##### Table of Contents



SECURITIES AND EXCHANGE COMMISSION

Washington D.C. 20549


FORM 20-F

ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2002

Commission file number: 333-98233

PARAMOUNT ENERGY TRUST

(Exact name of Registrant as specified in its charter)


Alberta, Canada
(Jurisdiction of incorporation or organization)

500, 630 - 4th Avenue S.W., Calgary, Alberta, T2P 0J9 Canada
(Address of principal executive offices)

Securities registered or to be registered pursuant to Section 12(b) of the Act:

|                    |  |                                          
|------------------- |  | -----------------------------------------
|Title of Each Class |  | Name of Each Exchange on Which Registered
|                    |  |                                          
|None                |  | N/A                                      

Securities registered or to be registered pursuant to Section 12(g) of the Act:

None
(Title of Class)



|Securities for which there is a reporting obligation pursuant to Section 15(d)
of the Act:
|------------------------------------------------------------------------------------------
|Trust Units
(Title of Class)                                                              



|Indicate the number of outstanding shares of each of the issuers classes of
capital or common stock as of the close of the period covered by the annual
report:
|----------------------------------------------------------------------------------------------------------------------------------------------------------------
|Trust Units as of December 31, 2002                     1                                                                                                       



|Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to such
filing requirements for the past 90 days.
|--------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|Yes [X] No [  ]                                                                                                                                                                                                                                                                                                                                         

|Indicate by check mark which financial statement item the registrant has
elected to follow:
|-------------------------------------------------------------------------------------------
|                                                                                           
|Item 17 [  ] Item 18 [X]                                                                   





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TABLE OF CONTENTS



|                                                          |                                                                                       |                                                            |  |  |  |  |  | 
|--------------------------------------------------------- | ------------------------------------------------------------------------------------- | ---------------------------------------------------------- |  |  |  |  |  | 
|INTRODUCTORY NOTE                                        
|CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS
|CERTAIN OIL AND GAS TERMS                                
|ENFORCEABILITY OF CIVIL LIABILITIES                      
|PART I                                                   
|                                                          | ITEM 1. IDENTITY OF DIRECTORS, SENIOR MANAGEMENT AND ADVISERS                        
|                                                          | ITEM 2. OFFER STATISTICS AND EXPECTED TIMETABLE                                      
|                                                          | ITEM 3. KEY INFORMATION                                                              
|                                                          |                                                                                       | A. Selected Financial Data                                
|                                                          |                                                                                       | B. Capitalization and Indebtedness                        
|                                                          |                                                                                       | C. Reasons for the Offer and Use of Proceeds              
|                                                          |                                                                                       | D. Risk Factors                                           
|                                                          | ITEM 4. INFORMATION ON THE COMPANY                                                   
|                                                          |                                                                                       | A. History and Development of the Company                 
|                                                          |                                                                                       | B. Business Overview                                      
|                                                          |                                                                                       | C. Organizational Structure                               
|                                                          |                                                                                       | D. Property, Plants and Equipment                         
|                                                          | ITEM 5. OPERATING AND FINANCIAL REVIEW AND PROSPECTS                                 
|                                                          |                                                                                       | A. Operating Results                                      
|                                                          |                                                                                       | B. Liquidity and Capital Resources                        
|                                                          |                                                                                       | C. Research and Development                               
|                                                          |                                                                                       | D. Trend Information                                      
|                                                          |                                                                                       | E. Off-Balance Sheet Arrangements                         
|                                                          |                                                                                       | F. Tabular Disclosure of Contractual Obligations          
|                                                          | ITEM 6. DIRECTORS, SENIOR MANAGEMENT AND EMPLOYEES                                   
|                                                          |                                                                                       | A. Directors and Senior Management                        
|                                                          |                                                                                       | B. Compensation                                           
|                                                          |                                                                                       | C. Board Practices                                        
|                                                          |                                                                                       | D. Employees                                              
|                                                          |                                                                                       | E. Share Ownership                                        
|                                                          | ITEM 7. MAJOR SHAREHOLDERS AND RELATED PARTY TRANSACTIONS                            
|                                                          |                                                                                       | A. Major Shareholders                                     
|                                                          |                                                                                       | B. Related Party Transactions                             
|                                                          |                                                                                       | C. Interests of Experts and Counsel                       
|                                                          | ITEM 8. FINANCIAL INFORMATION                                                        
|                                                          |                                                                                       | A. Consolidated Statements and Other Financial Information
|                                                          |                                                                                       | B. Significant Changes                                    
|                                                          | ITEM 9. THE OFFER AND LISTING                                                        
|                                                          |                                                                                       | A. Offer and Listing Details                              
|                                                          |                                                                                       | B. Plan of Distribution                                   
|                                                          |                                                                                       | C. Markets                                                
|                                                          |                                                                                       | D. Selling Shareholders                                   
|                                                          |                                                                                       | E. Dilution                                               
|                                                          |                                                                                       | F. Expense of the Issue                                   
|                                                          | ITEM 10. ADDITIONAL INFORMATION                                                      
|                                                          |                                                                                       | A. Share Capital  Treasury shares                        
|                                                          |                                                                                       | B. Memorandum and Articles of Association                 
|                                                          |                                                                                       | C. Material Contracts                                     
|                                                          |                                                                                       | D. Exchange Controls                                      
|                                                          |                                                                                       | E. Taxation                                               
|                                                          |                                                                                       | F. Dividend and Paying Agents                             
|                                                          |                                                                                       | G. Statement by Experts                                   
|                                                          |                                                                                       | H. Documents on Display                                   
|                                                          |                                                                                       | I. Subsidiary Information                                 
|                                                          | ITEM 11. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISKS                 
|                                                          | ITEM 12. DESCRIPTION OF SECURITIES OTHER THAN EQUITY SECURITIES                      
|PART II                                                  
|                                                          | ITEM 13. DEFAULTS, DIVIDEND ARREARAGES AND DELINQUENCIES                             
|                                                          | ITEM 14. MATERIAL MODIFICATIONS TO THE RIGHTS OF SECURITY HOLDERS AND USE OF PROCEEDS
|                                                          | ITEM 15. CONTROLS AND PROCEDURES                                                     
|                                                          | ITEM 16. [RESERVED]                                                                  
|PART III                                                 
|                                                          | ITEM 17. FINANCIAL STATEMENTS                                                        
|                                                          | ITEM 18. FINANCIAL STATEMENTS                                                        
|                                                          | ITEM 19. EXHIBITS                                                                    
|Asset Sale Agreement                                     
|List of Subsidiaries                                     
|Certifications                                           
|Financials                                               
|Financials                                               
|Financials                                               



