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Exhibit 99.1 PARAMOUNT ENERGY TRUST REVISED INITIAL ANNUAL INFORMATION FORM FOR THE YEAR ENDED DECEMBER 31, 2003 March 22, 2004




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TABLE OF CONTENTS PageGLOSSARY
    
    
    1ABBREVIATIONS
    
    
    3CONVERSION
    
    
    3SPECIAL NOTE REGARDING FORWARD-LOOKING STATEMENTS
    
    
    4PARAMOUNT ENERGY TRUST
    
    
    5GENERAL DEVELOPMENT OF THE BUSINESS
    
    
    6DESCRIPTION OF THE BUSINESS AND PLAN OF OPERATIONS
    
    
    8RECENT DEVELOPMENTS
    
    
    9REPORT OF MANAGEMENT AND DIRECTORS ON RESERVES DATA AND OTHER INFORMATION
    
    
    10REPORT ON RESERVES DATA
    
    
    11STATEMENT OF RESERVES DATA AND OTHER OIL AND GAS INFORMATION
    
    
    12RECORD OF CASH DISTRIBUTIONS
    
    
    30MARKET FOR SECURITIES
    
    
    30ADDITIONAL INFORMATION RESPECTING PARAMOUNT ENERGY TRUST
    
    
    31DESCRIPTION OF THE TRUST UNITS AND SPECIAL VOTING UNITS
    
    

    32THE ADMINISTRATOR
    
    
    45DIRECTORS AND OFFICERS
    
    
    45DISTRIBUTION REINVESTMENT AND OPTIONAL UNIT PURCHASE PLAN
    
    
    49PROMOTERS
    
    
    50LEGAL PROCEEDINGS
    
    
    50INTEREST OF INSIDERS AND OTHERS IN MATERIAL TRANSACTIONS
    
    
    50AUDITORS, TRANSFER AGENT AND REGISTRAR
    
    
    50MATERIAL CONTRACTS
    
    
    50INTEREST OF EXPERTS
    
    
    50SELECTED CONSOLIDATED FINANCIAL INFORMATION AND MANAGEMENT DISCUSSION AND
ANALYSIS FOR THE YEAR ENDED DECEMBER 31, 2003
    
    
    51RISK FACTORS
    
    
    51GOVERNMENT REGULATIONS
    
    
    58CONFLICTS OF INTEREST
    
    
    60ADDITIONAL INFORMATION
    
    
    60
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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




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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; 2




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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 Gasbbls
    
    barrels
    
    mcf
    
    
    
    thousand cubic feetmbbls
    
    thousand barrels
    
    mmcf
    
    
    
    million cubic feetmmbbls
    
    million barrels
    
    bcf
    
    
    
    billion cubic feetNGLs
    
    natural gas liquids
    
    mcf/d
    
    
    
    thousand cubic feet per daystb
    
    stock tank barrels of oil
    
    mmcf/d
    
    
    
    million cubic feet per daymstb
    
    thousand stock tank barrels of oil
    
    m3
    
    
    
    cubic metresmmboe
    
    million barrels of oil equivalent
    
    mmbtu
    
    
    
    million British Thermal Unitsboe/d
    
    barrels of oil equivalent per day
    
    GJ
    
    
    
    Gigajoulebbls/d
    
    barrels of oil per day
 OtherBOE 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 Bymcf
    
    cubic metres
    
    
    28.174cubic metres
    
    cubic feet
    
    
    35.494bbls
    
    cubic metres
    
    
    0.159cubic metres
    
    bbls
    
    
    6.289feet
    
    metres
    
    
    0.305metres
    
    feet
    
    
    3.281miles
    
    kilometres
    
    
    1.609kilometres
    
    miles
    
    
    0.621acres
    
    hectares
    
    
    0.405hectares
    
    acres
    
    
    2.471gigajoules
    
    mmbtu
    
    
    0.950
 3




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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. 4




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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. 5




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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 6




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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. 7




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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. 8




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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. 9




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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. MarjoramChairman and Chief Executive Officer
    
    Vice President Operations(signed) John W. Peltier
    
    (signed) Donald J. NelsonJohn W. Peltier
    
    Donald J. NelsonDirector
    
    DirectorMarch 18, 2004
 10




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##### 



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 RevenueDescription and
    
    
    
    (before income taxes, 10% discount rate)Independent Qualified Reserves
    
    Preparation Date ofEvaluator
    
    Evaluation Report
    
    Location of Reserves
    
    Audited
    
    Evaluated
    
    Reviewed
    
    TotalMcDaniel & Associates Consultants Ltd.
    
