exv99w1

TABLE OF CONTENTS


	Page
GLOSSARY		1
ABBREVIATIONS		3
CONVERSION		3
SPECIAL NOTE REGARDING FORWARD-LOOKING STATEMENTS		4
PARAMOUNT ENERGY TRUST		5
GENERAL DEVELOPMENT OF THE BUSINESS		6
DESCRIPTION OF THE BUSINESS AND PLAN OF OPERATIONS		8
RECENT DEVELOPMENTS		9
REPORT OF MANAGEMENT AND DIRECTORS ON RESERVES DATA AND OTHER INFORMATION		10
REPORT ON RESERVES DATA		11
STATEMENT OF RESERVES DATA AND OTHER OIL AND GAS INFORMATION		12
RECORD OF CASH DISTRIBUTIONS		30
MARKET FOR SECURITIES		30
ADDITIONAL INFORMATION RESPECTING PARAMOUNT ENERGY TRUST		31
DESCRIPTION OF THE TRUST UNITS AND SPECIAL VOTING UNITS		32
THE ADMINISTRATOR		45
DIRECTORS AND OFFICERS		45
DISTRIBUTION REINVESTMENT AND OPTIONAL UNIT PURCHASE PLAN		49
PROMOTERS		50
LEGAL PROCEEDINGS		50
INTEREST OF INSIDERS AND OTHERS IN MATERIAL TRANSACTIONS		50
AUDITORS, TRANSFER AGENT AND REGISTRAR		50
MATERIAL CONTRACTS		50
INTEREST OF EXPERTS		50
SELECTED CONSOLIDATED FINANCIAL INFORMATION AND MANAGEMENT DISCUSSION AND ANALYSIS FOR THE YEAR ENDED DECEMBER 31, 2003		51
RISK FACTORS		51
GOVERNMENT REGULATIONS		58
CONFLICTS OF INTEREST		60
ADDITIONAL INFORMATION		60

GLOSSARY

In this Initial Annual Information Form, the capitalized terms set forth below have the following meanings:

“ABCA” means the Business Corporations Act (Alberta), together with any or all regulations promulgated thereunder, as amended from time to time;

“Additional Assets” means the oil and natural gas properties and related assets acquired by POT from PRL under the terms of the Take-Up Agreement;

“Administrator” means Paramount Energy Operating Corp., a wholly-owned subsidiary of PET incorporated under the ABCA;

“AECO” is the Western Canadian Sedimentary Basin natural gas pricing benchmark;

“AEUB” means the Alberta Energy and Utilities Board;

“ARTC” means the Alberta Royalty Tax Credit, an Alberta provincial government program under which, in certain circumstances, tax credits may be provided against royalties on oil and gas production payable to the Province of Alberta;

“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;

“Canadian GAAP” means Canadian generally accepted accounting principles;

“C.H. Riddell Family” means C.H. Riddell together with his immediate family, including their spouses;

“Initial Assets” means the entire right, title and interest of PRL in the oil and natural gas properties and related assets acquired by POT from PRL under the terms of the Sale Agreement;

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

“McDaniel Report” means the independent engineering evaluation dated March 8, 2004 of the natural gas reserves and the present worth value of these reserves for the natural gas interests of PET prepared by McDaniel, based on escalating pricing and on constant pricing as at January 1, 2004;

“Ordinary Resolution” means a resolution approved at a meeting of Unitholders by more than 50% of the votes cast;

“PET” or the “Trust” means Paramount Energy Trust, an unincorporated trust formed under the laws of the Province of Alberta pursuant to the PET Trust Indenture. All references to “PET” or the “Trust”, unless the context otherwise requires, are references to Paramount Energy Trust and its subsidiaries;

“PET Assets” means the Initial Assets and the Additional Assets;

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

“POG” means Paramount Oil & Gas Ltd., a corporation incorporated under the ABCA;

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

“POT Royalty” means a contractual royalty of 99% of POT’s net revenue from its petroleum and natural gas properties with respect to the PET Assets and all other petroleum and natural gas properties POT may acquire from time to time less permitted

deductions with respect to debt payments, capital expenditures and certain other amounts, granted by POT to PET pursuant to the POT Royalty Agreement;

“POT Royalty Agreement” means the royalty agreement entered into between POT, as grantor, and PET, as royalty owner, as part of the Trust Structuring;

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

“PRL” means Paramount Resources Ltd., a corporation incorporated under the ABCA;

“PRL Common Share” means a common share in the capital of PRL;

“PRL Shareholders” means holders of PRL Common Shares;

“Rights” means transferable rights qualified for distribution pursuant to the PET prospectus dated January 29, 2003 which entitled a holder of Rights to subscribe for one Trust Unit for each Right held, at a price of $5.05;

“Rights Offering” means the previously completed issuance of Rights to the then holders of Trust Units as described in the PET prospectus dated January 29, 2003;

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

“Royalty Agreements” means, collectively, any and all royalty agreements between PET and any entity, providing for Royalties, including the POT Royalty Agreement;

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

“Sale Agreement” means the purchase and sale agreement, effective July 1, 2002, entered into between PRL and POT as part of the Trust Structuring, pursuant to which POT acquired from PRL 100% of PRL’s interest in the Initial Assets;

“Special Resolution” means a resolution passed at a meeting of Unitholders by more than 66²/₃% of the votes cast;

“Special Voting Units” means special voting units of PET referred to under “Description of the Trust Units and Special Voting Units”;

“Take-Up Agreement” means the purchase and sale agreement, effective July 1, 2002, entered into between PRL and POT as part of the Trust Structuring, pursuant to which POT acquired from PRL 100% of PRL’s interest in the Additional Assets;

“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 conveyed the Initial Assets to POT pursuant to the Sale Agreement; (ii) PRL and POT entered into the Take-Up Agreement; (iii) the POT Royalty was granted by POT to PET; and (iv) all Trust Units held by PRL and later distributed by PRL to PRL Shareholders were issued by PET to PRL, all as further described under “Organization and Structure of the Trust — General Development of the Business - Significant Acquisitions”;

“Trust Units” means the trust units of PET;

“Trustee” means Computershare Trust Company of Canada in its capacity as trustee of PET pursuant to the PET Trust Indenture;

“TSX” means the Toronto Stock Exchange;

“Unit Certificate” means the banknote form of certificate representing the Trust Units;

“Unit Incentive Plan” means the unit incentive plan of PET as described in “Unit Incentive Plan”;

“Unitholder” means the holder of a Trust Unit;

“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;

“U.S. Securities Act” means the United States Securities Act of 1933, as amended; and

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

Words importing the singular number only include the plural, and vice versa, and words importing any gender include all genders. All dollar amounts set forth in this Initial Annual Information Form are in Canadian dollars, except where otherwise indicated.

ABBREVIATIONS


Oil and Natural Gas Liquids		Natural Gas
bbls	barrels	mcf	thousand cubic feet
mbbls	thousand barrels	mmcf	million cubic feet
mmbbls	million barrels	bcf	billion cubic feet
NGLs	natural gas liquids	mcf/d	thousand cubic feet per day
stb	stock tank barrels of oil	mmcf/d	million cubic feet per day
mstb	thousand stock tank barrels of oil	m³	cubic metres
mmboe	million barrels of oil equivalent	mmbtu	million British Thermal Units
boe/d	barrels of oil equivalent per day	GJ	Gigajoule
bbls/d	barrels of oil per day


Other
BOE or boe		means barrel of oil equivalent, using the conversion factor of 6 mcf of natural gas being equivalent to one bbl of oil. The conversion factor used to convert natural gas to oil equivalent is not necessarily based upon either energy or price equivalents at this time.

WTI		means West Texas Intermediate.

°API		means the measure of the density or gravity of liquid petroleum products derived from a specific gravity.

psi		means pounds per square inch.

CONVERSION

The following table sets forth certain conversions between Standard Imperial Units and the International System of Units (or metric units).


To Convert From	To	Multiply By
mcf	cubic metres		28.174
cubic metres	cubic feet		35.494
bbls	cubic metres		0.159
cubic metres	bbls		6.289
feet	metres		0.305
metres	feet		3.281
miles	kilometres		1.609
kilometres	miles		0.621
acres	hectares		0.405
hectares	acres		2.471
gigajoules	mmbtu		0.950

SPECIAL NOTE REGARDING FORWARD-LOOKING STATEMENTS

Certain statements contained in this Initial Annual Information Form, and in certain documents incorporated by reference herein, constitute forward-looking statements. These statements relate to future events or the Trust’s future performance. All statements other than statements of historical fact may be forward-looking statements. Forward-looking statements are often, but not always, identified by the use of the words “anticipate”, “plan”, “continue”, “estimate”, “expect”, “may”, “will”, “project”, “should”, “believe”, “predict”, “targeting”, “seek”, “intend”, “could”, “potential”, “should” and similar expressions. These statements involve known and unknown risks, uncertainties and other factors that may cause actual results or events to differ materially from those anticipated in such forward-looking statements. The Trust and the Administrator believe the expectations reflected in those forward-looking statements are reasonable but no assurance can be given that these expectations will prove to be correct and such forward-looking statements included in this Initial Annual Information Form should not be unduly relied upon. These statements speak only as of the date of this Initial Annual Information Form.

These statements relate to future events or the Trust’s future performance.

In particular, this Initial Annual Information Form contains forward-looking statements pertaining to the following:

• the size of the Trust’s natural gas reserves;

• estimates of future cash flow and distributions;

• projections of market prices and costs and the related sensitivities to distributions;

• natural gas production levels;

• capital expenditure programs;

• supply and demand for natural gas;

• expectations regarding the ability to raise capital and to continually add to reserves through acquisitions and development; and

• treatment under governmental regulatory regimes both existing and proposed.

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

• volatility in market prices for natural gas;

• liabilities inherent in natural gas operations;

• adverse regulatory rulings, orders and decisions;

• uncertainties associated with estimating natural gas reserves;

• competition for, among other things, capital, acquisitions of reserves, undeveloped lands and skilled personnel;

• incorrect assessments of the value of acquisitions;

• geological, technical, drilling and processing problems; and

• the other factors discussed under “Risk Factors”.

These factors should not be construed as exhaustive. None of the Trust, the Administrator nor POT undertakes any obligation to publicly update or revise any forward-looking statements.

PARAMOUNT ENERGY TRUST

Corporate Structure

PET

Paramount Energy Trust (“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 Paramount Energy Operating Corp. (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. PET’s assets consist primarily of the POT Royalty, certain debt owing by Paramount Operating Trust (“POT”) to PET, 100% ownership of the Administrator and the ownership of 100% of the beneficial interest in POT.

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 effectively finances the operations of POT. PET distributes cash to the holders of its Trust Units (“Unitholders”), which will initially be comprised of royalty and interest income PET receives from POT and from ARTC, if any, less any expenses and any other amounts it must withhold or pay to third parties. All Trust Units outstanding from time to time are entitled to an equal undivided share of any distributions from PET. Under the PET Trust Indenture, PET has broad powers to invest funds that are not distributed to Unitholders. See “The PET Trust Indenture”.

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”). POT holds, through the Administrator, all of the oil and gas properties in the trust structure. 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. Pursuant to the POT Royalty, POT pays to PET 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. See “The POT Trust Indenture” and “The POT Royalty Agreement”.

The Administrator

The Administrator was incorporated on June 28, 2002 under the ABCA. All of the issued and outstanding shares of the Administrator are beneficially held by PET. As trustee of POT, the Administrator holds legal title to the assets and properties of POT on behalf of, and for the benefit of, POT and administers, manages and operates the oil and gas business of POT. The Administrator, in its capacity as trustee, retains 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. 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.

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. Only one Class A common share is currently outstanding. That share is held by the Trustee for and on behalf of PET. See “The PET Trust Indenture”, “The POT Trust Indenture” and “The Administrator - Directors and Officers”.

PET’s, POT’s and the Administrator’s head offices are located at 500, 630 — 4th Avenue S.W., Calgary, Alberta, and the Administrator’s registered office is located at 1200, 700 — 2nd Street S.W., Calgary, Alberta.

Organizational Structure of the Trust

The following diagram illustrates the current trust structure of PET, POT and the Administrator:

(CHART)

GENERAL DEVELOPMENT OF THE BUSINESS

History and Development

In April and May of 2002, the board of directors of PRL gave its initial approval to the formation and structuring 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 its 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 of PRL believed the transaction would be financially beneficial to shareholders of PRL. 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. In June of 2002, pursuant to the initial approval of the board of directors of PRL, PET, POT and the Administrator were formed as wholly-owned subsidiaries of PRL.

In January of 2003, the board of directors of PRL gave its final approval to the transaction as well as to the final Canadian prospectus and U.S. registration statement of PET which were prepared to facilitate the transaction. Upon the issuance of the final receipts by Canadian securities regulators for the Canadian prospectus and the effectiveness of the U.S. registration statement under United States securities laws, the following transactions were completed on February 3, 2003:

• POT acquired PRL’s natural gas properties and facilities in the Legend, Alberta area (the Initial Assets) in exchange for the issuance by POT to PRL of an $81 million promissory note. POT assumed all risks on these assets, and revenues and expenses associated with these assets accrued to POT for POT’s account, effective July 1, 2002;

• PRL and POT entered into a purchase and sale agreement whereunder POT agreed to acquire from PRL up to 100% of PRL’s interests in most of its remaining natural gas properties in northeast Alberta (the Additional Assets); and

• POT and PET entered into the POT Royalty Agreement effective July 1, 2002 pursuant to which POT granted the POT Royalty to PET over all of POT’s natural resource properties and all natural resource properties POT may acquire from time to time. As a result of a number of steps completed in connection with the payment of the consideration for the POT Royalty, PET issued 9,909,766 Trust Units to PRL and acquired the remaining $16,848,000 in indebtedness that POT owed to PRL.

