pro forma consolidated statements of earnings for the six month period ended June 30, 2002 and the year ended December 31, 2001 have been prepared assuming that the proposed transactions described in note 1 had been completed on January 1, 2001 and that PET was in operation through the periods. The amounts included in these pro forma financial statements have been derived from the historical financial statements of PRL’s northeast Alberta core area for the periods indicated as follows:

(a)	Revenue from the sales of natural gas, royalties and operating costs have been derived from the accounting records of PRL for the applicable periods. PRL is a Canadian petroleum and natural gas resource company involved in the exploration, development and production of petroleum and natural gas in Canada and the United States. The Initial Assets and the Additional Assets comprised approximately 40 percent of PRL’s operations (by production volumes) during the six-month period ended June 30, 2002. The amounts recorded for sales revenue, royalties and operating costs for properties included in the Initial Assets and the Additional Assets were recorded on a property by property basis in the financial records of PRL. The recorded amounts derived from PRL’s records have not been adjusted for purposes of these pro forma financial statements. PET expects to deal with the same or similar natural gas purchasers and industry service providers and on similar terms as PRL had historically with respect to the Northeast Alberta Properties. No other significant operating or contractual arrangements are expected to change to the extent that the revenue or cost structure of the Initial or Additional Assets would be changed materially following their acquisition by PET. The reserves in the Corner and Quigley properties, part of the Additional Assets, are currently dedicated to a gas purchase contract between PRL and a third party cogeneration facility. PRL has advised that it is making arrangements to obtain the consent of such third party to replace the dedicated reserves from Corner and Quigley with reserves from PRL’s other properties. As described in note 2, these pro forma financial statements have been prepared to present the pro forma results of operations applicable to the exercise of 100 percent, 75 percent and 50 percent of the Rights and the respective acquisition of 100 percent, 82.5 percent and 53.7 percent of PRL’s interest in the Additional Assets.
(b)	PRL’s hedging activities are a corporate activity and none of the existing PRL hedges will be assumed by PET. As PET may enter into hedging activities in the future, PRL’s hedging gains and losses have been allocated to the Northeast Alberta Properties based on relative production volumes.
(c)	During 2000, the Alberta Energy and Utilities Board (the “AEUB”) issued a decision regarding the Surmont natural gas bitumen co-production issue. The Surmont property is in northeast Alberta, is not acquired by PET and is one of the Excluded Assets. As a result of this decision, the AEUB ordered the shut-in of approximately 22 mmcf/d of PRL’s production. On February 28, 2002 PRL

F-34

PARAMOUNT ENERGY TRUST
Notes to Pro forma Consolidated Financial Statements
(dollar amounts in Cdn$ except as noted)

	and other Surmont gas producers entered into a Memorandum of Understanding with the Province of Alberta effective May 1, 2000. The Memorandum provided for the compensation of approximately $85 million to be paid to PRL and the other Surmont producers by the Alberta Crown, as well as granting to the Province of Alberta an 11% gross overriding royalty encompassing certain wells, land and leases affected by the shut-in order of May 1, 2000.
	In June 2002, PRL received approximately $47 million from the Province of Alberta as compensation for its proportionate share of the settlement. The cash settlement, net of the book value of associated wells, lands and leases in the affected area, has been recorded as a gain of $37.1 million in net earnings in the current period. As this settlement relates to the Excluded Assets it is not included in the pro forma statements of earnings.
(d)	The amounts included in these pro forma statements of earnings for general and administrative costs have been determined on the basis of an allocation of actual costs incurred by PRL. General and administrative costs of PRL are considered corporate costs and are not allocated or assigned to particular properties. During the six month period ended June 30, 2002 and the year ended December 31, 2001 PRL incurred general and administrative costs, before costs associated with share appreciation rights, of $0.12 per mcf. The amounts recorded in these pro forma statements of earnings have been determined on the basis of $0.12 per mcf of production from the properties included the Initial Assets and the Additional Assets. As PET has a separate Trust Unit incentive plan, the amounts applicable to PRL’s share appreciation rights plan have been excluded from these calculations. POT entered into an agreement (the “Administrative Services Agreement”) effective August 1, 2002 with PRL under which PRL will provide to POT certain administrative, financial, accounting, land management, engineering and other technical services for a transitional period to end on April 1, 2003 and the Administrator on POT’s behalf will provide to PRL certain administrative, financial, accounting, land management, engineering and other technical services relating to the Initial Assets and the Additional Assets and the business and affairs of PRL for a transitional period to end on April 1, 2003. POT will reimburse PRL, and PRL will reimburse POT, for the reasonable expenditures and costs that either incur in rendering such services, including general and administrative costs and expenses. Neither party will charge fees over and above such costs and expenditures. As the operations of PET and its subsidiaries will not differ materially from those of PRL related to the Initial and Additional Assets and the administration of a public oil and gas company, PET’s unit administrative expenses are expected to approximate the historical experience of PRL.
	The personnel required to manage the assets acquired are not expected to vary significantly should less than 100 percent of PRL’s interest in the Additional Assets be acquired. Consequently total pro forma general and administrative expense is held constant assuming exercise of 100 percent, 75 percent and 50 percent of the Rights respectively.
(e)	The amounts recorded for depletion, depreciation and amortization have been based on the costs recorded for the Initial Assets and the Additional Assets, the production volumes during the period and the estimates of proved reserves as at the time of the completion of the transactions. It is assumed that PET will follow the full cost method of accounting for Canadian accounting purposes. As PRL followed the successful efforts method of accounting, the amounts recorded for

F-35

PARAMOUNT ENERGY TRUST
Notes to Pro forma Consolidated Financial Statements
(dollar amounts in Cdn$ except as noted)

	depletion, depreciation and amortization, dry hole costs, lease rentals and geological and geophysical expense in the records of PRL are not directly comparable to or applicable to these pro forma consolidated financial statements.
(f)	The amounts included in these pro forma consolidated statements of operations for interest expense have been based on the bank loans assumed to exist on the completion of the transactions, market interest rates during the period and the interest rate spreads inherent in the proposed bank borrowing facilities of PET. The average amount of bank debt assumed to be outstanding was $100,000,000, $81,250,000 and $62,500,000 assuming exercise of 100 percent, 75 percent and 50 percent of the Rights respectively, for the six-month period ended June 30, 2002 and for the year ended December 31, 2001. This amount does not include amounts relating to the net income of the properties to be received from July 1, 2002 until the completion of the transactions which will be received by PET upon completion of the transactions.
(g)	For income tax purposes, PET is able to, and intends to, claim a deduction for all amounts paid or payable to unitholders, and then to allocate remaining taxable income, if any, to the unitholders. Accordingly no current or future income taxes have been included in the pro forma income statements.

5. Unit Incentive Plan

         PET has adopted a unit incentive plan which permits the Administrator’s board of directors to grant non-transferrable rights to purchase Trust Units (“Incentive Rights”) to its and affiliated entities, employees, officers, directors and other service providers. The purpose of the unit incentive plan is to provide an effective long-term incentive to eligible participants and to reward them on the basis of PET’s long-term performance and distribution. The Administrator’s board of directors will administer the unit incentive plan and determine participants, numbers of Incentive Rights and terms of vesting. The grant price of the Incentive Rights (the “Grant Price”) shall equal the per Trust Unit closing price on the trading date immediately preceding the date of the grant, unless otherwise permitted. The holder of the Incentive Rights may elect to reduce the strike price of the Incentive Rights (the “Strike Price”), such reduction determined by deducting from the Grant Price the aggregate amounts of all distributions on a per Trust Unit basis that PET pays its unitholders after the date of grant which represent a return of more than 2.5% per quarter on PET’s consolidated net fixed assets on its balance sheet at each calendar quarter end. The Strike Price will be adjusted on a quarterly basis and in no case may it be reduced to less than $0.001 per Trust Unit. PET intends to initially grant 970,000 rights to purchase PET Trust Units to directors, officers and employees of the Administrator.