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##### Table of Contents



TABLE OF CONTENTS

|                                                          |  |                                                            |  |     
|--------------------------------------------------------- |  | ---------------------------------------------------------- |  | ----
|                                                          |  |                                                            |  | Page
|                                                          |  |                                                            |  |     
|INTRODUCTORY NOTE                                         |  | iv                                                        
|CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS |  | iv                                                        
|CERTAIN OIL AND GAS TERMS                                 |  | v                                                         
|ENFORCEABILITY OF CIVIL LIABILITIES                       |  | v                                                         
|PART I                                                    |  |                                                            |  | 1   
|ITEM 1.                                                   |  | IDENTITY OF DIRECTORS, SENIOR MANAGEMENT AND ADVISERS      |  | 1   
|ITEM 2.                                                   |  | OFFER STATISTICS AND EXPECTED TIMETABLE                    |  | 1   
|ITEM 3.                                                   |  | KEY INFORMATION                                            |  | 1   
|                                                          |  | A. Selected Financial Data                                 |  | 1   
|                                                          |  | B. Capitalization and Indebtedness                         |  | 3   
|                                                          |  | C. Reasons for the Offer and Use of Proceeds               |  | 3   
|                                                          |  | D. Risk Factors                                            |  | 4   
|ITEM 4.                                                   |  | INFORMATION ON THE COMPANY                                 |  | 14  
|                                                          |  | A. History and Development of the Company                  |  | 14  
|                                                          |  | B. Business Overview                                       |  | 16  
|                                                          |  | C. Organizational Structure                                |  | 18  
|                                                          |  | D. Property, Plants and Equipment                          |  | 20  
|ITEM 5.                                                   |  | OPERATING AND FINANCIAL REVIEW AND PROSPECTS               |  | 30  
|                                                          |  | A. Operating Results                                       |  | 31  
|                                                          |  | B. Liquidity and Capital Resources                         |  | 42  
|                                                          |  | C. Research and Development                                |  | 43  
|                                                          |  | D. Trend Information                                       |  | 43  
|                                                          |  | E. Off-Balance Sheet Arrangements                          |  | 45  
|                                                          |  | F. Tabular Disclosure Of Contractual Obligations           |  | 45  
|ITEM 6.                                                   |  | DIRECTORS, SENIOR MANAGEMENT AND EMPLOYEES                 |  | 45  
|                                                          |  | A. Directors and Senior Management                         |  | 45  
|                                                          |  | B. Compensation                                            |  | 50  
|                                                          |  | C. Board Practices                                         |  | 51  
|                                                          |  | D. Employees                                               |  | 52  
|                                                          |  | E. Share Ownership                                         |  | 52  
|ITEM 7.                                                   |  | MAJOR SHAREHOLDERS AND RELATED PARTY TRANSACTIONS          |  | 55  
|                                                          |  | A. Major Shareholders                                      |  | 55  
|                                                          |  | B. Related Party Transactions                              |  | 55  
|                                                          |  | C. Interests of Experts and Counsel                        |  | 56  
|ITEM 8.                                                   |  | FINANCIAL INFORMATION                                      |  | 56  
|                                                          |  | A. Consolidated Statements and Other Financial Information |  | 56  
|                                                          |  | B. Significant Changes                                     |  | 56  
|ITEM 9.                                                   |  | THE OFFER AND LISTING                                      |  | 58  