Thereafter the board of directors of PRL declared and, on February 12, 2003, paid a dividend-in-kind to the PRL Shareholders of all of the Trust Units PRL received pursuant to the above transactions, on the basis of one Trust Unit for each 6.071646 PRL Common Shares held as of February 11, 2003.

The Trust Units commenced trading on the TSX on a when issued basis on February 7, 2003.

On February 15, 2003, PET issued to holders of its Trust Units, three Rights for every Trust Unit held of record on February 14, 2003. Each Right entitled the holder thereof to acquire one Trust Unit for a price of $5.05 until March 10, 2003. All of the Trust Units offered under the Rights Offering were subscribed for. As a result, on March 11, 2003, PET issued an aggregate of 29,728,609 Trust Units pursuant to the exercise of the Rights and received net aggregate subscription proceeds of $150.1 million.

On March 11, 2003, PET utilized the Rights subscription proceeds as well as the proceeds of bank financing arranged by PET to repay $30.1 million owing by PET to PRL and to acquire from PRL 100% of PRL’s interest in the natural gas assets and facilities provided for in the purchase and sale agreement referred to above for a cash purchase price of $220 million. POT assumed all risks on these assets, and revenues and expenses associated with these assets accrued to POT for POT’s account, effective July 1, 2002.

The acquisitions of the PET Assets from PRL constituted a “significant acquisition” for PET as that term is defined under applicable Canadian securities rules. For a description of the PET Assets, see “Narrative Description of the Business”.

PET completed a bought-deal equity financing on May 30, 2003 raising net proceeds of $60.1 million for the issuance of 5,000,000 Trust Units at $12.65 per Unit. These proceeds were initially used to reduce bank debt and to partially fund the Trust’s 2003 capital expenditure program.

On November 18, 2003, PET acquired all of the outstanding shares of Epact Exploration Ltd. (“Epact”) for $13.3 million plus the assumption of $4.8 million of net debt. Following the concurrent disposition of certain non-strategic Epact assets for $4.4 million, PET retained approximately 3.3 MMcf/d of gas production while establishing a new focus area in southern Alberta. This acquisition was funded through existing credit facilities. Immediately following the acquisition the retained properties were transferred to POT through the wind-up of Epact and dissolution of a related partnership.

C.H. Riddell, the Chairman, Chief Executive Officer and a director of the Administrator, is also the Chairman, Chief Executive Officer and a director of PRL. Susan L. Riddell Rose, the President, Chief Operating Officer and a director of the Administrator, is also a director of PRL. Mr. Riddell and his immediate family beneficially own or exercise control or direction over, directly or indirectly, 49.2% of the outstanding PRL Common Shares and 44.2% of the outstanding Trust Units. See “Conflicts of Interest”.

DESCRIPTION OF THE BUSINESS AND PLAN OF OPERATIONS

Paramount Energy Trust

Our goal is to provide Unitholders with a tax effective vehicle through which we can distribute income and add value through the exploitation of our assets as well as through prudent acquisitions of further assets. The majority of PET’s 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 PET’s assets will be sufficient to fund our production and administrative expenses, interest expenses and capital expenditures and to permit us to accumulate working capital for our on-going operations.

POT’s internal marketing group markets production from these 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. The Administrator currently has 84 full and part-time permanent employees. Many of the technical staff responsible for managing PET’s current assets have done so for a number of years including at PRL. The continuity of this technical team should ensure the continued efficient exploitation of our asset base. See “The Administrator — Employees”.

Exploitation Drilling

We intend to optimize the value of our assets by exploiting the natural gas production potential associated with the Trust’s properties. We will focus our capital expenditures on drilling low risk development wells to maximize production and cash flow. We believe that our 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.

Significant Acquisitions

In addition to pursuing the acquisition of other properties in our core areas we intend to continue to seek corporate and property opportunities focused on natural gas. We also expect to pursue acquisition opportunities which may diversify our current commodity and geographic focus. See “Recent Developments”. 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 per Trust Unit and our cash flow per Trust Unit and which increase our reserve and production base. We will target the acquisition of high quality assets with substantial low risk development potential and low capital requirements. We will not limit our acquisitions by commodity or geography although we presently intend to continue our focus on natural gas assets and plan to finance such acquisitions through debt and equity financings. The Trust is normally in the process of evaluating several potential acquisitions at any one time which individually or together could be material. As of the date hereof, the Trust has not reached agreement on the price or terms of any potential acquisition. The Trust cannot predict whether any current or future opportunities will result in one or more acquisitions being completed by the Trust.

Employees

The Administrator currently has 84 full and part-time permanent employees for the purposes of operating POT’s oil and gas operations. Our employees will also render services to the Trustee and PET. Our employees consist of 54 field employees and 30 office personnel.

RECENT DEVELOPMENTS

Regulatory Rulings

The Alberta Energy and Utilities Board (“AEUB” or the “Board”) issued General Bulletin (“GB”) 2003-28 (the “Bulletin”) on July 22, 2003. The AEUB continues to consider that gas production in pressure communication with associated potentially recoverable bitumen places future bitumen recovery at an unacceptable risk. On January 26, 2004, the AEUB Staff Submission Group (“SSG”) released their recommendations for the shut-in of producing wells with total average daily production of 135 MMcf/d as of August 31, 2003 or approximately one percent of the natural gas production of the Province of Alberta. Pursuant to Interim Shut-in Order 03-001, approximately 95 MMcf/d was shut-in by Industry on September 1, 2003. A shut-in date has not been announced for the remaining 40 MMcf/d recommended for shut-in by the SSG. A total of 24.1 MMcf/d of production net to PET was recommended for shut-in by the SSG which includes 7.6 MMcf/d of the gas shut-in on September 1, 2003 and an additional 16.5 MMcf/d of PET’s production which was previously exempted from Interim Shut-in Order 03-001.

PET submitted substantial technical evidence to the AEUB on February 23, 2004 with respect to the many wells for which the Trust objects to the shut-in recommendations of the AEUB’s SSG. While the task of providing adequate technical evidence to support continued gas production prior to the AEUB deadline was impossible, some evidence was provided for all of PET’s affected assets. AEUB Interim Hearings with respect to this matter began on March 10, 2004. On February 27, 2004 the Alberta Court of Appeal granted a stay of the AEUB hearing process to the extent that it applies to wells for which the productive status was previously determined under AEUB Decision 2003-23 following the Chard/Leismer Hearing. This should exclude 0.7 MMcf/d of PET production from the current proceedings. The Alberta Court of Appeal declined to grant a stay of the March Interim Hearings however PET and others have been granted Leave to Appeal the entire GB 2003-28 process. A date for the hearing of that appeal has not been set.

Until the AEUB determines the final productive status of the wells, PET cannot accurately estimate the amount of production that will be shut-in, if any, and for what duration. The amount and timing of compensation for having to shut in such production is also not determinable at this time. In order to establish a base level of certainty, PET’s forecasts of future cash flow and distributions assume the shut-in of gas volumes as recommended by the SSG and that any compensation for such shut-in, other than the temporary financial assistance program of $0.60 per Mcf presently in place, is delayed indefinitely.

See “Government Regulations — Regulatory Rulings” and “Risk Factors”.

Marten Hills Acquisition

On February 5, 2004 PET completed the acquisition of producing natural gas properties in the Marten Hills area of northeast Alberta for $30.3 million, effective January 1, 2004. These assets comprise production totaling 7.4 MMcf/d and while they are within the Trust’s northeast Alberta core area, they are outside the AEUB gas/bitumen area of concern identified in GB 2003-28. The acquisition was financed from existing credit facilities.

REPORT OF MANAGEMENT AND DIRECTORS ON RESERVES DATA AND OTHER INFORMATION

Management of Paramount Energy Trust (the “Trust”) are responsible for the preparation and disclosure of information with respect to the Trust’s oil and gas activities in accordance with securities regulatory requirements. This information includes reserves data, which consist of the following:


(a)	(i)	proved and proved plus probable oil and gas reserves estimated as at December 31, 2003 using forecast prices and costs; and

	(ii)	the related estimated future net revenue; and

(b)	(i)	proved oil and gas reserves estimated as at December 31, 2003 using constant prices and costs; and

	(ii)	the related estimated future net revenue.

McDaniel & Associates Consultants Ltd. (“McDaniel”) has evaluated the Trust’s Reserves Data. The report of McDaniel is presented below.

The Audit and Reserves Committee of the Board of Directors of the Trust has:

(a) reviewed the Trust’s procedures for providing information to McDaniel;

(b) met with McDaniel to determine whether any restrictions affected the ability of McDaniel to report without reservation and to inquire whether there has been any disputes between McDaniel and management; and

(c) reviewed the reserves data with management and McDaniel.

The Audit and Reserves Committee of the Board of Directors has reviewed the Trust’s procedures for assembling and reporting other information associated with oil and gas activities and has reviewed that information with management. The board of directors has, on the recommendation of the Audit and Reserves Committee, approved:

(a) the content and filing with securities regulatory authorities of the reserves data and other oil and gas information;

(b) the filing of the report of McDaniel on the reserves data; and

(c) the content and filing of this report.

Because the reserves data are based on judgements regarding future events, actual results will vary and the variations may be material.


(signed) “Clayton H. Riddell”		(signed) “Kevin J. Marjoram ”
Clayton H. Riddell		Kevin J. Marjoram
Chairman and Chief Executive Officer		Vice President Operations

(signed) “John W. Peltier”		(signed) “Donald J. Nelson”
John W. Peltier		Donald J. Nelson
Director		Director

March 18, 2004

REPORT ON RESERVES DATA

To the board of directors of Paramount Energy Trust (the “Trust”):

1. We have evaluated the Trust’s reserves data as at December 31, 2003. The reserves data consist of the following:


(a)	(i)	proved and proved plus probable gas reserves estimated as at December 31, 2003 using forecast prices and costs; and

	(ii)	the related estimated future net revenue; and

(b)	(i)	proved and proved plus probable gas reserves estimated as at December 31, 2003 using constant prices and costs; and

	(ii)	the related estimated future net revenue.

2. The reserves data are the responsibility of the Trust’s management. Our responsibility is to express an opinion on the reserves data based on our evaluation.

We carried out our evaluation in accordance with standards set out in the Canadian Oil and Gas Evaluation Handbook (the “COGE Handbook”) prepared jointly by the Society of Petroleum Evaluation Engineers (Calgary Chapter) and the Canadian Institute of Mining, Metallurgy & Petroleum (Petroleum Society).

3. Those standards require that we plan and perform an evaluation to obtain reasonable assurance as to whether the reserves data are free of material misstatement. An evaluation also includes assessing whether the reserves data are in accordance with principles and definitions presented in the COGE Handbook.

4. The following table sets forth the estimated future net revenue (before deduction of income taxes) attributed to proved plus probable reserves, estimated using forecast prices and costs and calculated using a discount rate of 10 percent, included in the reserves data of the Trust evaluated by us for the year ended December 31, 2003, and identifies the respective portions thereof that we have evaluated and reported on to the Trust’s board of directors:

Net Present Value of Future Net Revenue

Description and

(before income taxes, 10% discount rate)

Independent Qualified Reserves

Preparation Date of

Evaluator

Evaluation Report

Location of Reserves

Audited

Evaluated

Reviewed

Total

McDaniel & Associates Consultants Ltd.

December 31, 2003

Canada

Wells Not Affected by Gas over Bitumen Issues

225,243

Wells Identified for Shut-in

48,672

5. In our opinion, the reserves data evaluated by us have, in all material respects, been determined and are in accordance with the COGE Handbook. We express no opinion on the reserves data that we reviewed but did not audit or evaluate.

6. We have no responsibility to update our reports referred to in paragraph 4 for events and circumstances occurring after their respective preparation dates.

7. Because the reserves data are based on judgements regarding future events, actual results will vary and the variations may be material.

Executed as to our Report referred to above:

   (signed) “McDaniel & Associates Consultants Ltd.”
   McDaniel & Associates Consultants Ltd.
   Calgary, Alberta
   March 16, 2004

STATEMENT OF RESERVES DATA AND OTHER OIL AND GAS INFORMATION

The statement of reserves data and other oil and gas information set forth below (the “Statement”) is dated December 31, 2003. The effective date of the Statement is December 31, 2003 and the preparation date of the Statement is March 18, 2004.