    December 31, 2003
    
    CanadaWells Not Affected by Gas over
Bitumen Issues
    
    
    
    
    
    
    
    $
    225,243
    
    
    
    
    $
    225,243Wells Identified for Shut-in
    
    
    
    
    
    
    
    $
    48,672
    
    
    
    
    $
    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 11




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##### 



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 REVENUEBEFORE TAX DISCOUNTED ATRESERVES CATEGORIES
    
    NATURAL GAS
    
    (%/year)(1)Gross
    
    Net
    
    0%
    
    10%
    
    15%
    
    20%mmcf
    
    mmcf
    
    (M$)
    
    (M$)
    
    (M$)
    
    (M$)PROVEDDeveloped Producing
    
    
    115,219
    
    
    
    93,931
    
    
    
    379,244
    
    
    
    289,565
    
    
    
    259,941
    
    
    
    236,417Developed Non-Producing
    
    
    7,393
    
    
    
    6,209
    
    
    
    16,643
    
    
    
    14,224
    
    
    
    13,192
    
    
    
    12,295Undeveloped
    
    
    656
    
    
    
    544
    
    
    
    996
    
    
    
    748
    
    
    
    645
    
    
    
    555TOTAL PROVED
    
    
    123,268
    
    
    
    100,684
    
    
    
    396,883
    
    
    
    304,537
    
    
    
    273,778
    
    
    
    249,267PROBABLE
    
    
    25,519
    
    
    
    20,977
    
    
    
    91,885
    
    
    
    46,079
    
    
    
    35,391
    
    
    
    28,303TOTAL 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. 12




---



##### 



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
    
    WithReserves Category
    
    Gas/Bitumen(1)
    
    Gas/Bitumen(2)
    
    Total
    
    Gas/Bitumen(1)
    
    Gas/Bitumen(2)
    
    TotalPROVEDDeveloped Producing
    
    
    101,042
    
    
    
    14,176
    
    
    
    115,218
    
    
    
    82,026
    
    
    
    11,905
    
    
    
    93,931Non-Producing
    
    
    2,826
    
    
    
    4,567
    
    
    
    7,393
    
    
    
    2,267
    
    
    
    3,942
    
    
    
    6,209Undeveloped
    
    
    656
    
    
    
    
    
    
    
    656
    
    
    
    544
    
    
    
    
    
    
    
    544TOTAL PROVED
    
    
    104,524
    
    
    
    18,743
    
    
    
    123,267
    
    
    
    84,837
    
    
    
    15,847
    
    
    
    100,684PROBABLE
    
    
    16,318
    
    
    
    9,202
    
    
    
    25,520
    
    
    
    13,173
    
    
    
    7,804
    
    
    
    20,977TOTAL 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
    
    
    
    
    
    FUTURENET
    
    
    
    
    
    NETREVENUE
    
    
    
    
    
    REVENUEWELL
    
    BEFORE
    
    
    
    
    
    AFTERRESERVES
    
    
    
    
    
    
    
    
    
    OPERATING
    
    DEVELOPMENT
    
    ABANDONMENT
    
    INCOME
    
    INCOME
    
    INCOMECATEGORY
    
    REVENUE
    
    ROYALTIES
    
    COSTS
    
    COSTS
    
    COSTS
    
    TAXES
    
    TAXES(1)
    
    TAXES(1)Proved Reserves
    
    
    733,046
    
    
    
    119,303
    
    
    
    182,059
    
    
    
    4,469
    
    
    
    30,332
    
    
    
    396,883
    
    
    
    
    
    
    
    396,883Proved Plus
Probable Reserves
    
    
    884,148
    
    
    
    143,782
    
    
    
    216,647
    
    
    