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|         |  |                                                                              |  |     
|-------- |  | ---------------------------------------------------------------------------- |  | ----
|         |  |                                                                              |  | Page
|         |  |                                                                              |  |     
|         |  | A. Offer and Listing Details                                                 |  | 58  
|         |  | B. Plan of Distribution                                                      |  | 59  
|         |  | C. Markets                                                                   |  | 59  
|         |  | D. Selling Shareholders                                                      |  | 59  
|         |  | E. Dilution                                                                  |  | 59  
|         |  | F. Expense of the Issue                                                      |  | 59  
|ITEM 10. |  | ADDITIONAL INFORMATION                                                       |  | 59  
|         |  | A. Share Capital - Treasury shares                                           |  | 59  
|         |  | B. Memorandum and Articles of Association                                    |  | 60  
|         |  | C. Material Contracts                                                        |  | 60  
|         |  | D. Exchange Controls                                                         |  | 62  
|         |  | E. Taxation                                                                  |  | 62  
|         |  | F. Dividend and Paying Agents                                                |  | 69  
|         |  | G. Statement by Experts                                                      |  | 69  
|         |  | H. Documents on Display                                                      |  | 69  
|         |  | I. Subsidiary Information                                                    |  | 69  
|ITEM 11. |  | QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISKS                  |  | 70  
|ITEM 12. |  | DESCRIPTION OF SECURITIES OTHER THAN EQUITY SECURITIES                       |  | 71  
|PART II  |  |                                                                              |  | 71  
|ITEM 13. |  | DEFAULTS, DIVIDEND ARREARAGES AND DELINQUENCIES                              |  | 71  
|ITEM 14. |  | MATERIAL MODIFICATIONS TO THE RIGHTS OF SECURITY HOLDERS
AND USE OF PROCEEDS |  | 71  
|ITEM 15. |  | CONTROLS AND PROCEDURES                                                      |  | 72  
|ITEM 16  |  | [RESERVED]                                                                   |  | 73  
|PART III |  |                                                                              |  | 73  
|ITEM 17  |  | FINANCIAL STATEMENTS                                                         |  | 73  
|ITEM 18  |  | FINANCIAL STATEMENTS                                                         |  | 73  
|ITEM 19  |  | EXHIBITS                                                                     |  | 73  

iii



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INTRODUCTORY NOTE

The registrant, Paramount Energy Trust (PET or the Trust) is an
Alberta unincorporated trust formed at the instigation of Paramount Resources
Ltd. (PRL ) to own and develop certain oil and natural gas properties. PET,
whose trust units are listed on the Toronto Stock Exchange (TSX), finances
the operations of Paramount Operating Trust (POT), also an Alberta
unincorporated trust of which PET is the sole beneficiary and which is an
operating oil and natural gas entity. Paramount Energy Operating Corp. (the
Administrator), an Alberta corporation which is a wholly-owned subsidiary of
PET, provides certain operational, executive and financial services and
governance functions for PET and is the trustee of POT. Units in PET are
referred to throughout this report as Trust Units, and holders of Trust Units
are referred to as Unitholders.

Unless the context otherwise requires, all references in this report to
PET, as well as the terms we, us, and our, refer to PET and its
wholly-owned subsidiaries POT and the Administrator, collectively.