Disclosure of Reserves Data

The reserves data set forth below (the “Reserves Data”) is based upon an evaluation by McDaniel with an effective date of December 31, 2003 contained in a report of McDaniel dated March 8, 2004. The Reserves Data summarizes the natural gas reserves of the Trust and the net present values of future net revenue for these reserves using constant prices and costs and forecast prices and costs. The Reserves Data conforms with the requirements of National Instrument 51-101 Standards of Disclosure for Oil and Gas Activities (“NI 51-101”). Additional information not required by NI 51-101 has been presented to provide continuity and additional information which we believe is important to the readers of this information. PET engaged McDaniel to provide an evaluation of proved and proved plus probable reserves and no attempt was made to evaluate possible reserves.

All of the Trust’s reserves are in Canada and, specifically, in the province of Alberta and 100 percent of the Trust’s reserves are natural gas.

It should not be assumed that the estimates of future net revenues presented in the tables below represent the fair market value of the reserves. There is no assurance that the constant prices and costs assumptions and forecast prices and costs assumptions will be attained and variances could be material. Actual crude oil, natural gas and natural gas liquid reserves may be greater than or less than the estimates provided herein.

Reserves Data (Constant Prices and Costs)

SUMMARY OF GAS RESERVES
AND NET PRESENT VALUES OF FUTURE NET REVENUE
as of December 31, 2003
CONSTANT PRICES AND COSTS


					NET PRESENT VALUES OF FUTURE REVENUE
					BEFORE TAX DISCOUNTED AT
RESERVES CATEGORIES	NATURAL GAS				(%/year)⁽¹⁾
	Gross		Net		0%		10%		15%		20%
	mmcf		mmcf		(M$)		(M$)		(M$)		(M$)
PROVED
Developed Producing		115,219		93,931		379,244		289,565		259,941		236,417
Developed Non-Producing		7,393		6,209		16,643		14,224		13,192		12,295
Undeveloped		656		544		996		748		645		555

TOTAL PROVED		123,268		100,684		396,883		304,537		273,778		249,267
PROBABLE		25,519		20,977		91,885		46,079		35,391		28,303

TOTAL PROVED PLUS PROBABLE		148,787		121,661		488,768		350,616		309,169		277,570

Notes:

(1) For income tax purposes PET is able to and intends to claim deduction for all amounts paid or payable to the Unitholder then allocate remaining taxable income, if any, to the Unitholders. Accordingly, no income tax amounts have been reported herein.

The following table sets forth PET’s reserves on a Gross and a Net basis as evaluated by McDaniel, divided into two sub-categories, “Without Gas/Bitumen and With Gas/Bitumen”. See “Government Regulations — Regulatory Rulings”.

Natural Gas Reserves
(Based on Escalating Price Assumptions)


	Gross Reserves (mmcf)						Net Reserves (mmcf)
	Without		With				Without		With
Reserves Category	Gas/Bitumen⁽¹⁾		Gas/Bitumen⁽²⁾		Total		Gas/Bitumen⁽¹⁾		Gas/Bitumen⁽²⁾		Total
PROVED
Developed Producing		101,042		14,176		115,218		82,026		11,905		93,931
Non-Producing		2,826		4,567		7,393		2,267		3,942		6,209
Undeveloped		656		—		656		544		—		544

TOTAL PROVED		104,524		18,743		123,267		84,837		15,847		100,684
PROBABLE		16,318		9,202		25,520		13,173		7,804		20,977

TOTAL PROVED PLUS PROBABLE		120,842		27,945		148,787		98,010		23,651		121,661

Notes:

(1) “Without Gas/Bitumen” represents those reserves not recommended for shut-in by the AEUB Staff Submission Group.

(2) “With Gas/Bitumen” represents those reserves recommended for shut-in by the AEUB Staff Submission Group. Reserves related to production which is currently shut-in as a result of AEUB Interim Shut-in Order 03-001 have been categorized as probable reserves.

TOTAL FUTURE NET REVENUE
(UNDISCOUNTED)
as of December 31, 2003
CONSTANT PRICES AND COSTS ($000’s)

FUTURE

NET

REVENUE

WELL

BEFORE

AFTER

RESERVES

OPERATING

DEVELOPMENT

ABANDONMENT

INCOME

CATEGORY

REVENUE

ROYALTIES

COSTS

TAXES

TAXES⁽¹⁾

Proved Reserves

733,046

119,303

182,059

4,469

30,332

396,883

—

396,883

Proved Plus Probable Reserves

884,148

143,782

216,647

4,630

30,321

488,768

—

488,768

Note:

FUTURE NET REVENUE
BY PRODUCTION GROUP
as of December 31, 2003
CONSTANT PRICES AND COSTS


		FUTURE NET REVENUE
		BEFORE INCOME TAXES
RESERVES		(discounted at 10%/year)
CATEGORY	PRODUCTION GROUP	(M$)
Proved Reserves	Natural Gas (including by-products but excluding solution gas from oil wells)		304,537
Proved Plus Probable Reserves	Natural Gas (including by-products but excluding solution gas from oil wells)		350,616

Reserves Data (Forecast Prices and Costs)

SUMMARY OF GAS RESERVES
AND NET PRESENT VALUES OF FUTURE NET REVENUE
as of December 31, 2003
FORECAST PRICES AND COSTS


					NET PRESENT VALUES OF FUTURE REVENUE
					BEFORE TAX DISCOUNTED AT
RESERVES CATEGORIES	NATURAL GAS				(%/year)⁽¹⁾
	Gross		Net		0%		10%		15%		20%
	mmcf		mmcf		(M$)		(M$)		(M$)		(M$)
PROVED
Developed Producing		115,218		93,931		284,708		228,989		209,365		193,307
Developed Non-Producing		7,393		6,209		9,916		9,663		9,299		8,917
Undeveloped		656		544		572		416		346		283

TOTAL PROVED		123,267		100,684		295,196		239,068		219,010		202,507
PROBABLE		25,520		20,977		66,924		34,847		27,192		22,061

TOTAL PROVED PLUS PROBABLE		148,787		121,661		362,120		273,915		246,202		224,568

Note:

TOTAL FUTURE NET REVENUE
(UNDISCOUNTED)
as of December 31, 2003
FORECAST PRICES AND COSTS ($000’s)

FUTURE

NET

REVENUE

WELL

BEFORE

AFTER

RESERVES

OPERATING

DEVELOPMENT

ABANDONMENT

INCOME

CATEGORY

REVENUE

ROYALTIES

COSTS

TAXES

TAXES⁽¹⁾

Proved Reserves

635,712

99,574

200,550

4,565

35,827

295,196

—

295,196

Proved Plus Probable Reserves

766,053

119,436

243,490

4,734

36,273

362,120

—

362,120

Note:

FUTURE NET REVENUE
BY PRODUCTION GROUP
as of December 31, 2003
FORECAST PRICES AND COSTS


		FUTURE NET REVENUE
		BEFORE INCOME TAXES
RESERVES		(discounted at 10%/year)
CATEGORY	PRODUCTION GROUP	(M$)
Proved Reserves	Natural Gas (including by-products but excluding solution gas from oil wells)		239,068
Proved Plus Probable Reserves	Natural Gas (including by-products but excluding solution gas from oil wells)		273,915

Definitions and Other Notes

1. Columns may not add due to rounding.

2. The crude oil, natural gas liquids and natural gas reserve estimates presented in the McDaniel Report are based on the definitions and guidelines contained in the COGE Handbook. A summary of those definitions are set forth below.

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

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

(a) gain access to and prepare well locations for drilling, including surveying well locations for the purpose of determining specific development drilling sites, clearing ground, draining, road building, and relocating public roads, gas lines and power lines, pumping equipment and wellhead assembly;

(b) drill and equip development wells, development type stratigraphic test wells and service wells, including the costs of platforms and of well equipment such as casing, tubing, pumping equipment and wellhead assembly;

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

(d) provide improved recovery systems.

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

(a) costs of topographical, geochemical, geological and geophysical studies, rights of access to properties to conduct those studies, and salaries and other expenses of geologists, geophysical crews and others conducting those studies;

(b) costs of carrying and retaining unproved properties, such as delay rentals, taxes (other than income and capital taxes) on properties, legal costs for title defence, and the maintenance of land and lease records;

(c) dry hole contributions and bottom hole contributions;

(d) costs of drilling and equipping exploratory wells; and

(e) costs of drilling exploratory type stratigraphic test wells.

“Gross” means:

(a) in relation to the Trust’s interest in production and reserves, its “Trust gross reserves”, which are the Trust’s interest (operating and non-operating) share before deduction of royalties and without including any royalty interest of the Trust;

(b) in relation to wells, the total number of wells in which the Trust has an interest; and

(c) in relation to properties, the total area of properties in which the Trust has an interest.

“Net” means:

(a) in relation to the Trust’s interest in production and reserves, the Trust’s interest (operating and non-operating) share after deduction of royalties obligations, plus the Trust’s royalty interest in production or reserves.

(b) in relation to wells, the number of wells obtained by aggregating the Trust’s working interest in each of its gross wells; and

(c) in relation to the Trust’s interest in a property, the total area in which the Trust has an interest multiplied by the working interest owned by the Trust.

“NI 51-101” means National Instrument 51-101 Standards of Disclosure for Oil and Gas Activities;

Reserve Categories

Reserves are estimated remaining quantities of oil and natural gas and related substances anticipated to be recoverable from known accumulations, from a given date forward, based on

• analysis of drilling, geological, geophysical and engineering data;

• the use of established technology; and

• specified economic conditions.

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

(a) Proved reserves are those reserves that can be estimated with a high degree of certainty to be recoverable. It is likely that the actual remaining quantities recovered will exceed the estimated proved reserves.

(b) Probable reserves are those additional reserves that are less certain to be recovered than proved reserves. It is equally likely that the actual remaining quantities recovered will be greater or less than the sum of the estimated proved plus probable reserves.

Other criteria that must also be met for the categorization of reserves are provided in the COGE Handbook.

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

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

(i) Developed producing reserves are those reserves that are expected to be recovered from completion intervals open at the time of the estimate. These reserves may be currently producing or, if shut-in, they must have previously been on production, and the date of resumption of production must be known with reasonable certainly.

(ii) Developed non-producing reserves are those reserves that either have not been on production, or have previously been on production, but are shut-in, and the date of resumption of production is unknown.

(b) Undeveloped reserves are those reserves expected to be recovered from known accumulations where a significant expenditure (for example, when compared to the cost of drilling a well) is required to render them capable of production. They must fully meet the requirements of the reserves classification (proved, probable) to which they are assigned.

Levels of Certainty for Reported Reserves

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

(a) at least a 90 percent probability that the quantities actually recovered will equal or exceed the estimated proved reserves; and

(b) at least a 50 percent probability that the quantities actually recovered will equal or exceed the sum of the estimated proved plus probable reserves.

Additional clarification of certainty levels associated with reserves estimates and the effect of aggregation is provided in the COGE Handbook.

Pricing Assumptions

The forecast cost and price assumptions assume increases in wellhead selling prices and take into account inflation with respect to future operating and capital costs. Natural gas benchmark reference pricing, as at December 31, 2003, inflation and exchange rates utilized by McDaniel in the McDaniel Report, which were McDaniel’s then current forecasts at the date of the McDaniel Report, were as follows:

SUMMARY OF PRICING ASSUMPTIONS
as of December 31, 2003
CONSTANT PRICES AND COSTS

British Columbia

Alberta Average

Sask. Prov. Gas

CanWest

Plantgate

Year

Cdn$/Mmbtu

Historical⁽¹⁾ 2003

5.87

5.70

5.25

Note:

(1) As at December 31.

FORECAST PRICES AND COSTS


											British Columbia				US/CAD
	AECO		Alberta Average		Aggregator		Alberta Spot		Sask. Prov. Gas		CanWest				Exchange
	Spot Price		Plantgate		Plantgate		Sales Plantgate		Plantgate		Plantgate				Rate
Forecast	Cdn$/GJ		Cdn$/Mmbtu		Cdn$/Mmbtu		Cdn$/Mmbtu		Cdn$/Mmbtu		Cdn$/Mmbtu		Inflation%⁽¹⁾		U.S.$/Cdn$⁽²⁾
2004		5.50		5.65		5.65		5.65		5.80		5.55		2.0		0.75
2005		5.19		5.30		5.30		5.30		5.45		5.20		2.0		0.75
2006		4.87		4.95		4.95		4.95		5.15		4.85		2.0		0.75
2007		4.68		4.75		4.75		4.75		4.95		4.65		2.0		0.75
2008		4.53		4.60		4.60		4.60		4.80		4.50		2.0		0.75
2009		4.57		4.65		4.65		4.65		4.85		4.55		2.0		0.75
2010		4.60		4.65		4.65		4.65		4.85		4.55		2.0		0.75
2011		4.69		4.75		4.75		4.75		4.95		4.65		2.0		0.75
2012		4.78		4.85		4.85		4.85		5.05		4.75		2.0		0.75
2013		4.87		4.95		4.95		4.95		5.15		4.85		2.0		0.75
2014		4.97		5.05		5.05		5.05		5.25		4.95		2.0		0.75
2015		5.08		5.15		5.15		5.15		5.35		5.05		2.0		0.75
2016		5.19		5.25		5.25		5.25		5.45		5.15		2.0		0.75
2017		5.29		5.35		5.35		5.35		5.55		5.25		2.0		0.75
2018		5.40		5.45		5.45		5.45		5.65		5.35		2.0		0.75
2019		5.51		5.60		5.60		5.60		5.85		5.50		2.0		0.75
2020		5.61		5.70		5.70		5.70		5.95		5.60		2.0		0.75
2021		5.72		5.80		5.80		5.80		6.05		5.70		2.0		0.75
2022		5.82		5.90		5.90		5.90		6.15		5.80		2.0		0.75
2023		5.95		6.00		6.00		6.00		6.25		5.90		2.0		0.75

Notes:

(1) Inflation rates for forecasting prices and costs.