         For purposes of Canadian generally accepted accounting principles, PET will account for the Incentive rights granted to employees or directors of PET and its subsidiaries by the settlement method under which no amount will be recorded at the time the incentive rights are granted. Proceeds received on the exercise of the rights will be added to unitholders’ equity.

         The incentive rights will only be dilutive to the calculation of income per Trust Unit if the exercise price is below the fair value of the unit. Accordingly, for purposes of these pro forma consolidated financial statements, it has been assumed that the incentive rights will not be dilutive.

F-36

PARAMOUNT ENERGY TRUST
Notes to Pro forma Consolidated Financial Statements
(dollar amounts in Cdn$ except as noted)

6. United States generally accepted accounting principles:

         PET’s pro forma consolidated financial statements have been prepared in accordance with generally accepted accounting principles in Canada (“Cdn GAAP”) which differ in some respects to those in the United States (“US GAAP”). The following tables summarize the effects of those differences:

Pro Forma Statement of Earnings

Year Ended December 31, 2001
(Cdn$000)

		Rights @ 100%									Rights @ 75%									Rights @ 50%
		Cdn									Cdn									Cdn
		GAAP			Adjustments			US GAAP			GAAP			Adjustments			US GAAP			GAAP			Adjustments			US GAAP
Revenue:
	Sales of Natural Gas	$	228,283			—		$	228,283		$	193,211			—		$	193,211		$	135,848			—		$	135,848
	Hedging		8,838			4,929			13,767			7,480			4,297			11,777			5,259			3,262			8,521
	Royalties		(45,761	)		—			(45,761	)		(39,288	)		—			(39,288	)		(28,701	)		—			(28,701	)
			191,360			4,929			196,289			161,403			4,297			165,700			112,406			3,262			115,668
Expenses:
	Operating		32,870			—			32,870			27,912			—			27,912			19,804			—			19,804
	General and Administrative		4,498			—			4,498			4,498			—			4,498			4,498			—			4,498
	Interest		4,250			—			4,250			3,453			—			3,453			2,656			—			2,656
	Dry Hole		—			507			507			—			442			442			—			336			336
	Lease Rentals		—			2,105			2,105			—			1,835			1,835			—			1,393			1,393
	Geological and Geophysical		—			848			848			—			739			739			—			561			561
	Loss on Sale of Property		—			134			134			—			117			117			—			89			89
	Depletion and Depreciation		63,478			(927	)		62,551			53,435			(780	)		52,655			37,008			(540	)		36,468
	Site Restoration		3,398			—			3,398			2,820			—			2,820			1,874			—			1,874
			108,494			2,667			111,162			92,118			2,353			94,472			65,840			1,839			67,679
Net Earnings			82,866			2,262			85,127			69,285			1,944			71,228			46,566			1,423			47,989
Net Earnings per Trust Unit
	Basic	$	2.09					$	2.15		$	2.15					$	2.21		$	1.88					$	1.94
	Diluted	$	2.09					$	2.15		$	2.15					$	2.21		$	1.88					$	1.94

Six Months Ended June 30, 2002
(Cdn$000)

		Rights @ 100%									Rights @ 75%									Rights @ 50%
		Cdn									Cdn									Cdn
		GAAP			Adjustments			US GAAP			GAAP			Adjustments			US GAAP			GAAP			Adjustments			US GAAP
Revenue:
	Sales of Natural Gas	$	55,131			—		$	55,131		$	47,475			—		$	47,475		$	34,954			—		$	34,954
	Hedging		10,709			12,139			22,848			9,222			10,582			19,804			6,790			8,034			14,824
	Royalties		(9,366	)		—			(9,366	)		(8,146	)		—			(8,146	)		(6,151	)		—			(6,151	)
			56,474			12,139			68,613			48,551			10,582			59,133			35,593			8,034			43,627
Expenses:
	Operating		15,977			—			15,977			13,738			—			13,738			10,075			—			10,075
	Surmont Compensation, net		—			—			—			—			—			—			—			—			—
	General and Administrative		2,070			—			2,070			2,070			—			2,070			2,070			—			2,070
	Interest		2,126			—			2,126			1,864			—			1,864			1,437			—			1,437
	Dry Hole		—			218			218			—			190			190			—			144			144
	Lease Rentals		—			1,212			1,212			—			1,056			1,056			—			802			802
	Geological and Geophysical		—			367			367			—			320			320			—			243			243
	Loss on Sale of Property		—			134			134			—			117			117			—			89			89
	Depletion and Depreciation		28,816			(241	)		28,575			24,344			(203	)		24,141			17,030			(142	)		16,888
	Site Restoration		1,522			—			1,522			1,264			—			1,264			843			—			843
			50,511			1,690			52,201			43,280			1,480			44,760			31,455			1,136			32,591
Net Earnings			5,963			10,449			16,413			5,271			9,102			14,373			4,138			6,898			11,036
Net Earnings per Trust Unit
	Basic	$	0.15					$	0.41		$	0.16					$	0.45		$	0.17					$	0.45
	Diluted	$	0.15					$	0.41		$	0.16					$	0.45		$	0.17					$	0.45

F-37

PARAMOUNT ENERGY TRUST

Pro Forma Balance Sheet as at June 30, 2002

			Rights @ 100%							Rights @ 75%								Rights @ 50%
			Cdn							Cdn							Cdn
			GAAP		Adjustments			US GAAP		GAAP		Adjustments			US GAAP			GAAP		Adjustments			US GAAP
Property, Plant and Equipment	(a	)	$	251,269	$	(1,690	)	$	249,579	$	215,556	$	(1,480	)	$	214,076		$	157,112	$	(1,136	)	$	155,976
Unitholders’ Equity	(b	)	$	144,921	$	(1,690	)	$	143,231	$	111,333	$	(1,480	)	$	109,853		$	79,960	$	6,898		$	77,824

(a)	Accounting for Petroleum and Natural Gas Operations
	PRL follows the successful efforts method of accounting for its petroleum and natural gas operations. In common with substantially all other Canadian oil and gas royalty trusts, PET will adopt the full cost method of accounting for preparation of its consolidated financial statements in accordance with Canadian generally accepted accounting principles. Under US GAAP, it is only permissible to change an accounting policy if it can be demonstrated that the new accounting policy would be preferable, either through reference to authoritative literature, or on the basis of a change in the circumstances applicable to the entity. As the acquisition of the Initial Assets and the Additional Assets would be considered to be a reorganization of a portion of the operations of PRL, the adoption of the full cost method of accounting would be considered a change in accounting policy for US GAAP purposes. Accordingly, for US GAAP, it has been assumed that PET will follow the successful efforts method of accounting as described in the historical financial statements of the Northeast Alberta Properties.
(b)	Classification of Unitholders’ Equity
	Under US GAAP, the amount included on the pro forma balance sheet for unitholders’ equity would be reduced by an amount equal to the redemption value of the units as at the balance sheet date. As the redemption value is dependent on the trading value of the units as at the date they are presented for redemption and for a period thereafter, and the trust units do not yet have a trading value, it is not possible to determine the amount that would have been recorded as a liability if the transaction had been completed as at June 30, 2002. However, if the units had been trading at prices at or above the average book value per unit substantially all of the amount included in unitholders’ equity would have been reclassified as a liability. Accordingly, in future periods the amount recorded for permanent equity would be limited to the excess or deficiency of cumulative earnings over cumulative distributions less the difference between the excess of the redemption value of the units over the amount otherwise recorded. In addition, if the aggregate redemption value of the outstanding units is in excess of the amount of unitholders equity recorded on the balance sheet, it would be necessary to increase the balance to eliminate the difference with an offsetting entry to permanent equity. The charge during a period would be reflected in computing earnings available to unitholders.
(c)	Accounting for Derivative Instruments and Hedging Activities (FAS 133):
	Under US GAAP, PET is required commencing January 1, 2001 to account for derivative instruments and hedging activities in accordance with FAS 133 which requires that all derivatives be recognized as assets and liabilities on the balance sheet and measured at fair value. Gains or