As used in this report, the term PRL Northeast Alberta Assets means the
assets associated with the operations of PRL in its Northeast Alberta core
area, and the term PET Assets means the natural gas assets included in the
PRL Northeast Alberta Assets that were acquired by PET from PRL during February
and March, 2003 (but does not include the Ells natural gas property which PET
acquired from PRL effective March 19, 2003). See Item 4.D of this report.

The term McDaniel Report is used throughout this report to refer to he
independent engineering evaluation dated March 10, 2003 of the natural gas
reserves and the present worth value of these reserves for the natural gas
interests of PET prepared by McDaniel & Associates Consultants Ltd., based on
pricing as at January 1, 2003. McDaniel & Associates Consultants Ltd. is an
independent oil and gas reservoir engineering firm based in Calgary, Alberta.




CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS

This report includes forward-looking statements which generally relate
to future events or our future performance. In some cases, forward-looking
statements can be identified by terminology such as may, will, should,
expect, plan, anticipate, believe, estimate, predict, potential
or the negative of these terms or other comparable terminology. All statements
(other than statements of historical fact) included in this annual report that
address activities, events or developments that we expect or anticipate will or
may occur in the future, including such matters as changes in commodity prices,
future capital expenditures, the proposed acquisitions by us of certain assets
from PRL as detailed in this annual report, business strategies and measures to
implement our operations, our plans and references to our future success and
other such matters are forward-looking statements. These statements are only
predictions. Actual events or results may differ materially. These statements
are based upon certain assumptions and analyses we made based on our
managements experience and perception of historical trends, current conditions
and expected future developments, as

iv



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well as other factors we
believe are appropriate in the circumstances. Whether or not actual
results and developments will conform with our expectations and predictions,
however, is subject to a number of risks and uncertainties, including the
special considerations discussed in this annual report, general economic,
market or business conditions and the presence or lack of business
opportunities. See Risk Factors. Consequently, all the forward-looking
statements made in this annual report are qualified by these cautionary
statements, and there can be no assurance that the actual results or
developments we anticipate will be realized or, even if substantially realized,
that they will result in the expected consequences to, or have the expected
effects on, our businesses or operations. We are under no duty to update any of
the forward-looking statements after the date of this report to conform such
statements to actual results or to a change in our expectations.




CERTAIN OIL AND GAS TERMS

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

|        |  |                          |  |          |  |                                
|------- |  | ------------------------ |  | -------- |  | -------------------------------
|bcf   |  | 1,000,000,000 cubic feet |  | Mmbtu  |  | 1,000,000 British Thermal Units
|mcf   |  | 1,000 cubic feet         |  | mmcf   |  | 1,000,000 cubic feet           
|mcf/d |  | 1,000 cubic feet per day |  | mmcf/d |  | 1,000,000 cubic feet per day   
|GJ    |  | Gigajoule                |  |          |  |                                

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




ENFORCEABILITY OF CIVIL LIABILITIES

Investors ability to enforce civil liabilities under United States
securities laws may be affected adversely by the fact that we are organized
under and governed by the laws of Canada, that all of our directors and
officers reside outside the United States, that the experts named in this
prospectus are residents of Canada, and that all or substantially all of our
assets are, and the assets of such persons may be, located outside the United
States. As a result, investors may not be able to:



| |  |  | effect service of process upon us or such persons within the United States; or                                                                                                                                     
| | - |  | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|
| |  |  | enforce against us or such persons, in United States courts or in Canadian
courts, judgments obtained in United States courts based solely upon the
civil liability provisions of United States securities laws; or
|
| |  |  | bring an original action in Canada against us or such persons, to enforce
liabilities based solely upon the United States securities laws.                                                                         

v



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PART I




ITEM 1. IDENTITY OF DIRECTORS, SENIOR MANAGEMENT AND ADVISERS

Not applicable.




ITEM 2. OFFER STATISTICS AND EXPECTED TIMETABLE

Not applicable.




ITEM 3. KEY INFORMATION




A.     SELECTED FINANCIAL DATA (4)

The following is a summary of certain selected historical financial data
and financial and production information and is qualified in its entirety by
the detailed provisions contained in the Financial Statements for PRLs
Northeast Alberta Properties, for the years ended December 31, 2002, 2001 and
2000 (included in Exhibit 12.5 to this report) and the unaudited consolidated
financial statements of Paramount Energy Trust for the three month interim
periods ended March 31, 2003 and 2002 (included as Exhibit 12.3 to this
report). Selected information for the periods ended December 31, 1999 and 1998
is also set forth below.