    4,630
    
    
    
    30,321
    
    
    
    488,768
    
    
    
    
    
    
    
    488,768
 Note:  (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. 13




---



##### 



FUTURE NET REVENUE
BY PRODUCTION GROUP
as of December 31, 2003
CONSTANT PRICES AND COSTS FUTURE NET REVENUEBEFORE INCOME TAXESRESERVES
    
    
    
    (discounted at 10%/year)CATEGORY
    
    PRODUCTION GROUP
    
    (M$)Proved Reserves
    
    Natural Gas (including by-products but excluding solution gas from oil wells)
    
    
    304,537Proved 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 REVENUEBEFORE TAX DISCOUNTED ATRESERVES CATEGORIES
    
    NATURAL GAS
    
    (%/year)(1)Gross
    
    Net
    
    0%
    
    10%
    
    15%
    
    20%mmcf
    

    mmcf
    
    (M$)
    
    (M$)
    
    (M$)
    
    (M$)PROVEDDeveloped Producing
    
    
    115,218
    
    
    
    93,931
    
    
    
    284,708
    
    
    
    228,989
    
    
    
    209,365
    
    
    
    193,307Developed Non-Producing
    
    
    7,393
    
    
    
    6,209
    
    
    
    9,916
    
    
    
    9,663
    
    
    
    9,299
    
    
    
    8,917Undeveloped
    
    
    656
    
    
    
    544
    
    
    
    572
    
    
    
    416
    
    
    
    346
    
    
    
    283TOTAL PROVED
    
    
    123,267
    
    
    
    100,684
    
    
    
    295,196
    
    
    
    239,068
    
    
    
    219,010
    
    
    
    202,507PROBABLE
    
    
    25,520
    
    
    
    20,977
    
    
    
    66,924
    
    
    
    34,847
    
    
    
    27,192
    
    
    
    22,061TOTAL PROVED PLUS PROBABLE
    
    
    148,787
    
    
    
    121,661
    
    
    
    362,120
    
    
    
    273,915
    
    
    
    246,202
    
    
    
    224,568
 Note:  (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. TOTAL FUTURE NET REVENUE
(UNDISCOUNTED)
as of December 31, 2003
FORECAST PRICES AND COSTS ($000s) FUTURE
    
    
    
    
    
    FUTURENET
    
    
    
    
    
    NETREVENUE
    
    
    
    
    
    REVENUEWELL
    
    BEFORE
    
    
    
    
    
    AFTERRESERVES
    
    
    
    
    
    
    
    
    
    OPERATING
    
    DEVELOPMENT
    
    ABANDONMENT
    
    INCOME
    
    INCOME
    
    INCOMECATEGORY
    
    REVENUE
    
    ROYALTIES
    
    COSTS
    
    COSTS
    
    COSTS
    
    TAXES
    
    TAXES(1)
    
    TAXES(1)Proved Reserves
    
    
    635,712
    
    
    
    99,574
    
    
    
    200,550
    
    
    
    4,565
    
    
    
    35,827
    
    
    
    295,196
    
    
    
    
    
    
    
    295,196Proved Plus
Probable Reserves
    
    
    766,053
    
    
    
    119,436
    
    
    
    243,490
    
    
    
    4,734
    
    
    
    36,273
    
    
    
    362,120
    
    
    
    
    
    
    
    362,120
 14




---



##### 



Note:  (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. FUTURE NET REVENUE
BY PRODUCTION GROUP
as of December 31, 2003
FORECAST PRICES AND COSTS FUTURE NET REVENUEBEFORE INCOME TAXESRESERVES
    
    
    
    (discounted at 10%/year)CATEGORY
    
    PRODUCTION GROUP
    
    (M$)Proved Reserves
    
    Natural Gas (including by-products but excluding solution gas from oil wells)
    
    
    239,068Proved 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; 15




---



##### 



(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 reservesare 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 reservesare 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. 16




---



##### 



Each of the reserve categories (proved and probable) may be divided into
developed and undeveloped categories:  (a)
    
    Developed reservesare 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 reservesare 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 reservesare 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 reservesare 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 ColumbiaAlberta Average
    