F-38

PARAMOUNT ENERGY TRUST

Pro Forma Balance Sheet as at June 30, 2002

	losses, including unrealized amounts, on derivatives that have not been designated as hedges, or were not effective as hedges, are included in income as they arise.
	For derivatives designated as fair value hedges, changes in the fair value are recognized in earnings together with equal or lesser amounts of changes in the fair value of the hedged item.
	For derivatives designated as cash flow hedges, changes in the fair value of the derivatives are recognized in other comprehensive income until the hedged items are recognized in earnings. Any portion of the change in the fair value of the derivatives that is not effective in hedging the changes in future cash flows is included in earnings each period. As PRL did not contemplate the preparation of US GAAP financial statements at the time the derivative instruments were entered into, and the required hedge accounting documentation was not prepared, the derivatives entered into by PRL did not qualify as hedges for US GAAP purposes. As described above, gains or losses including unrealized amounts on the portion of PRL’s derivatives allocated to the Initial and Additional Assets are included in income as they arise under US GAAP. As none of the derivative contracts of PRL as at June 30 are to be acquired by PET, there are no associated adjustments to the pro forma consolidated balance sheet.
(d)	Unit Incentive Plan:
	FAS 123, “Accounting for Stock-Based Compensation”, establishes financial accounting and reporting standards for stock-based employee compensation plans as well as transactions in which an entity issues its equity instruments to acquire goods or services from non-employees. As permitted by the FAS 123, PET has elected to follow the intrinsic value method of accounting for stock-based compensation arrangement, as provided for in Accounting Principles Board Opinion 25 (“APB 25”).
	For purposes of Canadian generally accepted accounting principles, PET will account for the incentive rights granted to employees or directors of PET and its subsidiaries by the settlement method under which no amount will be recorded at the time the incentive rights are granted. Proceeds received on the exercise of the rights will be added to unitholders’ equity. For purposes of United States generally accepted accounting principles, the incentive rights will be accounted for by the variable plan method of accounting. In each quarter, the excess if any, of the fair value of the Trust Units over the exercise price as at the end of the quarter will be determined and recorded as a charge to earnings over the remaining vesting period.
(e)	Future Removal and Site Restoration Costs:
	Beginning on January 1, 2003, PET will be required to adopt FASB Statement No. 143 “Accounting for Asset Retirement Obligations” (“FAS 143”), which addresses financial accounting and reporting for obligations associated with the retirement of tangible costs. The standard applies to legal obligations associated with the retirement of long-lived assets that result from the acquisition, construction, development and use of the asset. FAS 143 requires that the fair value of a liability for an asset retirement obligation be recognized in the period in which it is incurred if a reasonable estimate of fair value can be made. The fair value is added to the carrying amount of

F-39

PARAMOUNT ENERGY TRUST

Pro Forma Balance Sheet as at June 30, 2002

	the associated asset. The liability is accreted at the end of each period through charges to operating expenses.
	The amount recorded for future removal and site restoration costs in these pro forma consolidated financials statements has been determined providing for the estimated future site restoration costs (undiscounted) on a unit of production basis over the life of the associated properties. It is expected that the application of FAS 143 will result in an increase in the amount of the liability recorded for future site restoration costs, and an increase in the carrying amount of the assets for the costs that would have been recorded less any applicable depletion and depreciation. The difference will be recorded as at January 1, 2003 as a cumulative catch up adjustment to income. The amount of these changes has not yet been determined.
(f)	Impairment or Disposal of Long Term Assets:
	In August 2001, the FASB issued Statement No. 144 “Accounting for the Impairment or Disposal of Long-term Assets” (“FAS 144”), which addresses the financial accounting and reporting for the impairment or disposal of long-lived assets. FAS 144 supersedes but retains the basic principle of Statement No. 121 for the impairment of assets to be held and used. Assets to be disposed of through abandonment or an exchange for similar productive assets will be classified as held for use until they cease to be used. FAS 144 establishes criteria that must be met in order to classify an asset or group as held for sale. Assets classified as held for sale will be measured at the lower of their carrying amount or fair value less cost to sell, and depreciation will cease when the asset or group is classified as held for sale. FAS 144 broadens the definition of disposals to be presented as discontinued operations to include components of an entity that comprise operating and cash flows that clearly can be distinguished, operationally and for financial reporting purposes from the rest of the entity. While FAS 144 may result in differences in future periods, it does not have any impact on these pro forma financial statements.
(g)	Oil and Gas Reserve Information
	The following table presents the proved reserve quantities and standardized measure of future net cash flows to be acquired under each pro forma scenario at July 1, 2002;

	Initial Assets			Additional Assets									Total Acquired
				Rights @			Rights @			Rights @			Rights @			Rights @			Rights @
				100%			75%			50%			100%			75%			50%
Net proved natural gas reserves (bcf)		38.8			91.5			75.4			49.2			130.3			114.2			88.0
($Cdn000)
Future Cash Inflows	$	124,633		$	272,770		$	224,899		$	146,559		$	397,403		$	349,532		$	271,192
Future Production and Development Costs		(58,127	)		(139,243	)		(114,805	)		(74,815	)		(197,370	)		(172,932	)		(132,942	)
Future Net Cash Flows		66,506			133,527			110,094			71,744			200,033			176,600			138,250
Deduct: 10% Annual Discount Factor		(18,433	)		(30,482	)		(25,133	)		(16,378	)		(48,915	)		(43,566	)		(34,811	)
Standardized Measure of Future Net Cash Flows	$	48,073		$	103,045		$	84,961		$	55,366		$	151,118		$	133,034		$	103,439

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Appendix “A”
FAIRNESS OPINION

Scotia Capital intends to provide its opinion, generally, in the form set forth below, at the time that the final Prospectus is filed with applicable regulatory authorities. The delivery of such an opinion is contingent upon there being no changes or circumstances, currently unknown to Scotia Capital or which may arise, which alone or in connection with other facts, changes or circumstances respecting the Reorganization, Paramount, PET or general economic financial or business conditions impact upon Scotia Capital’s ability to provide such an opinion.

•, 2002

THE SPECIAL COMMITTEE OF THE BOARD OF DIRECTORS
PARAMOUNT RESOURCES LTD.
4700 Bankers Hall West
888 – 3 Street S.W.
Calgary, Alberta
T2P 5C5

Attention: Mr. John B. Roy
Chairman of the Special Committee

To the Special Committee:

Reorganization of Paramount Resources Ltd. through the
Creation of Paramount Energy Trust and Related Transactions

Scotia Capital Inc. (“Scotia Capital”) understands that Paramount Resources Ltd. (together with its subsidiaries, affiliates and associates, unless the context otherwise requires, “Paramount”) has proposed a reorganization involving the sale of certain of its properties to a newly formed public trust (the “Reorganization”). Under the Reorganization, Paramount will distribute all of the outstanding trust units (“Units”) of Paramount Energy Trust (“PET”) to the holders of common shares (“Common Shares”) of Paramount of record on •, 2002 (the “Dividend Record Date”) by means of a dividend-in-kind (the “Dividend”) on the basis of one Unit for approximately each six Common Shares. After the distribution of the Dividend, PET will issue transferable rights (“Rights”) to holders of Units of record on •, 2002 entitling the holders of Rights (“Rightsholders”) to subscribe for Units (the “Rights Offering”).

Each Unitholder will receive three Rights for each Unit held. Each Right will entitle the Rightsholder to subscribe for one Unit at a price of $5.05 per Unit (the “Rights Exercise Price”) until 4:30 p.m. Calgary time on •, 2002 (the “Rights Expiry Time”). Under the terms of the Take-Up Agreement (as described below), Paramount Operating Trust (“POT”) will agree to use the net proceeds of the Rights Offering together with bank financing to acquire from Paramount the Additional Assets (as described below). Assuming all Rights are exercised, PET will raise gross proceeds of approximately Cdn.$150 million under the Rights Offering.