(Cdn$000)

|                                       |           |           |                    |      |            |   |        |       |      |   |         |   |      |   |         |   |  |   |         |             |  |   |         |   |  |   |         |  | 
|-------------------------------------- | --------- | --------- | ------------------ | ---- | ---------- | - | ------ | ----- | ---- | - | ------- | - | ---- | - | ------- | - |  | - | ------- | ----------- |  | - | ------- | - |  | - | ------- |  | 
|                                       |           |           | Three Months Ended |      |           
|                                       |           |           | March 31           |      | Year Ended
|                                       |           |           |                    |      |           
|                                       |           |           | 2003               |      | 2002       |   | 2002   |       | 2001 |   | 2000    |   | 1999 |   | 1998   
|                                       |           |           |                    |      |            |   |        |       |      |   |         |   |      |   |        
|                                       |           | Unaudited |                    |      |            |   |        |       |      |   |         |   |      |   |         |   |  |   |         | (Unaudited)
|                                       |           |           |                    |      |            |   |        |       |      |   |         |   |      |   |         |   |  |   |         |            
|Canadian GAAP                         
|Revenue (Before
royalties and
hedging) |           | $         | 62,104             |      |            | $ | 21,778 |       |      | $ | 126,095 |   |      | $ | 235,641 |   |  | $ | 195,927 |             |  | $ | 131,805 |   |  | $ | 109,944 | 
|Net earnings (Loss)                    |           |           | 26,416             |      |            |   | (7,378 | )     |      |   | 39,761  |   |      |   | 67,914  |   |  |   | 51,825  |             |  |   | 27,319  |   |  |   | (1)     | 
|Net earnings (Loss)
per Trust Unit     |           |           |                    |      |            |   |        |       |      |   |         |   |      |   |         |   |  |   |         |             |  |   |         |   |  |   |         | 
|                                       |  Basic   |           | $                  | 0.67 |            |   | $      | (0.11 | )    |   |         |  |      |   |         |  |  |   |         |            |  |   |         |  |  |   |         |  | 
|                                       |  Diluted |           |                    | 0.65 |            |   |        | (0.11 | )    |   |         |  |      |   |         |  |  |   |         |            |  |   |         |  |  |   |         |  | 
|Total assets                           |           | $         | 301,417            |      |            |   |        |       |      | $ | 279,075 |   |      | $ | 328,722 |   |  | $ | 330,502 |             |  | $ | 289,962 |   |  |   | (1)     | 
|Net assets                             |           |           | 176,459            |      |            |   |        |       |      |   | 113,952 |   |      |   | 200,982 |   |  |   | 223,954 |             |  |   | 243,366 |   |  |   | (1)     | 
|US GAAP (2)(3)                         |           |           |                    |      |            |   |        |       |      |   |         |   |      |   |         |   |  |   |         |             |  |   |         |   |  |   |         | 
|Total assets                           |           |           |                    |      |            |   |        |       |      |   | 269,012 |   |      |   | 333,039 |   |  |   | 330,502 |             |  |   | 289,962 |   |  |   | (1)     | 
|Net assets (net
investment of PRL)     |           |           |                    |      |            |   |        |       |      |   | 107,312 |   |      |   | 203,939 |   |  |   | 223,954 |             |  |   | 243,366 |   |  |   | (1)     | 

Notes:



| | (1) |  | Certain of the selected financial data have not been provided
for 1998, as financial statements have not been prepared for the PRL
Northeast Alberta Properties on a stand alone basis for that period.
See below for selected financial data on the PET Assets.                                     
| | --- |  | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|
| | (2) |  | The differences between Canadian GAAP and US GAAP are
described in the notes to the financial statements of the PRL
Northeast Alberta Properties. A reconciliation between United
States and Canadian GAAP has not been prepared for the unaudited
three month periods ended March 31, 2003 and 2002.
|
| | (3) |  | Other than disclosed here, the Canadian GAAP and US GAAP
amounts are the same for the items included in the selected
financial data.                                                                                                                                                                 

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| | (4) |  | Amounts shown are with respect to the PET Assets pursuant to
continuity of interests accounting for the three months ended March
31, 2003 and 2002 and for the PRL Northeast Alberta properties for
the other periods
presented. The operations of PRL in its northeast Alberta core
area are presented in the financial statements for PRLs Northeast
Alberta Properties presented elsewhere in this report. The
Northeast Alberta Properties include the PET Assets and the
Excluded Assets. The Excluded Assets consist of certain
exploration properties, gas properties in the Cold Lake Elizabeth
area and gas properties shut-in due to the Surmont co-production
issue. The Excluded Assets generated $2.4 million of revenue for
the year ended December 31, 2002.
| | --- |  | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