    Sask. Prov. Gas
    
    CanWestPlantgate
    
    Plantgate
    
    PlantgateYear
    
    Cdn$/Mmbtu
    
    Cdn$/Mmbtu
    
    Cdn$/MmbtuHistorical(1) 2003
    
    
    5.87
    
    
    
    5.70
    
    
    
    5.25
 17




---



##### 



Note:  (1)
    
    As at December 31. FORECAST PRICES AND COSTS British Columbia
    
    
    
    
    
    US/CADAECO
    
    Alberta Average
    
    Aggregator
    
    Alberta Spot
    
    Sask. Prov. Gas
    
    CanWest
    
    
    
    
    
    ExchangeSpot Price
    
    Plantgate
    
    Plantgate
    
    Sales Plantgate
    
    Plantgate
    
    Plantgate
    
    
    
    
    
    RateForecast
    
    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
    
    
    
    0.752005
    
    
    5.19
    
    
    
    5.30
    
    
    
    5.30
    
    
    
    5.30
    
    
    
    5.45
    
    
    
    5.20
    
    
    
    2.0
    
    
    
    0.752006
    
    
    4.87
    
    
    
    4.95
    
    
    
    4.95
    
    
    
    4.95
    
    
    
    5.15
    
    
    
    4.85
    
    
    
    2.0
    
    
    
    0.752007
    
    
    4.68
    
    
    
    4.75
    
    
    
    4.75
    
    
    
    4.75
    
    
    
    4.95
    
    
    
    4.65
    
    
    
    2.0
    
    
    
    0.752008
    
    
    4.53
    
    
    
    4.60
    
    
    
    4.60
    
    
    
    4.60
    
    
    
    4.80
    
    
    
    4.50
    
    
    
    2.0
    
    
    
    0.752009
    
    
    4.57
    
    
    
    4.65
    
    
    
    4.65
    
    
    
    4.65
    
    
    
    4.85
    
    
    
    4.55
    
    
    
    2.0
    
    
    
    0.752010
    
    
    4.60
    
    
    
    4.65
    
    
    
    4.65
    
    
    
    4.65
    
    
    
    4.85
    
    
    
    4.55
    
    
    
    2.0
    
    
    
    0.752011
    
    
    4.69
    
    
    
    4.75
    
    
    
    4.75
    
    
    
    4.75
    
    
    
    4.95
    
    
    
    4.65
    
    
    
    2.0
    
    
    
    0.752012
    
    
    4.78
    
    
    
    4.85
    
    
    
    4.85
    
    
    
    4.85
    
    
    
    5.05
    
    
    
    4.75
    
    
    
    2.0
    
    
    
    0.752013
    
    
    4.87
    
    
    
    4.95
    
    
    
    4.95
    
    
    
    4.95
    
    

    
    5.15
    
    
    
    4.85
    
    
    
    2.0
    
    
    
    0.752014
    
    
    4.97
    
    
    
    5.05
    
    
    
    5.05
    
    
    
    5.05
    
    
    
    5.25
    
    
    
    4.95
    
    
    
    2.0
    
    
    
    0.752015
    
    
    5.08
    
    
    
    5.15
    
    
    
    5.15
    
    
    
    5.15
    
    
    
    5.35
    
    
    
    5.05
    
    
    
    2.0
    
    
    
    0.752016
    
    
    5.19
    
    
    
    5.25
    
    
    
    5.25
    
    
    
    5.25
    
    
    
    5.45
    
    
    
    5.15
    
    
    
    2.0
    
    
    
    0.752017
    
    
    5.29
    
    
    
    5.35
    
    
    
    5.35
    
    
    
    5.35
    
    
    
    5.55
    
    
    
    5.25
    
    
    
    2.0
    
    
    
    0.752018
    
    
    5.40
    
    
    
    5.45
    
    
    
    5.45
    
    
    
    5.45
    
    
    
    5.65
    
    
    
    5.35
    
    
    
    2.0
    
    
    
    0.752019
    
    
    5.51
    
    
    
    5.60
    
    
    
    5.60
    
    
    
    5.60
    
    
    
    5.85
    
    
    