(2) Exchange rates used to generate the benchmark reference prices in this table.

Weighted average historical prices realized by the Trust for the year ended December 31, 2003, were $6.44/mcf for natural gas.

Reconciliations of Changes in Reserves and Future Net Revenue

RECONCILIATION OF
TRUST NET RESERVES
FORECAST PRICES AND COSTS


	ASSOCIATED AND NON-ASSOCIATED GAS
	Net Proved			Net Probable		Net Proved Plus Probable
FACTORS	(bcf)			(bcf)		(bcf)
December 31 2002⁽¹⁾		131.1			15.6		146.7
Improved Recoveries		2.1			0.5		2.6
Extensions		—			—		—
Discoveries		—			—		—
Technical Revisions		(16.1	)		3.7		(12.4	)
Acquisitions		8.6			1.2		9.8
Dispositions		—			—		—
Economic Factors		—			—		—
Production		(25.0	)		—		(25.0	)
December 31, 2003		100.7			21.0		121.7

Note:

(1) PET’s independent reserve report for the year ended December 31, 2002 was prepared in accordance with the then applicable National Policy 2B which used different reserve definitions than the currently applicable National Instrument 51-101. In order to make the reserve balances for the period ended December 31, 2002 more comparable to those for the period ended December 31, 2003 PET has chosen to present the December 31, 2002 balances as Total Proved plus 50% of the Probable Reserves with both figures being derived from the McDaniel Report dated December 31, 2002. Proved plus 50% of Probable reserves determined under National Policy 2B were commonly referred to as Established Reserves and recognized a risk factor being applied to the Probable Reserve category. Accordingly Established Reserves as at December 31, 2002 are used as the opening balance in this table and reconciled to the closing balance of Proved Plus Probable Reserves prepared in accordance with National Instrument 51-101. Under National Instrument 51-101 Proved Plus Probable Reserves reflect at least a 50% probability that the quantities actually recovered will equal or exceed the sum of the estimated Proved Plus Probable reserves. It should be noted that Established Reserves determined in accordance with National Policy 2B may not be strictly comparable to Proved Plus Probable Reserves in accordance with National Instrument 51-101.

RECONCILIATION OF
TRUST GROSS RESERVES
FORECAST PRICES AND COSTS


	ASSOCIATED AND NON-ASSOCIATED GAS
	Gross Proved			Gross Probable		Gross Proved Plus Probable
FACTORS	(bcf)			(bcf)		(bcf)
December 31 2002⁽¹⁾		164.3			19.7		183.9
Improved Recoveries		2.7			0.6		3.3
Extensions		—			—		—
Discoveries		—			—		—
Technical Revisions		(23.2	)		3.7		(19.5	)
Acquisitions		10.7			1.5		12.2
Dispositions		—			—		—
Economic Factors		—			—		—
Production		(31.2	)		—		(31.2	)
December 31, 2003		123.3			25.5		148.8

Note:

RECONCILIATION OF CHANGES IN
NET PRESENT VALUES OF FUTURE NET REVENUE
DISCOUNTED AT 10% PER YEAR
PROVED RESERVES
CONSTANT PRICES AND COSTS


	2003
PERIOD AND FACTOR	($000’s)
Estimated Future Net Revenue at December 31, 2002		362,817
Sales of Gas Produced, Net of Production Costs and Royalties		(135,303	)
Net Change in Prices, Production Costs and Royalties Related to Future Production		58,348
Changes in Estimated Future Development Costs		(1,276	)
Capital Additions		6,351
Acquisitions of Reserves		26,008
Dispositions of Reserves		—
Net Change Resulting from Revisions in Quantity Estimates		(48,690	)
Accretion of Discount		36,282
Net Change in Income Taxes⁽¹⁾		—
Estimated Future Net Revenue at December 31, 2003		304,537

Note:

Additional Information Relating to Reserves Data

Undeveloped Reserves

Future Development

The McDaniel Report estimates that future capital costs of $4.7 million will be required over the life of the Trust’s proved plus probable reserves for the drilling, completion, equipping and tie-in of up to 5 wells and the equipping, tie-in and recompletion of up to 10 wells included in the Trust’s proved plus probable reserves. Additionally, many of our current assets include incremental exploitation opportunities. We have currently identified a minimum of 25 development drilling locations including:

• Approximately 5 development wells in the Legend area.

• 5 development wells at Marten Hills.

• 3 development wells at Legend East.

• 2 development wells at Ells.

For a description of these properties, see “Other Oil and Gas Information — Oil and Gas Properties”.

In addition, there also exists potential for incremental gas production through recompletion of uphole zones in existing wells and optimization of facilities.

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

Significant Factors or Uncertainties

None of PET’s properties have unusually high expected development costs or operating costs, the need to build a major pipeline or other major facility before production of reserves can begin, or contractual obligations to produce and sell a significant portion of production at prices substantially below those which could be realized but for those contractual obligations.

Future Development Costs

The following table sets forth development costs deducted in the estimation of the Trust’s future net revenue attributable to the reserve categories noted below.


	Forecast Prices and Costs								Constant Prices and Costs
	Proved Reserves				Proved Plus Probable Reserves				Proved Reserves
Year	0%		10%		0%		10%		0%		10%
2004		4,471		4,263		4,471		4,263		4,384		4,180
2005		7		6		162		140		7		6
2006		42		33		42		33		40		32
2007		—		—		—		—		—		—
2008		—		—		4		3		—		—
Thereafter		43		25		55		28		39		23
Total		4,563		4,327		4,734		4,467		4,470		4,241

PET expects to fund the estimated future development costs from either internally-generated cash flow, debt or equity financing, and does not expect such costs to make development of any properties uneconomic.

Other Oil and Gas Information

Oil and Gas Properties

The following is a description of the Trust’s oil and natural gas properties as at December 31, 2003. Production stated is the Trust’s working interest share of production volume and, unless otherwise stated, is average production for 2003. Reserve amounts are stated, as at January 1, 2004 based on forecast costs and prices as evaluated in the McDaniel Report (see “Reserves Data”). The estimates of reserves and future net revenue for individual properties may not reflect the same confidence level as estimates of reserves and future net revenue for all properties, due to the effects of aggregation. Unless otherwise specified, gross and net acres and well count information are as at December 31, 2003.

Properties — General

The majority of the properties and facilities referred to below were acquired by PET from PRL in February and March of 2003. See “Organization and Structure of the Trust — General Development of the Business — Significant Acquisitions”. Any reference in this section to activity in connection with, or statistical information pertaining to, these properties prior to such acquisition are with respect to these properties at a time when they were owned by PRL. Any such references after such acquisitions are with respect to these properties at a time when they were owned by PET. The acquisitions by PET from PRL were effective July 1, 2002 and the cash flow from the effective date to closing accrued to PET.

Bohn Lake, Alberta

The Bohn Lake Area is in northeast Alberta approximately 90 kilometres south of Fort McMurray. The area comprises 50,560 acres (15,253 net acres) including an average 26.43% working interest in 29 (7.67 net) producing natural gas wells. The average daily production for 2003 from the Bohn Lake Area was approximately 2.2 mmcf/d of natural gas (net). The McDaniel Report evaluated PET’s total proved reserves at 3.82 bcf (gross) and probable reserves at 0.83 bcf 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/Chard Southwest, Alberta

The Chard Area and the Chard Southwest Area (collectively the “Chard/Chard Southwest Area”) are in northeast Alberta approximately 85 kilometres south of Fort McMurray. The areas comprise 46,720 gross acres (31,532 net acres) including an average 73.95% working interest in 21 (15.53 net) producing natural gas wells. The average daily production for 2003 from the Chard /Chard Southwest Area was approximately 1.7 mmcf/d of natural gas (net). The McDaniel Report evaluated PET’s total proved reserves at 2.75 bcf (gross) and probable reserves at 0.24 bcf of natural gas for the Chard/Chard Southwest Area. Production from the Chard Area is processed through one booster compressor owned 100% by PET. 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. PET’s interest in the gas plant is 33.3%.

Clyde, Alberta

The Clyde Area is in northeast Alberta approximately 85 kilometres southwest of Fort McMurray. The area comprises 26,880 gross acres (25,852 net acres) including an average 94.33% working interest in 11 (10.38 net) producing natural gas wells. The average daily production for 2003 from the Clyde Area was approximately 2.0 mmcf/d of natural gas (net). The McDaniel Report evaluated PET’s total proved reserves at 1.51 bcf (gross) and probable reserves at 0.07 bcf of natural gas for the Clyde Area. Production from the Clyde Area is processed through one gas plant owned 100% by PET.

Cold Lake/ Cold Lake Sunoma, Alberta

The Cold Lake Area and the Cold Lake Sunoma Area (collectively the “Cold Lake Area”) are in northeast Alberta approximately 250 kilometres southeast of Fort McMurray. The Cold Lake area comprises 122,703 gross acres (93,371 net acres) including an average 77.17% working interest in 63 (48.62 net) producing natural gas wells. The average daily production for 2003 from the Cold Lake Area was approximately 6.2 mmcf/d of natural gas (net). The McDaniel Report evaluated PET’s total proved reserves at 9.79 bcf (gross) and probable reserves at 2.09 bcf 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. 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 PET.

Corner, Alberta

The Corner Area is in Northeastern Alberta approximately 80 kilometres southwest of Fort McMurray. The area comprises 102,400 gross acres (100,355 net acres) involving an average 98.6% working interest in 44 (43.4 Net) producing natural gas wells. The average daily production for 2003 from the Corner Area was approximately 11.0 mmcf/d of natural gas (NET). The McDaniel Report evaluated PET’s total proved reserves at 11.86 bcf (gross) and probable reserves at 5.83 bcf of natural gas for the Corner Area. Production from the Corner Area is processed through one gas plant owned 100% by PET.

Craigmyle, Alberta

The Craigmyle Area, acquired November 2003 through the acquisition of Epact is approximately 90 kilometres northeast of Calgary. The Craigmyle property comprises 20,486 gross acres (5,273 net acres) including an average 19.76% working interest in 20 (3.95 net) producing natural gas wells. The average daily production from acquisition to December 31, 2003 from the Craigmyle Area was approximately 0.5 mmcf/d of natural gas (net). The McDaniel Report evaluated PET’s total proved reserves at 0.58 bcf (gross) and probable reserves at 0.21 bcf of natural gas for the Craigmyle Area. Production from the Craigmyle Area is processed through a number of non-operated gas plants.

Ells, Alberta

The Ells Property was acquired by the Trust from PRL effective March 19, 2003 for $18.4 million. Prior to closing, the asset was non-producing; however, production commenced on March 19, 2003. Ells is located in northeast Alberta approximately 50 kilometres northwest of Fort McMurray, and 16 kilometres east of PET’s Legend East property. The Trust owns an undivided 100% working interest in Alberta Provincial Crown leases comprising 28,800 gross acres (28,800 net acres) as well as a 100% working interest in 20 producing natural gas wells. The Ells Property acquisition also included the purchase of related facilities including a gas plant, a booster compressor station.

The average daily production for the period from acquisition to December 31, 2003 from the Ells Property was approximately 7.1 mmcf/d of natural gas. The McDaniel Report evaluated PET’s total proved reserves at 5.99 bcf (gross) and probable reserves at 1.08 bcf of natural gas for the Ells Property.

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 (33,114 net acres) including an average 98.58% working interest in 20 (19.72 net) producing natural gas wells. The average daily production for 2003 from the Kettle River Area was approximately 3.8 mmcf/d of natural gas (net). The McDaniel Report evaluated PET’s total proved reserves at 4.72 bcf (gross) and probable reserves at 0.54 bcf of natural gas for the Kettle River Area. Production from the Kettle River Area is processed through one gas plant owned 99.15% by PET.

Kirkpatrick, Alberta

The Kirkpatrick Area, acquired November 2003 through the acquisition of Epact is approximately 150 kilometres northeast of Calgary. The Kirkpatrick property comprises 10,737 gross acres (8,224 net acres) including an average 78.93% working interest in 9 (7.1 net) producing natural gas wells. The average daily production from acquisition to December 31, 2003 from the Kirkpatrick Area was approximately 0.6 mmcf/d of natural gas (net). The McDaniel Report evaluated PET’s total proved reserves at 0.71 bcf (gross) and probable reserves at 0.15 bcf of natural gas for the Kirkpatrick Area. Production from the Kirkpatrick Area is processed through a PET-owned compressor and then a plant operated by Altagas Services Inc.

Legend, Alberta

The Legend Area is approximately 120 kilometres northwest of Fort McMurray. The area comprises 146,560 gross acres (128,483 net acres) including an average 84.71% working interest in 64 gross (54.21 net) producing natural gas wells. The average daily production for 2003 based upon such working interest from the Legend Area was approximately 18.0 mmcf/d of natural gas (net). The McDaniel Report evaluated PET’s proved reserves at 38.71 bcf (gross) and probable reserves at 4.93 bcf of natural gas for the Legend Area. PET has a 82.25% interest in an operated gas plant and seven field booster compressors, with working interests ranging from 78.8% to 100% that process the natural gas from this area.