In order to implement the Reorganization, PET, POT and Paramount Energy Operating Corp. (the “Administrator”) will be formed. PET holds the beneficial interests in POT and the Administrator is the trustee of POT and the

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administrator of PET. The Dividend and Rights Offering components of the Reorganization will be undertaken following a series of steps or transactions, including:

• Paramount’s conveyance to POT under a sale agreement (the “Sale Agreement”) of its entire interest in certain natural gas and oil properties and related assets (the “Initial Assets”);

• Paramount’s and POT’s execution of an agreement (the “Take-Up Agreement”) which, subject to certain conditions, entitles and obligates POT to acquire from Paramount, up to 100% of Paramount’s interest in certain natural gas and oil properties and other related assets (the “Additional Assets”) upon completion of the Rights Offering; and

• The grant of a royalty by POT in favour of PET (the “POT Royalty”) under a royalty agreement (the “POT Royalty Agreement”) with respect to the Initial Assets, the Additional Assets and all other natural gas and petroleum properties which POT may acquire and pursuant to which PET will receive 99% of POT’s net revenue from all such petroleum and natural gas properties, less certain permitted deductions.

The distribution of the Units under the Dividend, the distribution of the Rights under the Rights Offering and the offer and sale of the Trust Units issuable on the exercise of such Rights will be qualified in Canada by a final prospectus and in the United States by a registration statement (collectively the “Prospectus”).

The completion and implementation of the Reorganization will be subject to a number of conditions including, completion and execution of all documents and agreements required to give effect to the Reorganization and acceptance and clearance of the Prospectus by the applicable Canadian and United States regulatory authorities. Scotia Capital has assumed that all of the conditions required to implement the Reorganization will be satisfied, and that the Reorganization will be completed in a timely manner as described in the Prospectus substantially in the form and on the terms approved by the Board of Directors of Paramount (the “Board”), and, as evidenced by the agreements, draft agreements and documents reviewed by Scotia Capital, without any material variations or amendments.

Scotia Capital understands that the Reorganization has “related party” considerations given the large indirect holdings in Paramount of the Riddell family and the executive and director positions of family members in each of Paramount and PET. However, we also understand that certain of the related party aspects of the Reorganization are exempt from the application of the valuation and minority approval requirements of Ontario Securities Commission Rule 61-501 and the corresponding policy of the Commission des valeurs mobilières du Québec (collectively the “Rules”), generally on the basis that either the steps occur while PET and POT are wholly-owned by Paramount and all shareholders receive the Dividend in proportion to their holdings in Paramount on the Dividend Record Date and if they still hold their Units on the rights record date they will receive Rights. Although the sale of the Additional Properties by Paramount and the acquisition thereof by POT are not exempt under the Rules as a matter of law, we understand that Paramount has received discretionary relief from the appropriate regulatory authorities which has the effect of also exempting this purchase and sale from the valuation and minority approval requirements of the Rules.

A committee of independent directors (the “Special Committee”) of the Board has been established to, among other things, consider the Reorganization and to report and make recommendations to the Board respecting the Reorganization. The Special Committee has retained Scotia Capital to provide advice and assistance to the Special Committee in connection with the Reorganization, including the preparation and delivery to the Special Committee of its opinion as to the fairness of the Reorganization, from a financial point of view, to holders of Common Shares (the “Opinion”). Scotia Capital has not been asked to prepare, and has not prepared, a formal valuation of Paramount or PET, or any of their respective securities or assets, and the Opinion should not be construed as such.

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Engagement

Scotia Capital was formally engaged by the Special Committee pursuant to an agreement between Paramount and Scotia Capital dated May 13, 2002 (the “Engagement Agreement”). Pursuant to the Engagement Agreement, Scotia Capital has been retained to perform certain financial advisory services on behalf of the Special Committee. The terms of the Engagement Agreement provide that Scotia Capital is to be paid fees for these professional services. In addition, Scotia Capital is to be reimbursed for reasonable out-of-pocket expenses and is to be indemnified by Paramount under certain circumstances with respect to its engagement.

Subject to the terms of the Engagement Agreement, Scotia Capital will be asked to consent to the inclusion of the Opinion in its entirety, together with a summary thereof, in a form acceptable to Scotia Capital, in the Prospectus and to the filing thereof with the Toronto Stock Exchange, securities commissions or similar regulatory authorities in each province of Canada where such filing is required and with the Securities Exchange Commission in the United States.

Credentials of Scotia Capital

Scotia Capital is one of Canada’s largest investment banking firms with operations in all facets of corporate and government finance, mergers and acquisitions, equity and fixed income, sales and trading and investment research. Scotia Capital has participated in a significant number of transactions involving private and public companies, trusts and royalty trusts and has extensive experience in preparing valuations and fairness opinions.

The Opinion expressed herein represents the opinion of Scotia Capital as a firm and the form and content hereof has been approved for release by a committee of directors and other professionals of Scotia Capital, each of whom is experienced in merger, acquisition, divestiture, fairness opinion and valuation matters.

Independence of Scotia Capital

None of Scotia Capital, its associates or affiliates, is an insider, associate or affiliate (as those terms are defined in the Securities Act (Alberta)), or a related entity of Paramount, or any of its associates or affiliates. Scotia Capital has not provided any financial advisory services or participated in any equity financing involving Paramount or its associates or affiliates, of a material nature, within the past two years, other than the services provided under the Engagement Agreement which are described above.

The Bank of Nova Scotia (“BNS”), the sole shareholder of Scotia Capital, is one of five lenders in Paramount’s banking syndicate, the agent bank of which is another Canadian chartered bank. BNS has been a participant in this syndicate since April, 2001. BNS is also one of three participants in the acquisition credit facilities for Paramount in respect of the acquisition of Summit and has committed to participate in a credit facility for PET and POT. While the majority of the terms and conditions are considered standard for a transaction of this nature, the final amount, pricing and some terms of the credit facility will be determined upon completion of the Rights Offering and will, in some respects, be conditional upon the ultimate success of the Rights Offering. The fees paid or which remain payable in connection with these credit facilities are not material to BNS. At this time, the fees remaining to be paid relate solely to BNS’s participation in the facility for the Summit acquisition and are not related to the Reorganization or the Opinion prepared by Scotia Capital.

Scotia Capital may also, in the future, in the ordinary course of its business, perform or continue to perform financial advisory, investment banking or banking services for Paramount, PET or any of their respective associates or affiliates. Scotia Capital does not believe that any of these relationships affects Scotia Capital’s independence with respect to the Opinion.

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Scotia Capital acts as a trader and dealer, both as principal and agent, in major financial markets and, as such, may have had positions in the securities of Paramount and, from time to time, may have executed transactions on behalf of such companies or clients for which it received or may receive compensation. As an investment dealer, Scotia Capital conducts research on securities and may, in the ordinary course of its business, provide research reports and investment advice to its clients on investment matters, including with respect to Paramount or PET or for any of their respective associates or affiliates, other interested parties or with respect to the Reorganization.