    5.50
    
    
    
    2.0
    
    
    
    0.752020
    
    
    5.61
    
    
    
    5.70
    
    
    
    5.70
    
    
    
    5.70
    
    
    
    5.95
    
    
    
    5.60
    
    
    
    2.0
    
    
    
    0.752021
    
    
    5.72
    
    
    
    5.80
    
    
    
    5.80
    
    
    
    5.80
    
    
    
    6.05
    
    
    
    5.70
    
    
    
    2.0
    
    
    
    0.752022
    
    
    5.82
    
    
    
    5.90
    
    
    
    5.90
    
    
    
    5.90
    
    
    
    6.15
    
    
    
    5.80
    
    
    
    2.0
    
    
    
    0.752023
    
    
    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 GASNet Proved
    
    Net Probable
    
    Net Proved Plus ProbableFACTORS
    
    (bcf)
    
    (bcf)
    
    (bcf)December 31 2002(1)
    
    
    131.1
    
    
    
    15.6
    
    
    
    146.7Improved Recoveries
    
    
    2.1
    
    
    
    0.5
    
    
    
    2.6Extensions
    
    
    
    
    
    
    
    
    
    
    Discoveries
    
    
    
    
    
    
    
    
    
    
    Technical Revisions
    
    
    (16.1
    )
    
    
    3.7
    
    
    
    (12.4
    )Acquisitions
    
    
    8.6
    
    
    
    1.2
    
    
    
    9.8Dispositions
    
    
    
    
    
    
    
    
    
    
    Economic Factors
    
    
    
    
    
    
    
    
    
    
    Production
    
    
    (25.0
    )
    
    
    
    
    
    
    (25.0
    )December 31, 2003
    
    
    100.7
    
    
    
    21.0
    
    
    
    121.7
 18




---



##### 



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 GASGross Proved
    
    Gross Probable
    
    Gross Proved Plus ProbableFACTORS
    
    (bcf)
    
    (bcf)
    
    (bcf)December 31 2002(1)
    
    
    164.3
    
    
    
    19.7
    
    
    
    183.9Improved Recoveries
    
    
    2.7
    
    
    
    0.6
    
    
    
    3.3Extensions
    
    
    
    
    
    
    
    
    
    
    Discoveries
    
    
    
    
    
    
    
    
    
    
    Technical Revisions
    
    
    (23.2
    )
    
    
    3.7
    
    
    
    (19.5
    )Acquisitions
    
    
    10.7
    
    
    
    1.5
    
    
    
    12.2Dispositions
    
    
    
    
    
    
    
    
    
    
    Economic Factors
    
    
    
    
    
    
    
    
    
    
    Production
    
    
    (31.2
    )
    
    
    
    
    
    
    (31.2
    )December 31, 2003
    
    
    123.3
    
    
    
    25.5
    
    
    
    148.8
 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. 19




---



##### 



RECONCILIATION OF CHANGES IN
NET PRESENT VALUES OF FUTURE NET REVENUE
DISCOUNTED AT 10% PER YEAR
PROVED RESERVES
CONSTANT PRICES AND COSTS 2003PERIOD AND FACTOR
    
    ($000s)Estimated Future Net Revenue at December 31, 2002
    
    
    362,817Sales of Gas Produced, Net of Production Costs and Royalties
    
    
    (135,303
    )Net Change in Prices, Production Costs and Royalties Related to Future Production
    
    
    58,348Changes in Estimated Future Development Costs
    
    
    (1,276
    )Capital Additions
    
    
    6,351Acquisitions of Reserves
    
    
    26,008Dispositions of Reserves
    
    
    Net Change Resulting from Revisions in Quantity Estimates
    
    
    (48,690
    )Accretion of Discount
    
    
    36,282Net Change in Income Taxes(1)
    
    
    Estimated Future Net Revenue at December 31, 2003
    
    
    304,537
 Note:  (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. 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. 20




---



##### 



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 CostsProved Reserves
    
    Proved Plus Probable Reserves
    
    Proved ReservesYear
    
    0%
    
    10%
    
    0%
    
    10%
    
    0%
    
    10%2004
    
    
    4,471
    
    
    