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 18 producing natural gas wells. The average daily production for 2003 from the Legend East Area was approximately 3.0 mmcf/d of natural gas (net). The McDaniel Report evaluated PET’s total proved reserves at 2.22 bcf (gross) and probable reserves at 0.35 bcf of natural gas for the Legend East Area. Production from the Legend East Area is processed through the Legend gas plant and two field booster compressors owned by PET.

Leismer, Alberta

The Leismer Area is in northeast Alberta approximately 90 kilometres southwest of Fort McMurray. The area comprises 227,840 gross acres (214,679 net acres) including a 86.66% working interest in 55 (47.66 net) producing natural gas wells. The average daily production for 2003 from the Leismer Area was approximately 7.9 mmcf/d of natural gas (net). The McDaniel Report evaluated PET’s total proved reserves at 7.28 bcf (gross) and probable reserves at 1.55 bcf of natural gas for the Leismer Area. Production from the Leismer Area is processed through one gas plant owned 32.5% by PET and three field booster compressors owned by PET.

Liege East, Alberta

The Liege East Area is in northeast Alberta approximately 120 kilometres west of Fort McMurray. The area comprises 12,160 gross acres (10,835 net acres) including an average 90.36% working interest in 10 (9.04 net) producing natural gas wells. The average daily production for 2003 from the Liege East Area was approximately 1.7 mmcf/d of natural gas (net). The McDaniel Report evaluated PET’s total proved reserves at 1.43 bcf (gross) and probable reserves at 0.15 bcf 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 PET and one Liege East field booster compressor owned 90.86% by PET.

Liege North, Alberta

The Liege North Area is in northeast Alberta approximately 120 kilometres west of Fort McMurray. The area comprises 67,200 gross acres (60,773 net acres) including an average 97.77% working interest in 13 (12.7 net) producing natural gas wells. The average daily production for 2003 from the Liege North Area was approximately 2.4 mmcf/d of natural gas (net). The McDaniel Report evaluated PET’s total proved reserves at 4.14 bcf (gross) and probable reserves at 0.43 bcf of natural gas for the Liege North Area. Production from the Liege North Area is processed through one gas plant owned 97.87% by PET.

Liege South, Alberta

The Liege South Area is in northeast Alberta approximately 120 kilometres west of Fort McMurray. The area comprises 118,240 gross acres (91,999 net acres) including an average 96.71% working interest in 20 (19.34 net) producing natural gas wells. The average daily production for 2003 from the Liege South Area was approximately 3.8 mmcf/d of natural gas (net). The McDaniel Report evaluated PET’s total proved reserves at 4.10 bcf (gross) and probable reserves at 0.48 bcf of natural gas for the Liege South Area. Production from the Liege South Area is processed through one gas plant owned 80.5% by PET and three field compressors owned by PET.

Minnehik, Alberta

The Minnehik Area, acquired November 2003 through the acquisition of Epact is approximately 200 kilometres north of Calgary. The Minnehik property comprises 1,440 gross acres (320 net acres) including an average 25% working interest in 4 (1 net) producing natural gas wells. The average daily production from acquisition to December 31, 2003 from the Minnehik Area was approximately 0.5 mmcf/d of natural gas (net). The McDaniel Report evaluated PET’s total proved reserves at 0.34 bcf (gross) and probable reserves at 0.12 bcf of natural gas for the Minnehik Area. Production from the Minnehik Area is processed through a compressor jointly owned with and a plant operated by Devon Canada Corporation.

Pony, Alberta

The Pony Area is in northeast Alberta approximately 75 kilometres southwest of Fort McMurray. The area comprises 16,640 gross acres (8,240 net acres) including an average 62.5% working interest in 4 (2.5 net) producing natural gas wells. The average daily production for 2003 from the Pony Area was approximately 0.5 mmcf/d of natural gas (net). The McDaniel Report evaluated PET’s total proved reserves at 0.68 bcf (gross) and probable reserves at 0.54 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 65,280 gross acres (65,280 net acres) including a 100% working interest in 18 producing natural gas wells. The average daily production for 2003 from the Quigley Area was approximately 2.9 mmcf/d of natural gas (net). The McDaniel Report evaluated PET’s total proved reserves at 2.47 bcf (gross) and probable reserves at 0.56 bcf of natural gas for the Quigley Area. Production from the Quigley Area is processed through one gas plant and one field compressor owned by PET.

Saleski, Alberta

The Saleski Area is in northeast Alberta approximately 110 kilometres west of Fort McMurray. The area comprises 95,040 gross acres (83,598 net acres) including an average 65.77% working interest in 28 (18.42 net) producing natural gas wells. The average daily production for 2003 from the Saleski Area was approximately 3.8 mmcf/d of natural gas (net). The McDaniel Report evaluated PET’s total proved reserves at 7.91 bcf (gross) and probable reserves at 1.56 bcf of natural gas for the Saleski Area. Production from the Saleski Area is processed through one gas plant owned 98.74% by PET.

Teepee Creek, Alberta

The Teepee Creek Area is in northeast Alberta approximately 175 kilometres southwest of Fort McMurray. The area comprises 110,319 gross acres (67,320 net acres) including an average 50% working interest in 10 (5 net) producing natural gas wells. The average daily production for 2003 from the Teepee Creek Area was approximately 1.4 mmcf/d of natural gas (net). The McDaniel Report evaluated PET’s total proved reserves at 0.53 bcf (gross) and probable reserves at 0.30 bcf 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 PET has a 37.5% interest.

Thornbury, Alberta

The Thornbury Area is in northeast Alberta approximately 75 kilometres southwest of Fort McMurray. The area comprises 52,480 gross acres (36,684 net acres) including an average 70.13% working interest in 39 (27.35 net) producing natural gas wells. The average daily production for 2003 from the Thornbury Area was approximately 4.4 mmcf/d of natural gas (net). The McDaniel Report evaluated PET’s total proved reserves at 8.55 bcf (gross) and probable reserves (unrisked) at 0.58 bcf 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.

Winefred, Alberta

The Winefred Area is in northeast Alberta approximately 200 kilometres southeast of Fort McMurray. The area comprises 101,760 gross acres (85,168 net acres) including an average 85.71% working interest in 14 (12.0 net) producing natural gas wells. The average daily production for 2003 from the Winefred Area was approximately 3.4 mmcf/d of natural gas (net). The McDaniel Report evaluated PET’s total proved reserves at 4.45 bcf (gross) and probable reserves at 3.09 bcf 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.

Oil And Gas Wells

The following table sets forth the number and status of wells in which the Trust had a working interest as at December 31, 2003.


	Natural Gas Wells
	Producing				Non-Producing⁽³⁾⁽⁴⁾
Name of Area (Alberta)	Gross⁽¹⁾		Net⁽²⁾		Gross⁽¹⁾		Net(2)
Bohn Lake		29		7.67		29		6.78
Chard/Chard Southwest		21		15.53		26		22.61
Clyde		11		10.38		16		14.90
Cold Lake		63		48.62		112		83.63
Corner		44		43.39		51		49.67
Craigmyle		20		3.95		22		3.02
Ells		20		20.00		10		10.00
Kettle River		20		19.72		18		17.72
Kirkpatrick		9		7.10		6		3.79
Legend		64		54.21		25		21.57
Legend East		18		18.00		20		20.00
Leismer		55		47.66		128		121.55
Liege East		10		9.04		5		4.62
Liege North		13		12.70		26		24.14
Liege South		20		19.34		74		56.86
Minnehik		4		1.00		2		0.25
Pony		4		2.50		14		5.37
Quigley		18		18.00		27		27.00
Saleski		28		18.42		15		10.98
Teepee Creek		10		5.00		30		15.94
Thornbury		39		27.35		34		23.27


	Natural Gas Wells
	Producing				Non-Producing⁽³⁾⁽⁴⁾
Name of Area (Alberta)	Gross⁽¹⁾		Net⁽²⁾		Gross⁽¹⁾		Net(2)
Winefred		14		12.00		75		66.32
Other		7		1.51		15		6.63

Total		541		423.09		780		616.62

Notes:

(1) “Gross” refers to the number of wells, producing and non-producing, respectively, in which a working interest or royalty interest is held by PET.

(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, markets and/or awaiting regulatory approval to commence production but are capable of producing in commercial quantities.

(4) Allowance for the abandonment costs associated with the wellbores was made in the McDaniel Report. There are 18 wells that are classified as service wells not included in the gross/net well count.

Landholdings Including Properties with no Attributable Reserves

The following table sets out the Trust’s developed and undeveloped land holdings as at December 31, 2003.


	Developed Acres				Undeveloped Acres(3)(4)
	Gross⁽¹⁾		Net⁽²⁾		Gross⁽¹⁾		Net⁽²⁾
Bohn Lake		48,960		14,720		1,600		533
Chard/Chard Southwest		28,800		19,207		17,920		12,325
Clyde		12,800		11,772		14,080		14,080
Cold Lake		94,563		71,463		28,140		21,909
Corner		74,240		73,155		28,160		27,200
Craigmyle		14,086		3,251		6,400		2,022
Ells		28,800		28,800		—		—
Kettle River		35,200		33,114		—		—
Kirkpatrick		5,457		4,574		5,280		3,650
Legend		125,440		107,899		21,120		20,584
Legend East		27,520		27,520		24,960		24,960
Leismer		136,960		130,160		90,880		84,518
Liege East		11,520		10,279		640		556
Liege North		67,200		60,773		—		—
Liege South		86,880		79,837		31,360		12,163
Minnehik		1,440		320		—		—
Pony		9,600		5,200		7,040		3,040
Quigley		52,160		52,160		13,120		13,120
Saleski		72,320		64,068		22,720		19,530
Teepee Creek		72,559		37,560		37,760		29,760
Thornbury		48,640		34,892		3,840		1,792
Winefred		72,960		63,808		28,800		21,360
Other		16,000		6,648		17,424		8,496

Total		1,144,105		941,178		401,244		321,599

Notes:

(1) “Gross” means the total number of developed and undeveloped acres, respectively, in which PET has an interest in respect of its current assets.

(2) “Net” means the aggregate of the numbers obtained by multiplying each gross acre by the actual percentage interest therein.

(3) During 2004, 192,960 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) “Undeveloped Acres” refers to land where no reserves have been assigned by McDaniel in the McDaniel Report.

PET does not have any material work commitments on any of its lands.

Forward Contracts

PET currently has no material future contracts to buy, sell, exchange or transport natural gas from its assets. PET currently sells approximately 60% of its gas production at AECO market prices. An additional 40% is directed to the Progas and PanAlberta aggregator pools. PET currently has financial natural gas hedge in place as follows:


Volumes at AECO
(Gigajoules/day) (“GJ/d”)	Price ($/GJ)	Term
45,000 GJ/d	$6.30	January 2004 – March 2004
35,000 GJ/d	$5.56	April 2004 – October 2004
7,500 GJ/d	$5.00 to 7.10	April 2004 – December 2004
15,000 GJ/d	$6.42	November 2004 – March 2005

PET currently has no other financial hedges or physical fixed price sales contracts in place for commodity, currency or interest rates.

Additional Information Concerning Abandonment and Reclamation Costs

PET engaged Prevent Technologies Ltd. an independent evaluator to prepare a summary (the “Net Liability Report”) of expected future abandonment and reclamation costs for PET’s surface leases, wells and facilities as well as estimated related salvage value. The Net Liability Report identifies total expected undiscounted future costs of $46.4 million ($23.0 million discounted at 10%) for the decommissioning, abandonment and reclamation of PET’s assets including its 1,039.71 net wells. Related undiscounted salvage value is estimated at $59.1 million ($29.4 million discounted at 10%) for plants, equipment and facilities. The McDaniel Report includes an undiscounted amount of $36.3 million ($18.0 million discounted at 10%) with respect to expected future well abandonment costs for PET’s proved plus probable reserves. PET expects to incur a total of approximately $4.5 million over the next three years for decommissioning, abandonment and reclamation of its assets.

Capital Expenditures

The following tables summarize capital expenditures related to the Trust’s activities for the year ended December 31, 2003:


Property acquisition costs		32,252
Exploration costs		8,327
Corporate Assets		757

Total	$	41,336

Exploration and Development Activities

The following table sets forth the gross and net exploratory and development wells in which the Trust participated during the year ended December 31, 2003:


	Gross		Net
Light and Medium Oil		—		—
Natural Gas		16		11.4
Service		1		0.5
Dry		—		—

Total:		17		11.9

Success Rate (%)		100		100
Exploratory		—		—
Development		17		11.9

Total		17		11.9

Production Estimates

The following table sets out the volume of the Trust’s production estimated for the year ended December 31, 2004 which is reflected in the estimate of future net revenue disclosed in the tables contained under “- Disclosure of Reserves Data”.