Scope of Review

In connection with the Opinion, Scotia Capital has reviewed and relied upon or carried out, among other things, the following:

a)	the First Amended and Restated PET Trust Indenture made effective as of August 1, 2002, which amended and restated the Trust Indenture dated June 28, 2002, as amended and restated, among BMO Nesbitt Burns Inc., as settlor, and Computershare Trust Company of Canada, as trustee, and the Administrator;
b)	the First Amended and Restated POT Trust Indenture made effective as of August 1, 2002, which amended and restated the Trust Indenture dated June 28, 2002, as amended and restated, between CIBC World Markets Inc., as settlor, and the Administrator, as trustee;
c)	the PET preliminary prospectus dated August 15, 2002;
d)	the PET registration statement dated August 15, 2002;
e)	the Prospectus;
f)	the Sale Agreement effective as of July 1, 2002 between Paramount and the Administrator as trustee of POT;
g)	the Take-Up Agreement effective as of July 1, 2002 between Paramount and the Administrator as trustee of POT;
h)	the Royalty Agreement effective as of July 1, 2002 between PET and POT;
i)	the draft Funding Agreement between Computershare Trust Company of Canada as trustee of PET by its agent, the Administrator, the Administrator as trustee of POT and Paramount;
j)	a copy of the PET Unit Incentive Plan dated as of •, 2002;
k)	the audited annual financial statements and annual reports of Paramount for each of the last three fiscal years ending December 31, 2001 and the first quarter report of Paramount for 2002;
l)	the audited financial statements of Summit, for each of the last three fiscal years ending December 31, 2001 and the first quarter report of Summit for 2002;
m)	the Paramount Annual Information Form dated March 22, 2002;
n)	the Summit Annual Information Form dated March 19, 2002;
o)	the Audited Balance Sheet, the Audited Schedule of Revenue and Operating Costs, the Compilation Report and the Pro Forma Consolidated Financial Statements of PET (the “Pro Forma Statements”);

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p)	the financial forecast of PET for the year ending December 31, 2003 and the auditors report thereon dated August 15, 2002 (the “Financial Forecast”);
q)	information regarding Paramount’s oil and gas assets, including the reserve report prepared by McDaniel & Associates Consultants Ltd., an independent oil and gas reservoir engineering firm, effective January 1, 2002 and an update with respect to the Initial Assets and the Additional Assets as of July 1, 2002;
r)	the Update of Unproven Acreage Interests as of July 1, 2002 relating to the Initial Assets and the Additional Assets prepared for Paramount by McDaniel & Associates Consultants Ltd.;
s)	information regarding Summit’s oil and gas assets, including the reserve report prepared by Sproule Associates Limited, an independent oil and gas reservoir engineering firm, effective January 1, 2002;
t)	the 2002 and 2003 Paramount budgets prepared by management of Paramount;
u)	the 2002 and 2003 PET budgets prepared by management of PET;
v)	the draft commitment letter and summary of terms and conditions between Computershare Trust Company of Canada, as trustee of PET as borrower and the Administrator, as trustee of POT, as guarantor, and a syndicate of Canadian chartered banks as of August 1, 2002;
w)	other public information relating to the business, operations, financial performance of Paramount, Summit, and other selected public companies that we considered relevant;
x)	other non-public information regarding Paramount and its business operations and prospects including unaudited updated financial information prepared by the management of Paramount;
y)	public information relating to the business operations, financial performance, stock trading history and management contracts of publicly traded trusts similarly constituted or comparable to PET ;
z)	current and forward commodity price trading information and commodity price forecasts of independent engineering firms;
aa)	discussions with senior management of Paramount;
bb)	discussions with the Special Committee;
cc)	memorandum prepared by, and discussions with legal and tax advisors to Paramount and the Special Committee;
dd)	an application dated May 31, 2002 from Paramount to the Ontario Securities Commission and the Commission des valeurs mobilières du Québec seeking exemption from certain related party transactions between Paramount and PET;
ee)	resolutions and minutes of the Board and the Special Committee respecting the Reorganization;
ff)	such other information, investigations and analyses as we considered necessary or appropriate in the circumstances.

Assumptions and Limitations

This opinion is subject to the assumptions, explanations and limitations expressed below.

With the Special Committee’s approval and as provided for in the Engagement Agreement, Scotia Capital has relied, without independent verification, upon all financial and other information that was obtained by us from

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public sources or that was provided to us by Paramount and its affiliates, associates, advisors or otherwise. We have assumed that this information was complete and accurate and did not omit to state any material fact or any fact necessary to be stated to make that information not misleading. Our Opinion is conditional upon such completeness and accuracy. In accordance with the terms of our engagement, but subject to the exercise of our professional judgment, we have not conducted any independent investigation to verify the completeness or accuracy of such information. With respect to the financial forecasts and budgets provided to us and used in our analysis, we have assumed that they have been reasonably prepared on bases reflecting the best currently available estimates and judgments of management of Paramount and PET and their affiliates and associates as to the matters covered thereby. Senior management of Paramount and PET have represented to us, in certificates delivered as of the date hereof, amongst other things, that the information, opinions and other materials (the “Information”) provided to us by or on behalf of Paramount and PET are complete and correct at the date the Information was provided to us and that since the date of the Information, there has been no material change, financial or otherwise, in the financial position of Paramount or PET, or in their respective assets, liabilities (contingent or otherwise), business or operations and there has been no change in any material fact which is of a nature as to render the Information untrue or misleading in any material respect.

We have, with respect to all legal and tax matters relating to the Reorganization and the implementation thereof, relied upon advice of legal and tax counsel, including as disclosed and discussed with us and as set forth in the Prospectus, and do not express any opinion thereon. Without limitation, we have relied upon the advice of such counsel with respect to the tax consequences upon Paramount, the holders of Common Shares and Units and Rights holders with respect to the various taxable events which occur with respect to the Reorganization. We have assumed that all amounts which will be available for distribution to holders of Units (calculated in the manner set forth in the Financial Forecast) will be distributed to holders of Units. We have also assumed that no material amount of Units will be redeemed by PET in the foreseeable future and that PET will qualify as a “unit trust” as defined by the Tax Act and will continue to qualify thereafter as a “mutual fund trust” as defined in the Tax Act, and that the Units will be qualified investments under the Tax Act for trusts governed by registered retirement savings plans, registered retirement income funds, registered education savings plans and deferred profit sharing plans and will not be foreign property for such plans.

The Opinion is based on the securities markets, economic, general business and financial conditions prevailing as of the date of this Opinion and the conditions and prospects, financial and otherwise, of Paramount and PET as they were reflected in the information reviewed by us. In its analysis and in preparing the Opinion, Scotia Capital has made numerous assumptions with respect to industry performance, general business, financial, market and economic conditions, and other matters, many of which are beyond the control of Scotia Capital, Paramount or PET, or any party involved with Paramount in connection with the Reorganization.

The Opinion has been provided for the use of the Special Committee and for inclusion in the Prospectus (together with a summary thereof in a form acceptable to Scotia Capital) and may not be used by any other person or relied upon by any other person without the express written consent of Scotia Capital. The Opinion is given as of the date hereof and Scotia Capital disclaims any undertakings or obligation to advise any person of any change in any fact or matter affecting the Opinion which may come or be brought to Scotia Capital’s attention after the date hereof. Without limiting the foregoing, in the event that there is any material change in any fact or matter after the date hereof, Scotia Capital reserves the right to change, modify or withdraw the Opinion.

Scotia Capital believes that its analyses must be considered as a whole and that selecting portions of its analyses and specific factors, without considering all factors and analyses together, could create a misleading view of the process underlying the Opinion. The preparation of a fairness opinion is a complex process and is not necessarily

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susceptible to partial analysis or summary description. Any attempt to do so could lead to undue emphasis on any particular factor or analysis. The Opinion should not be construed as a recommendation to acquire Common Shares, Units or Rights, to exercise Rights, or to otherwise trade Common Shares, Rights or Units.

We have not been asked to express herein, and are not expressing herein, any opinion as to the price at which the Common Shares, Units or the Rights will trade during or after the completion of the Reorganization.