    4,263
    
    
    
    4,471
    
    
    
    4,263
    
    
    
    4,384
    
    
    
    4,1802005
    
    
    7
    
    
    
    6
    
    
    
    162
    
    
    
    140
    
    
    
    7
    
    
    
    62006
    
    
    42
    
    
    
    33
    
    
    
    42
    
    
    
    33
    
    
    
    40
    
    
    
    322007
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    2008
    
    
    
    
    
    
    
    
    
    
    4
    
    
    
    3
    
    
    
    
    
    
    
    Thereafter
    
    
    43
    
    
    
    25
    
    
    
    55
    
    
    
    28
    
    
    
    39
    
    
    
    23Total
    
    
    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. 21




---



##### 



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. 22




---



##### 



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 23




---



##### 



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. 24




---



##### 



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




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##### 



Natural Gas WellsProducing
    
    Non-Producing(3)(4)Name of Area (Alberta)
    
    Gross(1)
    
    Net(2)
    
    Gross(1)
    
    Net(2)Winefred
    
    
    14
    
    
    
    12.00
    
    
    
    75
    
    
    
    66.32Other
    
    
    7
    
    
    
    1.51
    
    
    
    15
    
    
    
    6.63Total
    
    
    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
    
    
    
    533Chard/Chard Southwest
    
    
    28,800
    
    
    
    19,207
    
    
    
    17,920
    
    
    
    12,325Clyde
    
    
    12,800
    
    
    
    11,772
    
    
    
    14,080
    
    
    
    14,080Cold Lake
    
    
    94,563
    
    
    
    71,463
    
    
    
    28,140
    
    
    
    21,909Corner
    
    
    74,240
    
    
    
    73,155
    
    
    
    28,160
    
    
    
    27,200Craigmyle
    
    
    14,086
    
    
    
    3,251
    
    
    
    6,400
    
    
    
    2,022Ells
    
    
    28,800
    
    
    
    28,800
    
    
    
    
    
    
    
    Kettle River
    
    
    35,200
    
    
    
    33,114
    
    
    
    
    
    
    
    Kirkpatrick
    
    
    5,457
    
    
    
    4,574
    
    
    
    5,280
    
    
    
    3,650Legend
    
    
    125,440
    
    
    
    107,899
    
    
    
    21,120
    
    
    
    20,584Legend East
    
    
    27,520
    
    
    
    27,520
    
    
    
    24,960
    
    
    
    24,960Leismer
    
    
    136,960
    
    
    
    130,160
    
    
    
    90,880
    
    
    
    84,518Liege East
    
    
    11,520
    
    
    
    10,279
    
    
    
    640
    
    
    
    556Liege North
    
    
    67,200
    
    
    
    60,773
    
    
    
    
    
    
    
    Liege South
    
    
    86,880
    
    
    
    79,837
    
    
    
    31,360
    
    
    
    12,163Minnehik
    
    
    1,440
    
    
    
    320
    
    
    
    
    
    
    
    Pony
    
    
    9,600
    
    
    
    5,200
    
    
    
    7,040
    
    
    
    3,040Quigley
    
    
    52,160
    
    
    
    52,160
    
    
    
    13,120
    
    
    
    13,120Saleski
    
    
    72,320
    
    
    
    64,068
    
    
    
    22,720
    
    
    
    19,530Teepee Creek
    
    
    72,559
    
    
    
    37,560
    
    
    
    37,760
    
    
    
    29,760Thornbury
    
    
    48,640
    
    
    
    34,892
    
    
    
    3,840
    
    
    
    1,792Winefred
    
    
    72,960
    
    
    
    63,808
    
    
    
    28,800
    
    
    
    21,360Other
    
    
    16,000
    
    
    
    6,648
    
    
    
    17,424
    
    
    
    8,496Total
    
    
    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. 26




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##### 



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)
    
    Term45,000 GJ/d
    
    $6.30
    
    January 2004  March 200435,000 GJ/d
    
    $5.56
    
    April 2004  October 20047,500 GJ/d
    
    $5.00 to 7.10
    
    April 2004  December 200415,000 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
    