	Natural Gas
	(MMcf/d)
2004		80.5

Production History, Prices Received and Capital Expenditures

The following tables summarize certain information in respect of production, product prices received, royalties paid, operating expenses and resulting netback for the periods indicated below:


	2003												2003
	Quarter Ended												Total
	Dec 31			Sept 30			June 30			Mar 31
Average Daily Production Volume⁽¹⁾
Natural Gas (mmcf/d)		81.2	⁽¹⁾		88.5			88.4			84.2			85.6
Natural Gas Netbacks ($/mcf)
Average Net Product Price Received	$	5.49		$	5.76		$	6.37		$	8.19		$	6.44
Royalties		(0.98	)		(0.96	)		(1.10	)		(1.87	)		(1.22	)
Operating Costs		(0.85	)		(0.82	)		(0.76	)		(1.13	)		(0.89	)

Netback	$	3.66		$	3.98		$	4.51		$	5.19		$	4.33

Note:

(1) PET shut-in 7.9 MMcf/d pursuant to AEUB shut-in order 03-001 September 1, 2003. See “Government Regulation – Regulatory Rulings” and “Risk Factors”.


				2002									2002
	Quarter Ended												Total
	Dec 31			Sept 30			June 30			Mar 31
Average Daily Production Volume
Natural Gas (mmcf/d)		91.0			97.8			97.1			93.5			94.8
Natural Gas Netbacks ($/mcf)
Average Net Product Price Received	$	4.84		$	3.12		$	3.78		$	2.59		$	3.57
Royalties		(0.99	)		(0.47	)		(0.65	)		(0.43	)		(0.63	)
Operating Costs		(0.87	)		(0.56	)		(0.83	)		(1.26	)		(0.87	)

Netback	$	2.98		$	2.09		$	2.30		$	0.90		$	2.07

The following tables show capital expenditures made by PET in the categories and for the periods indicated:


	2003									2003
	Quarter Ended									Total
($000)	Dec 31		Sept 30			June 30		Mar 31
Category of Expenditure
Land and Acquisition		13,833		—			18,419		—		32,252
Drilling & Exploration		224		(671	)		87		8,687		8,327
Equipping		—		—			—		—		—
Facilities & Gathering		—		—			—		—		—
Corporate Assets		757		—			—		—		757

Total		14,814		(671	)		18,506		8,687		41,336

The following table indicates the Trust’s average daily production from its important fields for the year ended December 31, 2003:


	Production
Name of Area (Alberta)	(mmcf/d)
Bohn Lake		2.2
Chard		1.7
Clyde		2.0
Cold Lake		6.2
Corner		11.0
Craigmyle		0.1
Ells		5.0
Hoole		0.1
Kettle River		3.8
Kirkpatrick		0.1
Legend		18.0
Legend East		3.0
Leismer		7.9
Liege East		1.7
Liege North		2.4
Liege South		3.8
Minnehik		0.1
Pony		0.5
Quigley		2.9
Saleski		3.8
Surmont		0.0
Teepee Creek		1.4
Thornbury		4.4
Winefred		3.4
Other		0.0

Total		85.6

Cyclical and Seasonal Impact of Industry

The Trust’s operational results and financial condition will be dependent on the prices received for natural gas production. Natural gas prices have fluctuated widely during recent years and are determined by supply and demand factors, including weather and general economic conditions, as well as conditions in other oil and natural gas producing regions. Any decline in natural gas prices could have an adverse effect on the Trust’s financial condition.

Renegotiation or Termination of Contracts

As at the date hereof, the Trust does not anticipate that any aspect of its business will be materially affected in the current fiscal year by the renegotiation or termination of contracts or subcontracts.

Competitive Conditions

The Trust is a member of the petroleum and natural gas industry, which is highly competitive at all levels. The Trust competes with other companies and other energy trusts for all of its business inputs, including exploitation and development prospects, access to commodity markets, property and corporate acquisitions, and available capital. The Trust endeavours to be competitive by maintaining a strong financial condition and by utilizing current technologies to enhance exploitation, development and operational activities.

Environmental Considerations

The Trust is pro-active in its approach to environment concerns. Procedures are in place to ensure that due care is taken in the day-to-day management of its gas properties. All government regulations and procedures are followed in adherence to the law. The Trust believes in well abandonment and site restoration in a timely manner to ensure minimal damage to the environment and lower overall costs to the Trust.

RECORD OF CASH DISTRIBUTIONS

The accompanying table summarizes cash distributions from PET to its Unitholders since its inception.


Record Date	Payment Date	Distribution per Trust Unit
March 31, 2003	April 15, 2003	$	0.830
April 30, 2003	May 15, 2003	$	0.277
May 31, 2003	June 16, 2003	$	0.277
June 30, 2003	July 15, 2003	$	0.250
July 31, 2003	August 15, 2003	$	0.250
August 29, 2003	September 15, 2003	$	0.200
September 30, 2003	October 15, 2003	$	0.200
October 31, 2003	November 17, 2003	$	0.200
November 28, 2003	December 15, 2003	$	0.200
December 31, 2003	January 15, 2004	$	0.200
January 30, 2004	February 16, 2004	$	0.200
February 27, 2004	March 15, 2004	$	0.160

MARKET FOR SECURITIES

The outstanding Trust Units of PET are listed and posted for trading on the TSX under the symbol PMT.UN.

The following table sets forth the price range and trading volume of the Trust Units as reported by the TSX for the periods indicated.


Period	High			Low		Volume
2004
January		11.79			9.75		8,024,454
February		11.85			10.21		3,712,657
March 1-21		11.88			11.60		2,104,200
2003
February 7 to 28⁽¹⁾		32.51	⁽²⁾		11.75		2,408,997
March		15.45			12.70		4,291,899
April		13.40			12.60		3,074,616
May		14.46			12.69		4,682,153
June		13.99			8.46		8,703,963
July		10.45			8.25		6,813,923
August		10.31			9.81		3,673,243
September		10.90			9.45		3,183,273
October		11.45			10.25		2,222,921
November		11.45			10.93		2,179,434
December		11.86			11.03		5,185,763

Notes:

(1) The Trust Units commenced trading on the TSX on February 7, 2003.

(2) For the period from February 7 through February 11, 2003, the Trust Units were trading with three Rights attached. Adjusting for the $5.05 exercise price of the Rights, the high price for this period was $13.00.

ADDITIONAL INFORMATION RESPECTING PARAMOUNT ENERGY TRUST

The POT Royalty Agreement

Grant of Royalty

Under the POT Royalty Agreement, POT granted the POT Royalty to PET with respect to all petroleum and natural gas properties POT may acquire and hold 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.

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 PET’s lenders act upon their security, they may dispose of POT’s 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.

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. 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”. No fractional Trust Units will be issued or transferred except for the purposes of distributions of Trust Units referred to in “Description of the Trust Units and Special Voting Units – Distributions”.

In order to allow us flexibility in pursuing corporate acquisitions, the PET Trust Indenture allows for the creation and issuance of 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. 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 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 PET’s assets. Under the PET Trust Indenture material amendments to the PET Trust Indenture affecting the rights of Unitholders require the approval of Unitholders by a special resolution of at least 66 2/3% of the votes cast by Unitholders at a validly called meeting of Unitholders. See “The PET Trust Indenture – Meetings and Resolutions of Unitholders”.

The Trust Units do not represent a traditional investment and you should not view them as “shares” in PET. As a Unitholder, you do not have the statutory rights normally associated with ownership of shares of a corporation including, for example, the right to bring “oppression” or “derivative” actions. 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, our ability to extract additional production from our existing assets and our ability to acquire additional assets. Changes in market conditions may adversely affect the market price of the Trust Units. See “Risk Factors”.

The Trust Units are not “deposits” within the meaning of the Canada Deposit Insurance Corporation Act (Canada) and are not insured under the provisions of that act or any other legislation. Furthermore, 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:

• in connection with PET’s assets, obligations or affairs; or

• with respect to any act any person performs pursuant to the PET Trust Indenture; or

• 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

• with respect to any transaction any person enters into pursuant to the PET Trust Indenture.

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 entered into by or on behalf of PET 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 have obtained insurance, in amounts 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 distribute cash to the Unitholders out of the income and other amounts we receive from 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.

The material sources of PET’s cash flow are currently limited to:

• 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;

• interest and principal POT pays respecting indebtedness of POT to PET from time to time to finance its operations; and

• trust income POT distributes to PET as its sole beneficiary.

PET’s material expenses are currently substantially limited to:

• interest, principal and fees paid to its lenders;

• trustee fees and expenses;

• expenses related to printing and other matters in connection with communicating with and sending distributions to the Unitholders; and

• 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 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.

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:

• between record dates for distributions, we have paid cash in respect of Trust Units tendered for redemption (see “Description of the Trust Units and Special Voting Units — Redemption Right”), 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

• 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 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 their 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, including securities laws, of all jurisdictions, and the receipt of all applicable regulatory approvals, by the issuance of promissory notes of PET (referred to in this section and elsewhere as the “Notes” or the “PET 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 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:

• 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

• 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, including securities laws, of all jurisdictions, 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 and 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 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 as income, however, any portion designated as income will not reduce the amount of any declared and unpaid income distribution that the Unitholder may be entitled to receive at the time of redemption. In such case, the Unitholder would receive full payment of both the redemption amount (however designated) and the unpaid income distribution.

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 (referred to in this section as “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 (referred to in this section as 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, to the extent Non-Resident Unitholders have not sold the specified number of Trust Units, 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.

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.

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 from undertaking such engagements. The PET Trust Indenture specifies that the Administrator will require any such person to disclose to the Trustee any conflict of the interests of such persons with the interests of PET within a reasonable period of time after such person ascertains such conflict.

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”.

Investment Powers

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

• 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

• 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:

• 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

• 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, among other things:

• the appointment of the Trustee;

• the appointment or removal of our auditors; and

• the election or removal of the Administrator’s directors.

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

• removal of the Trustee;

• amending the PET Trust Indenture (except as described under “The PET Trust Indenture — Amendments to the PET Trust Indenture”);

• 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”);

• 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;

• 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”; 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;

• termination or winding-up of the affairs of PET; and

• 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 initial trustee. The Trustee may exercise all rights, powers and privileges that could be exercised by a beneficial owner of PET’s assets.

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.

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:

• any sale or surrender of any Royalty;

• any demand under, or sale or surrender, of any debt instruments;

• any sale or surrender of any interest that PET holds in POT or in any other entity it controls, directly or indirectly;

• any acquisition or disposition of permitted investments;

• any offering of securities;

• any terms and any amendment to certain material agreements of PET;

• any underwriting agreement;

• 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;

• any redemption of Trust Units;

• credit facilities, borrowings, hedging, security for indebtedness (including guarantees) or other agreement to facilitate our borrowing;

• any financial statements and tax filings;

• any compliance with PET’s legal or listing obligations;

• any calculation of distributions; and

• 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:

• without limiting the duties and obligations of the Transfer Agent, the countersigning, transferring and canceling of certificates representing Trust Units and the maintenance of registers of Unitholders;

• the payment and delivery of distributions to Unitholders;

• 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;

• waiving the performance or breach of the provisions of the PET Trust Indenture;

• terminating the PET Trust Indenture and certain material agreements of PET; and

• 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:

• any error in judgment;

• 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;

• any dealing with any asset that resulted in the depreciation of or loss to PET;

• any reliance on any evaluation or assessment provided by an appropriately qualified person;

• 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

• 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, willful 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, willful 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.

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, willful 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:

• ensuring that PET will comply with any applicable laws or requirements of any governmental agency or authority of Canada or of any province;

• 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;

• ensuring that such additional protection is provided for the interests of Unitholders as the Trustee may consider expedient;

• removing or curing any conflicts or inconsistencies between the provisions of the PET Trust Indenture or certain material agreements of PET, 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;

• making changes for any other purpose not inconsistent with the terms of the PET Trust Indenture and any 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

• 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.

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:

• 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

• 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.

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 presently the auditors and will hold office until the next 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 is subject to the continuous disclosure obligations under applicable securities legislation including the obligation to file quarterly and annual financial reports. PET’s year-end is 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.

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:

• sell, transfer, assign and convey all or any part of POT’s property;

• retain any investments in real or personal property which come into its possession as trustee;

• 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;

• vote any securities;

• act as the absolute representative of PET in respect of matters pertaining to the administration of the assets of POT;

• invest POT’s property and assets in investments of every nature;

• borrow money from or lend money to any person on such terms and conditions as the Administrator considers appropriate;

• assume debt, and pledge, mortgage or otherwise encumber POT’s properties;

• 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;

• 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;

• 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;

• institute, prosecute, and defend any suit, action, arbitration proceeding or other proceeding affecting the Administrator or POT’s properties;

• engage in rate swap transactions and derivatives for hedging purposes; and

• 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 willful misconduct. In addition, the Administrator shall cease to act as POT’s trustee if it:

• enters into a liquidation, whether compulsory or voluntary, except a voluntary liquidation for the purpose of amalgamation or reconstruction;

• 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

• 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 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.

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:

• the sale of any assets of POT to the Administrator;

• the amendment of any terms of the POT Trust Indenture;

• certain matters relating to the Administrator; and

• 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”.