Approach to Fairness

In considering the fairness of the Reorganization, from a financial point of view, to the holders of Common Shares, Scotia Capital considered a number of factors including the following:

a)	the expected trading ranges of the Common Shares and Units after the completion of the Reorganization on a fully settled basis together with the value which is potentially obtainable through the exercise or sale of the Rights, as compared to the current and historical trading range of the Common Shares. The extent to which a Paramount shareholder realizes value from the Reorganization may depend upon the nature and timing of that individual’s investment decisions respecting any of the Common Shares, Units or Rights. We believe that the expected trading range for the Units and, indirectly, the Rights, will be influenced principally by cash on cash yield. We also considered other secondary market valuation methodologies or benchmarks applicable to a sample of comparable trusts (in respect of PET), and corporations (in respect of Paramount, both before and following the Reorganization) selected by us and which we consider to be appropriate for this purpose, including those relating to entity value, market capitalization, public float, asset composition, reserve life index, net asset value, leverage, and operations or business. The trading ranges of the Units and Rights could be adversely affected while Units and Rights re-circulate from holders of Common Shares to new investors due to the nature of the Units representing an investment in a trust as compared to an investment in a corporation;
b)	the possible tax consequences of the Reorganization on Paramount and holders of Common Shares;
c)	the net present value of the projected future cash flows for Paramount before giving effect to the Reorganization and for PET and Paramount after giving effect to the Reorganization;
d)	the terms of the Rights Offering which we determined was structured so as to provide a measure of intrinsic value to holders of Units and to maximize the probability of the exercise of the outstanding Rights;
e)	Paramount’s prospects as a stand-alone entity and the limited alternatives to the Reorganization which were considered by Paramount, assuming it did not implement the Reorganization and remained operating under its current and prospective business plan, relative to the Reorganization and the prospects of Paramount and PET following the Reorganization; and
f)	the procedural steps being undertaken in implementing the Reorganization.

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Opinion

Based upon and subject to the foregoing, it is our opinion that, as of the date hereof, the Reorganization is fair, from a financial point of view, to the holders of Common Shares.

Yours truly,

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Dealers Prospectus Delivery Obligation

         Until • [90 days from prospectus date], all dealers that effect transaction in these securities, whether or not participating in this offering may be required to deliver a prospectus.

Part II. Information Not Required In Prospectus

ITEM 6. INDEMNIFICATION OF DIRECTORS AND OFFICERS.

         The PET Trust Indenture provides that, in addition to any other indemnity provided by contract or at law, the Trustee, each of its directors, officers, employees, shareholders and agents and each of their respective heirs, executors, successors and assigns (collectively referred to in this paragraph as the “indemnified parties”) shall be indemnified out of the assets of PET in respect of all liabilities, losses, costs, charges, damages, penalties and expenses (collectively referred to in this paragraph as the “liabilities”) suffered or incurred in respect of any claims or proceedings that are proposed or commenced against any indemnified party for or in respect of acting as or on behalf of PET or the Trustee, any act, omission or error in respect of PET or the carrying out of any Trustee’s duties or responsibilities under the PET Trust Indenture (including any such liabilities relating to environmental matters and issues). However, such indemnification will not be applicable to the indemnified party where any of such liabilities is suffered or incurred as a result of the indemnified party’s own gross negligence, willful misconduct or fraud.

         The PET Trust Indenture provides that the Unitholders (which would include any controlling Unitholder) are indemnified by PET, to the extent of the assets of PET, from any liability in contract or in tort or of any other kind in connection with the assets of PET, the obligations or the affairs of PET, with respect to any act performed by any person pursuant to the PET Trust Indenture, with respect to any act or omission of any person in the performance or exercise, or purported performance or exercise, of any obligation, power, discussion or authority conferred upon any person under the PET Trust Indenture or with respect to any transaction entered into by any person pursuant to the PET Trust Indenture.

         The Administrator and POT have entered into an agreement with the Trustee whereunder the Administrator and POT agree to jointly and severally indemnify the Trustee and each of its directors, officers, employees and agents (collectively referred to in this paragraph as the “indemnified parties) from and against any and all losses, expenses, claims, actions, damages and liabilities, joint or several, including the aggregate amount paid in reasonable settlement of any actions, suits, proceedings, investigations or claims that may be made or threatened against any indemnified party (collectively referred to in this paragraph as the “liabilities”) to which any indemnified party may become subject or otherwise involved in any capacity insofar as the claims relate to or are based upon the Trustee acting as trustee of PET (including any such liabilities relating to environmental matters and issues). These indemnities do not apply to an indemnified party the extent that liabilities have resulted from the gross negligence, fraud or willful misconduct of the indemnified party. This limitation does not apply in respect of matters that are fully delegated to the Administrator or are otherwise the responsibility of the Administrator and do not involve any conduct of the Trustee.

         The PET Trust Indenture provides that, in addition to any other indemnity provided by contract or at law, the Administrator, each of its directors, officers, employees and agents and each of their respective heirs, executors, successors and assigns (collectively referred to in this paragraph as the “indemnified parties”) shall be indemnified out of the assets of PET in respect of all liabilities, losses, costs, charges, damages, penalties and expenses (collectively referred to in this paragraph as the “liabilities”) suffered or incurred in respect of any claims or proceedings that are proposed or commenced against any indemnified party for or in respect of acting or not acting in connection with matters delegated to the Administrator, any act, omission or error in respect of PET or the carrying out of any of the matters delegated to the Administrator under the PET Trust Indenture (including any such liabilities relating to environmental matters and issues). However, such indemnification will not be applicable to an indemnified party to the extent that any of such liabilities is suffered or incurred as a result of the indemnified party’s own gross negligence, willful misconduct or fraud. PET has also entered into separate agreements with each of the directors and officers of the Administrator whereunder PET directly provides the indemnity referred to in this paragraph to each such director and officer.

         Under the terms of the PET Trust Indenture, insurance may be acquired insuring the Trustee, the Administrator and the directors and officers of the Trustee and the Administrator against claims and liabilities asserted by reason of any action alleged to have taken or omitted by PET or by the Administrator.

         The POT Trust Indenture provides that, in addition to any other indemnity provided by contract, the Administrator, each of its directors, officers, employees and agents and each of their respective heirs, executors, successors and assigns (collectively referred to in this paragraph as the “indemnified parties”) shall be indemnified out of

the assets of POT in respect of all liabilities, losses, costs, charges, damages and expenses (collectively referred to in this paragraph as the “liabilities”) suffered or incurred for or in respect of any claims or proceedings that are proposed or commenced against any indemnified party for or in respect of acting as or on behalf of POT or the Administrator, any act, omission or error in respect of POT or the carrying out of any the Administrator’s duties or responsibilities under the POT Trust Indenture (including any such liabilities relating to environmental matters and issues). However, such indemnification will not be applicable to an indemnified party to the extent that any of such liabilities is suffered or incurred as a result of the indemnified party’s own gross negligence, willful misconduct or fraud. POT has also entered into separate agreements with each of the directors and officers of the Administrator whereunder POT directly provides the indemnity referred to in this paragraph to each such director and officer.

         The POT Trust Indenture provides the beneficiary of POT (being PET) as well as the beneficiaries thereof (being the Unitholders of PET and therefore includes a controlling Unitholder) are indemnified by POT, to the extent of the assets of POT, from any liability in contract or in tort or of any other kind in connection with the assets of POT, the obligations or the affairs of POT, with respect to any act performed by any person pursuant to the POT Trust Indenture, with respect to any act or omission of any person in the performance or exercise, or purported performance or exercise, of any obligation, power, discretion or authority conferred upon any person under the POT Trust Indenture or with respect to any transaction entered into by any person pursuant to the POT Trust Indenture.

         Under the terms of the POT Trust Indenture, insurance may be acquired insuring the Administrator, the beneficiary of POT (being PET) and the directors, officers, employees or agents of the Administrator against claims and liabilities asserted by reason of any action alleged to have been taken or omitted by POT, the Administrator or the beneficiary of POT (being PET).

         The By-laws of the Administrator contain provisions which provide that the Administrator shall, to the extent permitted by the Business Corporations Act (Alberta) (“ABCA”), indemnify its officers and directors, former officers and directors, or persons who act or acted at the Administrators’ request as a director or officer of a company of which the Administrator is a shareholder or creditor, and their heirs and legal representatives, and to purchase and maintain insurance for the benefit of any officers or directors as such, as the board of directors of the Administrator may determine.