    
    32,252Exploration costs
    
    
    8,327Corporate Assets
    
    
    757Total
    
    $
    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
    
    NetLight and Medium Oil
    
    
    
    
    
    
    Natural Gas
    
    
    16
    
    
    
    11.4Service
    
    
    1
    
    
    
    0.5Dry
    
    
    
    
    
    
    Total:
    
    
    17
    
    
    
    11.9Success Rate (%)
    
    
    100
    
    
    
    100Exploratory
    
    
    
    
    
    
    Development
    
    
    17
    
    
    
    11.9Total
    
    
    17
    
    
    
    11.9
 27




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##### 



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
    
    2003Quarter Ended
    
    TotalDec 31
    
    Sept 30
    
    June 30
    
    Mar 31Average Daily Production
Volume(1)Natural Gas (mmcf/d)
    
    
    81.2
    (1)
    
    
    88.5
    
    
    
    88.4
    
    
    
    84.2
    
    
    
    85.6Natural Gas Netbacks ($/mcf)Average Net Product
Price Received
    
    $
    5.49
    
    
    $
    5.76
    
    
    $
    6.37
    
    
    $
    8.19
    
    
    $
    6.44Royalties
    
    
    (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
    
    
    
    
    
    2002Quarter Ended
    
    TotalDec 31
    
    Sept 30
    
    June 30
    
    Mar 31Average Daily Production VolumeNatural Gas (mmcf/d)
    
    
    91.0
    
    
    
    97.8
    
    
    
    97.1
    
    
    
    93.5
    
    
    
    94.8Natural Gas Netbacks ($/mcf)Average Net Product Price Received
    
    $
    4.84
    
    
    $
    3.12
    
    
    $
    3.78
    
    
    $
    2.59
    
    
    $
    3.57Royalties
    
    
    (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
    
    2003Quarter Ended
    
    Total($000)
    
    Dec 31
    
    Sept 30
    
    June 30
    
    Mar 31Category of ExpenditureLand and Acquisition
    
    
    13,833
    
    
    
    
    
    
    
    18,419
    
    
    
    
    
    
    
    32,252Drilling & Exploration
    
    
    224
    
    
    
    (671
    )
    
    
    87
    
    
    
    8,687
    
    
    
    8,327Equipping
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    Facilities & Gathering
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    Corporate Assets
    
    
    757
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    757Total
    
    
    14,814
    
    
    
    (671
    )
    
    
    18,506
    
    
    
    8,687
    
    
    
    41,336
 28




---



##### 



The following table indicates the Trusts average daily production from its
important fields for the year ended December 31, 2003: ProductionName of Area (Alberta)
    
    (mmcf/d)Bohn Lake
    
    
    2.2Chard
    
    
    1.7Clyde
    
    
    2.0Cold Lake
    
    
    6.2Corner
    
    
    11.0Craigmyle
    
    
    0.1Ells
    
    
    5.0Hoole
    
    
    0.1Kettle River
    
    
    3.8Kirkpatrick
    
    
    0.1Legend
    
    
    18.0Legend East
    
    
    3.0Leismer
    
    
    7.9Liege East
    
    
    1.7Liege North
    
    
    2.4Liege South
    
    
    3.8Minnehik
    
    
    0.1Pony
    
    
    0.5Quigley
    
    
    2.9Saleski
    
    
    3.8Surmont
    
    
    0.0Teepee Creek
    
    
    1.4Thornbury
    
    
    4.4Winefred
    
    
    3.4Other
    
    
    0.0Total
    
    
    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. 29




---



##### 



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 UnitMarch 31, 2003
    
    April 15, 2003
    
    $
    0.830April 30, 2003
    
    May 15, 2003
    
    $
    0.277May 31, 2003
    
    June 16, 2003
    
    $
    0.277June 30, 2003
    
    July 15, 2003
    
    $
    0.250July 31, 2003
    
    August 15, 2003
    
    $
    0.250August 29, 2003
    
    September 15, 2003
    
    $
    0.200September 30, 2003
    
    October 15, 2003
    
    $
    0.200October 31, 2003
    
    November 17, 2003
    
    $
    0.200November 28, 2003
    
    December 15, 2003
    
    $
    0.200December 31, 2003
    
    January 15, 2004
    
    $
    0.200January 30, 2004
    
    February 16, 2004
    
    $
    0.200February 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
    
    Volume2004January
    
    
    11.79
    
    
    