Prohibited Amendments to POT Trust Indenture

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

• a change to a discretionary power of any mandatory duty imposed on the Administrator as trustee, unless the Administrator consents; or

• 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 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 (the “Board”) 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 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 the
of Residence	Administrator	Director Since	Principal Occupation
Clayton H. Riddell⁽⁴⁾ Calgary, Alberta	Chairman of the Board, Chief Executive Officer and Director	June 28, 2002	Chairman of the Board of PRL and Chief Executive Officer of PRL

Susan L. Riddell Rose⁽³⁾ Calgary, Alberta	President, Chief Operating Officer and Director	June 28, 2002	President and Chief Operating Officer of the Administrator

Cameron R. Sebastian Calgary, Alberta	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	Vice-President, Land, Legal and Acquisitions	—	Vice-President, Land, Legal and Acquisitions of the Administrator since June 28, 2002

Myra Jones Calgary, Alberta	Corporate Secretary	—	Corporate Secretary of the Administrator since June 28, 2002

Kevin J. Marjoram Calgary, Alberta	Vice-President, Operations	—	Vice-President, Operations of the Administrator since July 1, 2002


Name and Municipality	Offices held with the
of Residence	Administrator	Director Since	Principal Occupation
Brett Norris Calgary, Alberta	Vice President, New Ventures & Geosciences	—	Vice President, New Ventures & Geosciences since November 17, 2003

Donald J. Nelson ^{(1)(2)(3)(4)(7)} Calgary, Alberta	Director	June 28, 2002	President of Fairway Resources Inc. an oil and gas consulting firm.

John W. (Jack) Peltier ^(1)(2)(3)(7) Calgary, Alberta	Director	June 28, 2002	President of Ipperwash Resources Ltd., a private investment company

Karen A. Genoway ^(2)(4)(7) Calgary, Alberta	Director	June 28, 2002	Vice-President, Land, Onyx Energy Inc., a private oil and gas company

Howard R. Ward(1)(2)(7) Calgary, Alberta	Director	June 28, 2002	Partner with International Energy Counsel LLP, a law firm

Notes:

(1) Member of the Audit and Reserves Committee.

(2) Member of the Corporate Governance Committee.

(3) Member of the Environment and Safety 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.

The directors and officers of the Administrator, as a group, beneficially own, directly or indirectly, or exercise control or direction over, an aggregate of 19,833,963 Trust Units representing 44.3% of the outstanding Trust Units.

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. (2001 – 2003). 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

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, 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.

Brett Norris, Vice President, New Ventures & Geosciences

Brett Norris graduated in 1986 from the University of Toronto with a Bachelor of Science (Geology), and in 1989 from the University of Western Ontario with a Master’s of Science (Geology). Mr. Norris has been Vice-President, New Ventures and Geosciences of the Administrator since November 17, 2003. Prior to this, he worked at Nexen for 5.5 years, working in the International Division in the Yemen and Colombia operations groups, most recently holding the position of Exploitation Manager, Colombia Operations. Before this, he worked with several companies and has consulted independently, both domestically and internationally. Mr. Norris is a member of the Canadian Society of Petroleum Geologists (CSPG), the Association of Petroleum Engineers Geologists and Geophysicists of Alberta (APEGGA), and Society of Petroleum Engineers (SPE).

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

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 president of Fairway Resources Inc. a private firm providing consulting services to the oil and gas industry. 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. Mr. Nelson is also currently a director of Taylor NGL Limited Partnership (2003 – present) and Culane Energy Inc. (2003 – present).

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. 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. From June of 2002 to December of 2002 he was counsel with McCarthy Tetrault LLP. Effective December of 2002 he became a partner with International Energy Counsel LLP, a law firm. 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 Chief Executive Officer of PRL. Mr. Riddell anticipates devoting approximately 50% of his business time on efforts pertaining to POT, PET and the Administrator.

Board Committees

Corporate Governance Committee

The Corporate Governance Committee is responsible for the governance of the Board of the Administrator including the responsibility to review the mandate of the Board’s committees, recommending changes to size and composition of the Board and its committees and generally implementing good corporate governance practices. It oversees the effectiveness of management and management’s interaction with and responsiveness to the Board and reviews succession planning and recommends approval of the full Board. This Committee also conducts an annual survey to ensure that directors’ compensation is consistent with industry standards. The Corporate Governance Committee currently consists of Karen A. Genoway, John W. Peltier, Donald J. Nelson and Howard R. Ward, all of whom are outside directors.

Audit and Reserves Committee

The Audit and Reserves Committee reviews and recommends to the Board the approval of the annual and interim financial statements and the engagement of the Trust’s external auditors. It communicates directly with the auditors and reviews programs and policies regarding the effectiveness of internal controls over the Trust’s accounting and financial reporting systems. It also reviews insurance coverage and directors’ and officers’ liability insurance.

The Audit and Reserves Committee also reviews reserves estimates prepared by the Trust’s independent reserve engineers and in-house staff, estimated future net revenues, future development costs and timing, remaining tax pools and commodity prices and cost estimates used. The Audit and Reserves Committee currently consists of John W. Peltier, Donald J. Nelson and Howard R. Ward, all of whom are outside directors.

Compensation Committee

The Compensation Committee ensures that compensation policies are fair, equitable and competitive with the rest of the industry. It ensures that the incentive mechanism of remuneration is aligned with the interests of the Unitholders. It reviews existing management resources to ensure that they are adequate and that there is an efficient succession planning process in place. Once in each fiscal year, the Compensation Committee will review with the President the performance, development and succession of management of the Administrator. The Compensation Committee currently consists of Clayton H. Riddell, Donald J. Nelson and Karen A. Genoway.

Environment and Safety Committee

The Environment and Safety Committee reviews environmental and safety regulations, reviews and approves internal environment and safety policies and emergency response plans, reviews environmental, health and safety risks and ensures proper management of those risks. The Environment and Safety Committee currently consists of John W. Peltier, Donald J. Nelson and Susan L. Riddell Rose.

DISTRIBUTION REINVESTMENT AND OPTIONAL UNIT PURCHASE PLAN

PET has received required regulatory approvals for and established a Distribution Reinvestment and Optional Unit Purchase Plan (the “DRIP Plan”). Under the DRIP Plan, eligible Unitholders with the opportunity to reinvest monthly cash distributions to acquire additional Trust Units at 94 percent of the Treasury Purchase Price, which is defined as the daily volume weighted average trading prices of the Trust Units for the 10 trading days immediately preceding a distribution payment date. As well, subject to thresholds and restrictions described in the DRIP Plan, it contains a provision for the purchase of additional Trust Units with Optional Cash Payments of up to $100,000 per Participant per financial year of PET to acquire additional Trust Units at the same six percent discount to the Treasury Purchase Price. 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.

PET reserves the right to determine the number of DRIP Units available for purchase under the DRIP Plan for any distribution payment date. In respect of any distribution payment date, if fulfilling all of the elections under the DRIP Plan would result in our exceeding the limitations on the number of DRIP Units issuable under the DRIP 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.

PROMOTERS

The Administrator could be considered the promoter of the Trust. The Administrator holds 1 Trust Unit or less than 0.01% of the issued and outstanding Trust Units.

LEGAL PROCEEDINGS

There are no outstanding legal proceedings which are for claims in excess of 10% of the current asset value of the Trust to which the Trust is a party or in respect of which any of its properties are subject, nor are there any such proceedings known to be contemplated.

INTEREST OF INSIDERS AND OTHERS IN MATERIAL TRANSACTIONS

There were no material interests, direct or indirect, of directors and senior officers of the Administrator, nominees for director of the Administrator, any Unitholder who beneficially owns more than 10% of the Trust Units or any known associate or affiliate of such persons in any transaction during 2003 or in any proposed transaction which has materially affected or would materially affect the Trust or the Administrator other than (i) certain insiders purchasing Trust Units under the public offerings of such securities completed during 2003, and (ii) as disclosed herein.

AUDITORS, TRANSFER AGENT AND REGISTRAR

The auditors of the Trust are KPMG LLP, Chartered Accountants, Calgary, Alberta.

Computershare Trust Company of Canada at its offices in Calgary, Alberta and Toronto, Ontario acts as the transfer agent and registrar for the Trust Units.

MATERIAL CONTRACTS

Except for contracts entered into by the Trust in the ordinary course of business or otherwise disclosed herein, the only material contracts entered into or to be entered into by the Trust which can reasonably be regarded as presently material are the following:

1. the PET Trust Indenture;

2. the POT Trust Indenture; and

3. the POT Royalty Agreement.

INTEREST OF EXPERTS

Burnet, Duckworth & Palmer LLP, Calgary, Alberta has aided in the preparation of this Initial Annual Information Form and McDaniel & Associates Consultants Ltd., has certified certain of the contents herein. No person or company whose profession or business gives authority to a statement made by such person or company and who is named in this Initial Annual Information Form or in a document that is specifically incorporated by reference into this Initial Annual Information Form as having prepared or certified a part of this Initial Annual Information Form, or a report or valuation described in this Initial Annual Information Form or in a document specifically incorporated by reference into this Initial Annual Information Form, has received or shall receive a direct or indirect interest in the property of the Trust or of any associate or affiliate of the Trust. As at the date hereof, the aforementioned persons and companies beneficially own, directly or indirectly, less than 1% of the securities of the Trust and its associates and affiliates. In addition, none of the aforementioned persons or companies, nor any director, officer or employee of any of the aforementioned persons or companies, is or is expected to be elected, appointed or employed as a director, officer or employee of the Trust or of any associates or affiliates of the Trust.

SELECTED CONSOLIDATED FINANCIAL INFORMATION AND
MANAGEMENT DISCUSSION AND ANALYSIS FOR THE YEAR ENDED DECEMBER 31, 2003

Selected consolidated financial information and management discussion and analysis of PET for the year ended December 31, 2003 can be found in PET’s Management Discussion and Analysis. Such information has been filed on SEDAR at www.sedar.com and is specifically incorporated by reference herein.

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 Initial Annual Information Form, including our financial statements and the related notes.

There is uncertainty with respect to our ability to produce a substantial portion of our natural gas reserves.

Recent proposals by the AEUB have brought into question our ability to continue to produce natural gas from the Wabiskaw and McMurray formations in certain parts of Northeast Alberta as the AEUB is proposing to shut-in production from such area. We cannot at this time accurately estimate the amount of production which may be shut-in, if any, and for what duration. We also cannot ensure that PET 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. See “Government Regulations – Regulatory Rulings”.

Adverse regulatory decisions regarding applications or policies for the shut-in of natural gas wells may materially affect our assets and operations.

All of our assets are presently located in Northeast Alberta. Actions by the AEUB restricting the production of natural gas in northeast Alberta have reduced natural gas production in the area and are likely to do so in the future. Such actions may have a material adverse effect on our production and cash flow, and on the amount of income available for distribution to our Unitholders. See “Government Regulations — Regulatory Rulings”.

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 PET’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. PET 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, PET’s production levels and reserves will decline over time.

PET’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 our current assets, the unit production costs increase. Without reserve additions through acquisition or development activities, PET’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, PET’s ability to make the necessary capital investments to maintain or expand its oil and natural gas reserves will be impaired. If PET uses production revenue to finance capital expenditures or property acquisitions, the level of distributable income to you will be reduced.

Our reserve data regarding our current 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.

Our title to our 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 our 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.

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 credit 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.

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 labour 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 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. 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.

Our operations may expand into other jurisdictions.

The operations and expertise of management of the Trust are currently focused on conventional gas production and development in the Western Canadian Sedimentary Basin. In the future, the Trust may acquire gas properties outside this geographic area. In addition, the Trust Indenture does not limit the activities of the Trust to gas production and development, and the Trust could acquire other energy related assets, such as oil and natural gas processing plants or pipelines, or an interest in an oil sands project. Expansion of our activities into new areas may present new additional risks or alternatively, significantly increase the exposure to one or more of the present risk factors which may result in future operational and financial conditions of the Trust being adversely affected.

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, PET may be forced to pay more for attractive properties or be unable to acquire new assets efficiently, which would materially adversely affect PET’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. 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” for a description of our management, including their experience and qualifications.

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. This could result in the loss by us of attractive business opportunities or of talented personnel.

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

The continuing production from less than 10% of our current 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 willful misconduct of the operator. The expense of bringing such an action could be significant and we may 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.

We may be unable to secure additional financing.

PET’s primary source of bank financing is a demand credit facility with a syndicate of Canadian chartered banks in the amount of $100 million. The credit facility is presently due April 30, 2004. PET expects that the facility will be extended at that date. If that does not occur then PET will need to find alternative sources of financing. If alternative sources of financing are not available, or are more expensive than the current credit facility, then PET, POT and the Administrator may be unable to effectively operate their business or to pay distributions on the Trust Units.

In addition, 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 favourable 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”.

You may suffer dilution of your interest in PET.

To maintain or expand PET’s oil and natural gas reserves 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”, and “Description of the Trust Units and Special Voting Units – PET Unitholder Liability”.

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 favourable.

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 favourable, in order to comply with these restrictions. See “Description of the Trust Units and Special Voting Units – Non-Resident Unitholders”.

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 the 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.

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.

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. U.S. natural gas markets and prices have a significant effect on Canadian natural gas prices. A material increase in the value of the Canadian dollar may negatively impact our production revenue.

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.

Changes in legislation could materially adversely affect our business.