         The Administrator expects to purchase directors’ and officers’ liability insurance for the benefit of its directors and officers.

ITEM 7.   RECENT SALES OF UNREGISTERED SECURITIES.

Not Applicable.

ITEM 8.   EXHIBITS AND FINANCIAL STATEMENT SCHEDULES.

(a) Exhibits

	Sequential
Exhibit #	Page #	Description
1.1*	P.	Dealer Manager Agreement dated August 8, 2002 among Paramount Energy Trust, Paramount Operating Trust, Paramount Energy Operating Corp., Paramount Resources Ltd., and BMO Nesbitt Burns Inc., CIBC World Markets Inc. and FirstEnergy Capital Corp;
2.1**	P.	Form of Initial Assets Purchase Agreement between Paramount Resources Ltd. and Paramount Operating Trust;

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Exhibit	Sequential
#	Page #	Description
2.2**	P.	Form of Take-Up Agreement between Paramount Resources Ltd. and Paramount Operating Trust;
2.3*	P.	Form of Funding Agreement among Paramount Energy Trust, Paramount Operating Trust and Paramount Resources Ltd;
2.4.*	P.	Form of Promissory Note to be issued by Paramount Energy Trust to Paramount Resources Ltd, in the principal amount of $30,000,000;
2.5*	P.	Form of Promissory Note to be issued by Paramount Operating Trust to Paramount Energy Trust in the principal amount of $16,848,000;
2.6	P.	Form of Promissory Note to be issued by Paramount Operating Trust to Paramount Energy Trust in connection with the acquisition of the Additional Assets by Paramount Operating Trust;
2.7	P.	Form of Guarantee to be issued by Paramount Operating Trust to Paramount Resources Ltd.;
2.8	P.	Form of Guarantee to be issued by Paramount Energy Trust and Paramount Operating Trust to certain banks;
3.1*	P.	First Amended and Restated Trust Indenture for Paramount Energy Trust dated effective August 1, 2002 between Computershare Trust Company of Canada and Paramount Energy Operating Corp.;
3.2*	P.	First Amended and Restated Trust Indenture for Paramount Operating Trust dated effective August 1, 2002 between CIBC World Markets Inc. and Paramount Energy Operating Corp.;
4.	—	Included as Exhibits 2.4, 2.5 and 2.6;
5.1**	P.	Opinion of Gowling Lafleur Henderson LLP;
8.1**	P.	Opinion of Felesky Flynn LLP;
8.2**	P.	Opinion of Stikeman Elliott; and
8.3**	P.	Opinion of Carter, Ledyard & Milburn;
10.1*	P.	Form of Royalty Agreement between Paramount Energy Trust and Paramount Operating Trust;
10.2*	P.	Unit Incentive Plan of Paramount Energy Trust;
10.3*	P.	Form of Unit Incentive Agreement;
10.4	P.	Employment Agreement between Paramount Energy Operating Corp. and Clayton Riddell;
10.5*	P.	Commitment Letter dated August 15, 2002 among PET, POT and their lenders;

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Exhibit	Sequential
#	Page #	Description
10.5(a)	P.	First Amending Agreements dated September 30, 2002 to the Commitment Letter among Computershare Trust Company of Canada (as Trustee of PET), the Administrator (as Trustee of POT) and the Lenders;
10.6	P.	Employment Agreement between Paramount Energy Operating Corp. and Susan L. Riddell Rose;
10.7	P.	Employment Agreement between Paramount Energy Operating Corp. and Gary Jackson;
10.8	P.	Employment Agreement between Paramount Energy Operating Corp. and Cameron Sebastian;
10.9	P.	Employment Agreement between Paramount Energy Operating Corp. and Kevin Marjoram;
22.1**	—	The consent of Gowling Lafleur Henderson LLP is included in Exhibit 5.1;
22.2**	—	The consent of Felesky Flynn LLP is included in Exhibit 8.1;
22.3**	—	The consent of Stikeman Elliott is included in Exhibit 8.2;
22.4**	—	The consent of Carter, Ledyard & Milburn is included in Exhibit 8.3;
22.5**	P.	Consent of KPMG LLP;
22.6**	P.	Awareness letter of KPMG LLP;
22.7**	P.	Consent of McDaniel & Associates Consultants Ltd;
99.1*	P.	Administrative Services Agreement dated as of August 1, 2002 between Paramount Resources Ltd. and POT;
99.2*	P.	Indemnity Agreement from the Administrator and POT in favor of Computershare Trust Company of Canada;
99.3*	P.	Form of Indemnity Agreement from the Administrator in favor of the directors and officers of the Administrator;
99.4*	P .	Form of Indemnity Agreement from Paramount Energy Trust in favor of the directors and officers of the Administrator;
99.5*	P.	Form of Indemnity Agreement from POT in favor of the directors and officers of the Administrator.

*  Document previously filed.

** Amendment to previously filed document.

(b) Financial Statement Schedules

Not Applicable

ITEM 9.   UNDERTAKINGS

         The undersigned registrant hereby undertakes to supplement the prospectus, after the expiration of the subscription period, to set forth the results of the subscription offer, the transactions by the Dealer Managers during the subscription period, the amount of unsubscribed securities to be purchased by the Dealer Managers, and the terms of any subsequent reoffering thereof. If any public offering by the Dealer Managers is to be made on terms differing from those

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set forth on the cover page of the prospectus, a post-effective amendment will be filed to set forth the terms of such offering.

         Insofar as indemnification for liabilities arising under the Securities Act of 1933 may be permitted to directors, officers and controlling persons of the registrant pursuant to the foregoing provisions, or otherwise, the registrant has been advised that in the opinion of the Securities and Exchange Commission such indemnification is against public policy as expressed in the Act and is, therefore, unenforceable. In the event that a claim for indemnification against such liabilities (other than the payment by the registrant of expenses incurred or paid by a director, officer or controlling person of the registrant in the successful defense of any action, suit or proceeding) is asserted by such director, officer or controlling person in connection with the securities being registered, the registrant will, unless in the opinion of its counsel the matter has been settled by controlling precedent, submit to a court of appropriate jurisdiction the question whether such indemnification by it is against public policy as expressed in the Act and will be governed by the final adjudication of such issue.

         The undersigned registrant hereby undertakes:

(1)    that for purposes of determining any liability under the Securities Act of 1933, the information omitted from the form of prospectus filed as part of this registration statement in reliance upon Rule 430A and contained in a form of prospectus filed by the registrant pursuant to Rule 424(b)(1) or (4)or 497(h) under the Securities Act shall be deemed to be part of this registration statement as of the time it was declared effective.

(2)     that for the purpose of determining any liability under the Securities Act of 1933, each post-effective amendment that contains a form of prospectus shall be deemed to be a new registration statement relating to the securities offered therein, and the offering of such securities at that time shall be deemed to be the initial bona fide offering thereof.

(3)    to file, during any period in which offers or sales are being made, a post-effective amendment to this registration statement:

(i)	to include any prospectus required by section 10(a)(3) of the Securities Act of 1933;
(ii)	to reflect in the prospectus any facts or events arising after the effective date of the registration statement (or the most recent post-effective amendment thereof) which, individually or in the aggregate represent a fundamental change in the information in the registration statement. Notwithstanding the foregoing, any increase or decrease in volume of securities offered (if the total dollar value of securities offered would not exceed that which was registered) and any deviation from the low or high end of the estimated maximum offering range may be reflected in the form of prospectus filed with the Commission pursuant to Rule 424(b) if, in the aggregate, the changes in volume and price represent no more than a 20% change in the maximum aggregate offering price set forth in the “Calculation of Registration Fee” table in the effective registration statement;
(iii)	to include any material information with respect to the plan of distribution not previously disclosed in the registration statement or any material change to such information in the registration statement;

(4)     that, for the purpose of determining any liability under the Securities Act of 1933, each such post-effective amendment shall be deemed to be a new registration statement relating to the securities offered therein, and the offering of such securities at that time shall be deemed to be the initial bona fide offering thereof.