    9.75
    
    
    
    8,024,454February
    
    
    11.85
    
    
    
    10.21
    
    
    
    3,712,657March 1-21
    
    
    11.88
    
    
    
    11.60
    
    
    
    2,104,2002003February 7
to 28(1)
    
    
    32.51
    (2)
    
    
    11.75
    
    
    
    2,408,997March
    
    
    15.45
    
    
    
    12.70
    
    
    
    4,291,899April
    
    
    13.40
    
    
    
    12.60
    
    
    
    3,074,616May
    
    
    14.46
    
    
    
    12.69
    
    
    
    4,682,153June
    
    
    13.99
    
    
    
    8.46
    
    
    
    8,703,963July
    
    
    10.45
    
    
    
    8.25
    
    
    
    6,813,923August
    
    
    10.31
    
    
    
    9.81
    
    
    
    3,673,243September
    
    
    10.90
    
    
    
    9.45
    
    
    
    3,183,273October
    
    
    11.45
    
    
    
    10.25
    
    
    
    2,222,921November
    
    
    11.45
    
    
    
    10.93
    
    
    
    2,179,434December
    
    
    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. 30




---



##### 



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. 31




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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. 32




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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. 33




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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 34




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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; 35




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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. 36




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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: 37




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
    
    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. 38




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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; 39




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
    
    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 40




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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 41




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
    
    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; 42




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
    
    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 43




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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. 44




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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 theof Residence
    
    Administrator
    
    Director Since
    
    Principal OccupationClayton 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 PRLSusan L. Riddell Rose(3)Calgary, Alberta
    
    President, Chief
Operating Officer
and Director
    
    June 28, 2002
    
    President and Chief
Operating Officer
of the
AdministratorCameron R. Sebastian
Calgary, Alberta
    
    Vice-President,
Finance and Chief
Financial Officer
    
    
    
    Vice-President,
Finance and Chief
Financial Officer
of the
Administrator since
June 28, 2002Gary C. Jackson
Calgary, Alberta
    
    Vice-President,
Land, Legal and
Acquisitions
    
    
    
    Vice-President,
Land, Legal and
Acquisitions of the
Administrator since
June 28, 2002Myra Jones
Calgary, Alberta
    
    Corporate Secretary
    
    
    
    Corporate Secretary
of the
Administrator since
June 28, 2002Kevin J. Marjoram
Calgary, Alberta
    
    Vice-President,
Operations
    
    
    
    Vice-President,
Operations of the
Administrator since
July 1, 2002
 45




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Name and Municipality
    
    Offices held with theof Residence
    
    Administrator
    
    Director Since
    
    Principal OccupationBrett Norris
Calgary, Alberta
    
    Vice President, New
Ventures &
Geosciences
    
    
    
    Vice President, New
Ventures &
Geosciences since
November 17, 2003Donald 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 companyKaren A. Genoway
(2)(4)(7)Calgary, Alberta
    
    Director
    
    June 28, 2002
    
    Vice-President,
Land, Onyx Energy
Inc., a private oil
and gas companyHoward 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. 46




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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 47




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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. 48




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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 49




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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; and3.
    
    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. 50




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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 51




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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. 52




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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. 53




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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. 54




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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. 55




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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 56




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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: 57




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
    
    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 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. 58




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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 59




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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; 60




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(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  2.
    
    at any other time, one copy of any documents referred to in items (1)(a),
(b) and (c) above, provided that the Trust may require the payment of a
reasonable charge if the request is made by a person who is not a security
holder of the Trust. For additional copies of this Initial Annual Information Form and the materials
listed in the preceding paragraphs, please contact: Mr. Cameron R. Sebastian
Chief Financial Officer
Paramount Energy Operating Corp.
500, 630  4th Avenue S.W.
Calgary, Alberta T2P 0J9
Telephone: (403) 269-4400
Fax: (403) 269-4444 61