There can be no assurance that the treatment of mutual fund trusts will not be changed in a manner which adversely affects Trust Unitholders. If the Trust ceases to qualify as a “mutual fund trust” under the Tax Act, the Trust Units will cease to be qualified

investments for registered retirement savings plans, registered education savings plans, deferred profit sharing plans and registered retirement income funds.

Income tax laws, or other laws or government incentive programs relating to the oil and gas industry, such as the treatment of mutual fund trusts and resource taxation, may in the future be changed or interpreted in a manner that adversely affects the Trust and its Unitholders. Tax authorities having jurisdiction over the Trust or the Unitholders may disagree with how the Trust calculates its income for tax purposes or could change administrative practises to the detriment of the Trust or the detriment of its Unitholders.

The Administrator intends that the Trust will continue to qualify as a mutual fund trust for purposes of the Tax Act. The Trust may not, however, always be able to satisfy any future requirements for the maintenance of mutual fund trust status. Should the status of the Trust as a mutual fund trust be lost or successfully challenged by a relevant tax authority, certain adverse consequences may arise for the Trust and its Unitholders. Some of the significant consequences of losing mutual fund trust status are as follows:

• The Trust would be taxed on certain types of income distributed to Unitholders, including income generated by the royalties held by the Trust. Payment of this tax may have adverse consequences for some Unitholders, particularly Unitholders that are not residents of Canada and residents of Canada that are otherwise exempt from Canadian income tax.

• The Trust would cease to be eligible for the capital gains refund mechanism available under Canadian tax laws if it ceased to be a mutual fund trust.

• Trust Units held by Unitholders that are not residents of Canada would become taxable Canadian property. These non-resident holders would be subject to Canadian income tax on any gains realized on a disposition of Trust Units held by them.

• Trust Units would not constitute qualified investments for registered retirement savings plans (“RRSPs”), registered retirement income funds (“RRIFs”), registered education savings plans (“RESTs”) or deferred profit sharing plans (“DPSPs”). If, at the end of any month, one of these exempt plans holds Trust Units that are not qualified investments, the plan must pay a tax equal to 1% of the fair market value of the Trust Units at the time the Trust Units were acquired by the exempt plan. An RRSP or RRIF holding non-qualified Trust Units would be subject to taxation on income attributable to the Trust Units. If an RESP holds non-qualified Trust Units, it may have its registration revoked by the Canada Customs and Revenue Agency.

In addition, the Administrator may take certain measures in the future to the extent it believes necessary to ensure that the Trust maintains its status as a mutual fund trust. These measures could be adverse to certain holders of Trust Units, particularly “non-residents” of Canada as defined in the Tax Act.

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 has adopted the 1997 Kyoto Protocol to the United Nations Framework Convention on Climate Change, known as the Kyoto Protocol. As a result, new requirements and regulations may be implemented which would 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.

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 investments by registered retirement savings plans, deferred profit sharing plans, registered retirement income funds and registered education savings plans. Should the Trust Units become non-qualified investments for purposes of being held in such plans, the plans might become liable for penalties and the market for the Trust Units both immediately and in the future may be adversely affected.

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

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 U.S. 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 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.

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. None of the wells currently drilled on the properties comprising the PET 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. See “Risk Factors” for a discussion of the Kyoto Protocol.

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, approximately 44.3% of the outstanding Trust Units. Additionally, some of our directors are directors of other industry participants who might be our competitors. See “The Administrator”.

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 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.

ADDITIONAL INFORMATION

Additional information, including directors’ and officers’ remuneration and indebtedness, principal holders of securities and interests of insiders in material transactions, where applicable, is contained in the Information Circular of the Trust with respect to the annual meeting of Unitholders to be held May 13, 2004. Additional financial information is provided in Paramount’s financial statements for the year ended December 31, 2003.

The Trust shall provide to any person, upon request to the Chief Financial Officer:

1. when the securities of the Trust are in the course of a distribution pursuant to a preliminary short form prospectus or a short form prospectus:

(a) one copy of the Initial Annual Information Form of the Trust, together with one copy of any document, or the pertinent pages of any document, incorporated by reference in the Initial Annual Information Form;

(b) one copy of the comparative financial statements of Paramount for its most recently completed fiscal period for which financial statements have been filed, together with the accompanying report of the auditor and one copy of the most recent interim financial statements of the Trust that have been filed, if any, for any period after the end of its most recently completed financial year;

•		the size of the Trust’s natural gas reserves;

•		estimates of future cash flow and distributions;

•		projections of market prices and costs and the related sensitivities to distributions;

•		natural gas production levels;

•		capital expenditure programs;

•		supply and demand for natural gas;

•		expectations regarding the ability to raise capital and to continually add to reserves through acquisitions and development; and

•		treatment under governmental regulatory regimes both existing and proposed.

•		volatility in market prices for natural gas;

•		liabilities inherent in natural gas operations;

•		adverse regulatory rulings, orders and decisions;

•		uncertainties associated with estimating natural gas reserves;

•		competition for, among other things, capital, acquisitions of reserves, undeveloped lands and skilled personnel;

•		incorrect assessments of the value of acquisitions;

•		geological, technical, drilling and processing problems; and

•		the other factors discussed under “Risk Factors”.

•		POT acquired PRL’s natural gas properties and facilities in the Legend, Alberta area (the Initial Assets) in exchange for the issuance by POT to PRL of an $81 million promissory note. POT assumed all risks on these assets, and revenues and expenses associated with these assets accrued to POT for POT’s account, effective July 1, 2002;

•		PRL and POT entered into a purchase and sale agreement whereunder POT agreed to acquire from PRL up to 100% of PRL’s interests in most of its remaining natural gas properties in northeast Alberta (the Additional Assets); and

•		POT and PET entered into the POT Royalty Agreement effective July 1, 2002 pursuant to which POT granted the POT Royalty to PET over all of POT’s natural resource properties and all natural resource properties POT may acquire from time to time. As a result of a number of steps completed in connection with the payment of the consideration for the POT Royalty, PET issued 9,909,766 Trust Units to PRL and acquired the remaining $16,848,000 in indebtedness that POT owed to PRL.

	(a)		reviewed the Trust’s procedures for providing information to McDaniel;

	(b)		met with McDaniel to determine whether any restrictions affected the ability of McDaniel to report without reservation and to inquire whether there has been any disputes between McDaniel and management; and

	(c)		reviewed the reserves data with management and McDaniel.

	(a)		the content and filing with securities regulatory authorities of the reserves data and other oil and gas information;

	(b)		the filing of the report of McDaniel on the reserves data; and

	(c)		the content and filing of this report.

2.		The reserves data are the responsibility of the Trust’s management. Our responsibility is to express an opinion on the reserves data based on our evaluation.

		We carried out our evaluation in accordance with standards set out in the Canadian Oil and Gas Evaluation Handbook (the “COGE Handbook”) prepared jointly by the Society of Petroleum Evaluation Engineers (Calgary Chapter) and the Canadian Institute of Mining, Metallurgy & Petroleum (Petroleum Society).

3.		Those standards require that we plan and perform an evaluation to obtain reasonable assurance as to whether the reserves data are free of material misstatement. An evaluation also includes assessing whether the reserves data are in accordance with principles and definitions presented in the COGE Handbook.

4.		The following table sets forth the estimated future net revenue (before deduction of income taxes) attributed to proved plus probable reserves, estimated using forecast prices and costs and calculated using a discount rate of 10 percent, included in the reserves data of the Trust evaluated by us for the year ended December 31, 2003, and identifies the respective portions thereof that we have evaluated and reported on to the Trust’s board of directors:

5.		In our opinion, the reserves data evaluated by us have, in all material respects, been determined and are in accordance with the COGE Handbook. We express no opinion on the reserves data that we reviewed but did not audit or evaluate.

6.		We have no responsibility to update our reports referred to in paragraph 4 for events and circumstances occurring after their respective preparation dates.

7.		Because the reserves data are based on judgements regarding future events, actual results will vary and the variations may be material.

(1)		“Without Gas/Bitumen” represents those reserves not recommended for shut-in by the AEUB Staff Submission Group.

(2)		“With Gas/Bitumen” represents those reserves recommended for shut-in by the AEUB Staff Submission Group. Reserves related to production which is currently shut-in as a result of AEUB Interim Shut-in Order 03-001 have been categorized as probable reserves.

1.		Columns may not add due to rounding.

2.		The crude oil, natural gas liquids and natural gas reserve estimates presented in the McDaniel Report are based on the definitions and guidelines contained in the COGE Handbook. A summary of those definitions are set forth below.

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

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

	(a)		gain access to and prepare well locations for drilling, including surveying well locations for the purpose of determining specific development drilling sites, clearing ground, draining, road building, and relocating public roads, gas lines and power lines, pumping equipment and wellhead assembly;

	(b)		drill and equip development wells, development type stratigraphic test wells and service wells, including the costs of platforms and of well equipment such as casing, tubing, pumping equipment and wellhead assembly;

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

	(d)		provide improved recovery systems.

	(b)		costs of carrying and retaining unproved properties, such as delay rentals, taxes (other than income and capital taxes) on properties, legal costs for title defence, and the maintenance of land and lease records;

	(c)		dry hole contributions and bottom hole contributions;

	(d)		costs of drilling and equipping exploratory wells; and

	(e)		costs of drilling exploratory type stratigraphic test wells.

	(a)		in relation to the Trust’s interest in production and reserves, its “Trust gross reserves”, which are the Trust’s interest (operating and non-operating) share before deduction of royalties and without including any royalty interest of the Trust;

	(b)		in relation to wells, the total number of wells in which the Trust has an interest; and

	(c)		in relation to properties, the total area of properties in which the Trust has an interest.

	(a)		in relation to the Trust’s interest in production and reserves, the Trust’s interest (operating and non-operating) share after deduction of royalties obligations, plus the Trust’s royalty interest in production or reserves.

	(b)		in relation to wells, the number of wells obtained by aggregating the Trust’s working interest in each of its gross wells; and

	(c)		in relation to the Trust’s interest in a property, the total area in which the Trust has an interest multiplied by the working interest owned by the Trust.

•		analysis of drilling, geological, geophysical and engineering data;

•		the use of established technology; and

•		specified economic conditions.

	(a)		Proved reserves are those reserves that can be estimated with a high degree of certainty to be recoverable. It is likely that the actual remaining quantities recovered will exceed the estimated proved reserves.

	(b)		Probable reserves are those additional reserves that are less certain to be recovered than proved reserves. It is equally likely that the actual remaining quantities recovered will be greater or less than the sum of the estimated proved plus probable reserves.

	(i)		Developed producing reserves are those reserves that are expected to be recovered from completion intervals open at the time of the estimate. These reserves may be currently producing or, if shut-in, they must have previously been on production, and the date of resumption of production must be known with reasonable certainly.

	(ii)		Developed non-producing reserves are those reserves that either have not been on production, or have previously been on production, but are shut-in, and the date of resumption of production is unknown.

	(a)		at least a 90 percent probability that the quantities actually recovered will equal or exceed the estimated proved reserves; and

	(b)		at least a 50 percent probability that the quantities actually recovered will equal or exceed the sum of the estimated proved plus probable reserves.

(1)		Inflation rates for forecasting prices and costs.

(2)		Exchange rates used to generate the benchmark reference prices in this table.

(1)		“Gross” refers to the number of wells, producing and non-producing, respectively, in which a working interest or royalty interest is held by PET.

(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, markets and/or awaiting regulatory approval to commence production but are capable of producing in commercial quantities.

(4)		Allowance for the abandonment costs associated with the wellbores was made in the McDaniel Report. There are 18 wells that are classified as service wells not included in the gross/net well count.

(1)		“Gross” means the total number of developed and undeveloped acres, respectively, in which PET has an interest in respect of its current assets.

(2)		“Net” means the aggregate of the numbers obtained by multiplying each gross acre by the actual percentage interest therein.

(3)		During 2004, 192,960 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)		“Undeveloped Acres” refers to land where no reserves have been assigned by McDaniel in the McDaniel Report.

•		removal of the Trustee;

•		amending the PET Trust Indenture (except as described under “The PET Trust Indenture — Amendments to the PET Trust Indenture”);

•		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”);

•		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;

(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”; 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;

(1)		Member of the Audit and Reserves Committee.

(2)		Member of the Corporate Governance Committee.

(3)		Member of the Environment and Safety 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.

1.		the PET Trust Indenture;

2.		the POT Trust Indenture; and

3.		the POT Royalty Agreement.

•		modify operations;

•		install pollution control equipment;

•		perform site clean-ups; or

•		curtail or cease certain operations.

(a)		one copy of the Initial Annual Information Form of the Trust, together with one copy of any document, or the pertinent pages of any document, incorporated by reference in the Initial Annual Information Form;

(b)		one copy of the comparative financial statements of Paramount for its most recently completed fiscal period for which financial statements have been filed, together with the accompanying report of the auditor and one copy of the most recent interim financial statements of the Trust that have been filed, if any, for any period after the end of its most recently completed financial year;

(c)		one copy of the Information Circular of the Trust in respect of its most recent annual and special meeting of Unitholders; and

(d)		one copy of any other documents that are incorporated by reference into the preliminary short form prospectus or the short form prospectus and which are not required to be provided under items (a) to (c) above; or