(5)     to remove from registration by means of a post-effective amendment any of the securities being registered which remain unsold at the
termination of the offering.

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(6)     To file a post-effective amendment to the registration statement to include any financial statements required by Item 8.A of Form 20-F at the start of any delayed offering or throughout a continuous offering. Financial statements and information otherwise required by Section 10(a)(3) of the Securities Act of 1933 need not be furnished, provided that the registrant includes in the prospectus, by means of a post-effective amendment, financial statements required pursuant to this paragraph and other information necessary to ensure that all other information in the prospectus is at least as current as the date of those financial statements.

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SIGNATURES

         Pursuant to the requirements of the Securities Act, the Registrant certifies that it has reasonable grounds to believe that it meets all of the requirements for filing Form F-1 and has duly caused this registration statement to be signed on its behalf by the undersigned, thereunto duly authorized, in the City of Calgary, Alberta, Canada, on November 6, 2002.

PARAMOUNT ENERGY TRUST
By:	Paramount Energy Operating Corp., Administrator
By:	/s/ Clayton H. Riddell
	Clayton H. Riddell Chairman and Chief Executive Officer

POWER OF ATTORNEY

         Each person whose signature appears below hereby constitutes Clayton H. Riddell, Susan L. Riddell Rose, Cameron R. Sebastian, Kurtis T. Kulman and Leslie A. Fryers, and each of them singly, his or her true and lawful attorneys-in-fact with full power to sign on behalf of such person, in the capacities indicated below, any and all amendments to this registration statement and any subsequent related registration statement filed pursuant to Rule 462(b) under the Securities Act of 1933, and generally to do all such things in the name and on behalf of such person, in the capacities indicated below, to enable the Registrant to comply with the provisions of the Securities Act of 1933 and all requirements of the Securities and Exchange Commission thereunder, hereby ratifying and confirming the signature of such person as it may be signed by said attorneys-in-fact, or any of them, to any and all amendments to this registration statement.

         Pursuant to the requirements of the Securities Act, this registration statement has been signed by the following persons in the capacities* and on the dates indicated.

Signature	Capacity	Date
/s/ Clayton H. Riddell Clayton H. Riddell	Chairman, Chief Executive Officer and Director (Principal executive officer)	November 6, 2002

* The Registrant is a trust and the persons (other than the Authorized Representative in the United States) are signing in their capacities as officers or directors of Paramount Energy Operating Corp., the administrator of the Registrant.

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Signature	Capacity	Date
/s/ Cameron R. Sebastian Cameron R. Sebastian	Chief Financial Officer (Principal financial officer and principal accounting officer)	November 6, 2002
/s/ Karen A. Genoway Karen A. Genoway	Director	November 6, 2002
/s/ Donald J. Nelson Donald J. Nelson	Director	November 6, 2002
/s/ John W. Peltier John W. Peltier	Director	November 6, 2002
/s/ Susan L. Riddell Rose Susan L. Riddell Rose	Director	November 6, 2002
/s/ Howard R. Ward Howard R. Ward	Director	November 6, 2002
PARAMOUNT OPERATING (U.S.) CORP.	Authorized Representative in the United States

By: /s/ Clayton H. Riddell
Clayton H. Riddell November 6, 2002

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EXHIBITS TO INDEX

	Sequential
Exhibit #	Page #	Description
1.1*	P.	Dealer Manager Agreement dated August 8, 2002 among Paramount Energy Trust, Paramount Operating Trust, Paramount Energy Operating Corp., Paramount Resources Ltd., and BMO Nesbitt Burns Inc., CIBC World Markets Inc. and FirstEnergy Capital Corp;
2.1**	P.	Form of Initial Assets Purchase Agreement between Paramount Resources Ltd. and Paramount Operating Trust;
2.2**	P.	Form of Take-Up Agreement between Paramount Resources Ltd. and Paramount Operating Trust;
2.3*	P.	Form of Funding Agreement among Paramount Energy Trust, Paramount Operating Trust and Paramount Resources Ltd;
2.4.*	P.	Form of Promissory Note to be issued by Paramount Energy Trust to Paramount Resources Ltd, in the principal amount of $30,000,000;
2.5*	P.	Form of Promissory Note to be issued by Paramount Operating Trust to Paramount Energy Trust in the principal amount of $16,848,000;
2.6	P.	Form of Promissory Note to be issued by Paramount Operating Trust to Paramount Energy Trust in connection with the acquisition of the Additional Assets by Paramount Operating Trust;
2.7	P.	Form of Guarantee to be issued by Paramount Operating Trust to Paramount Resources Ltd.;
2.8	P.	Form of Guarantee to be issued by Paramount Energy Trust and Paramount Operating Trust to certain banks;
3.1*	P.	First Amended and Restated Trust Indenture for Paramount Energy Trust dated effective August 1, 2002 between Computershare Trust Company of Canada and Paramount Energy Operating Corp.;
3.2*	P.	First Amended and Restated Trust Indenture for Paramount Operating Trust dated effective August 1, 2002 between CIBC World Markets Inc. and Paramount Energy Operating Corp.;
4.	—	Included as Exhibits 2.4, 2.5 and 2.6;
5.1**	P.	Opinion of Gowling Lafleur Henderson LLP;
8.1**	P.	Opinion of Felesky Flynn LLP;
8.2**	P.	Opinion of Stikeman Elliott; and
8.3**	P.	Opinion of Carter, Ledyard & Milburn;
10.1*	P.	Form of Royalty Agreement between Paramount Energy Trust and Paramount Operating Trust;
10.2*	P.	Unit Incentive Plan of Paramount Energy Trust;

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	Sequential
Exhibit #	Page #	Description
10.3*	P.	Form of Unit Incentive Agreement;
10.4	P.	Employment Agreement between Paramount Energy Operating Corp. and Clayton Riddell;
10.5*	P.	Commitment Letter dated August 15, 2002 among PET, POT and their lenders;
10.5(a)	P.	First Amending Agreements dated September 30, 2002 to the Commitment Letter among Computershare Trust Company of Canada (as Trustee of PET), the Administrator (as Trustee of POT) and the Lenders;
10.6	P.	Employment Agreement between Paramount Energy Operating Corp. and Susan L. Riddell Rose;
10.7	P.	Employment Agreement between Paramount Energy Operating Corp. and Gary Jackson;
10.8	P.	Employment Agreement between Paramount Energy Operating Corp. and Cameron Sebastian;
10.9	P.	Employment Agreement between Paramount Energy Operating Corp. and Kevin Marjoram;
22.1**	—	The consent of Gowling Lafleur Henderson LLP is included in Exhibit 5.1;
22.2**	—	The consent of Felesky Flynn LLP is included in Exhibit 8.1;
22.3**	—	The consent of Stikeman Elliott is included in Exhibit 8.2;
22.4**	—	The consent of Carter, Ledyard & Milburn is included in Exhibit 8.3;
22.5**	P.	Consent of KPMG LLP;
22.6**	P.	Awareness letter of KPMG LLP;
22.7**	P.	Consent of McDaniel & Associates Consultants Ltd;
99.1*	P.	Administrative Services Agreement dated as of August 1, 2002 between Paramount Resources Ltd. and POT;
99.2*	P.	Indemnity Agreement from the Administrator and POT in favor of Computershare Trust Company of Canada;
99.3*	P.	Form of Indemnity Agreement from the Administrator in favor of the directors and officers of the Administrator;
99.4*	P.	Form of Indemnity Agreement from Paramount Energy Trust in favor of the directors and officers of the Administrator;
99.5*	P.	Form of Indemnity Agreement from POT in favor of the directors and officers of the Administrator.

  *     Document previously filed.

**     Amendment to previously filed document.

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