Selected Financial And Production Information (3)

|                    |  |                             |         |      |  |   |         |  
|------------------- |  | --------------------------- | ------- | ---- |  | - | ------- | -
|                    |  | Three Months Ended March 31
|(Cdn$000 except as  |  |                            
|indicated)          |  | 2003                        |         | 2002
|                    |  |                             |         |     
|Production (mmcf/d) |  |                             | 84.2    |      |  |   | 93.5    |  
|Price ($/mcf)       |  | $                           | 8.19    |      |  | $ | 2.59    |  
|Revenue             |  | $                           | 62,104  |      |  | $ | 21,778  |  
|Royalties           |  |                             | (14,195 | )    |  |   | (3,647  | )
|Operating Costs     |  |                             | (8,559  | )    |  |   | (10,594 | )
|                    |  |                             |         |      |  |   |         |  
|Operating Income(2) |  | $                           | 39,350  |      |  | $ | 7,537   |  
|                    |  |                             |         |      |  |   |         |  

|                    |  |                          |         |          |  |          |       |        |  |          |         |          |  |   |         |   |  |   |        |   |  |   |         |  
|------------------- |  | ------------------------ | ------- | -------- |  | -------- | ----- | ------ |  | -------- | ------- | -------- |  | - | ------- | - |  | - | ------ | - |  | - | ------- | -
|                    |  | Years Ended December 31,
|                    |  |                         
|                    |  | 2002                     |         | 2001    
|                    |  |                          |         |         
|(Cdn$000 except as  |  | PET                      |         | Excluded |  | PRL N.E. |       | PET    |  | Excluded |         | PRL N.E.
|indicated)          |  | Assets                   |         | Assets   |  | Assets   |       | Assets |  | Assets   |         | Assets  
|                    |  |                          |         |          |  |          |       |        |  |          |         |         
|Production (mmcf/d) |  |                          | 94.8    |          |  |          | 1.7   |        |  |          | 96.5    |          |  |   | 102.7   |   |  |   | 2.9    |   |  |   | 105.6   |  
|Price ($/mcf)       |  | $                        | 3.57    |          |  | $        | 3.75  |        |  | $        | 3.58    |          |  | $ | 6.09    |   |  | $ | 6.95   |   |  | $ | 6.11    |  
|Revenue             |  | $                        | 123,739 |          |  | $        | 2,356 |        |  | $        | 126,095 |          |  | $ | 228,283 |   |  | $ | 7,358  |   |  | $ | 235,641 |  
|Royalties           |  |                          | (21,886 | )        |  |          | (602  | )      |  |          | (22,488 | )        |  |   | (45,761 | ) |  |   | (1,558 | ) |  |   | (47,319 | )
|Operating Costs     |  |                          | (30,265 | )        |  |          | (422  | )      |  |          | (30,687 | )        |  |   | (32,870 | ) |  |   | (1,085 | ) |  |   | (33,955 | )
|                    |  |                          |         |          |  |          |       |        |  |          |         |          |  |   |         |   |  |   |        |   |  |   |         |  
|Operating Income(2) |  | $                        | 71,588  |          |  | $        | 1,332 |        |  | $        | 72,920  |          |  | $ | 149,652 |   |  | $ | 4,715  |   |  | $ | 154,367 |  
|                    |  |                          |         |          |  |          |       |        |  |          |         |          |  |   |         |   |  |   |        |   |  |   |         |  

|                    |  |                         |         |          |  |                  |        |        |  |          |         |          |  |        |         |          |  |   |        |   |  |   |         |   |  |   |         |   |  |  |    |  
|------------------- |  | ----------------------- | ------- | -------- |  | ---------------- | ------ | ------ |  | -------- | ------- | -------- |  | ------ | ------- | -------- |  | - | ------ | - |  | - | ------- | - |  | - | ------- | - |  |  | -- | -
|                    |  | Years Ended December 31
|                    |  |                        
|                    |  | 2000                    |         | 1999     |  | 1998 (unaudited)
|                    |  |                         |         |          |  |                 
|(Cdn $000 except as |  | PET.                    |         | Excluded |  | PRL N.E.         |        | PET    |  | Excluded |         | PRL N.E. |  | PET    |         | PRL N.E.
|indicated)          |  | Assets                  |         | Assets   |  | Assets           |        | Assets |  | Assets   |         | Assets   |  | Assets |         | Assets  
|                    |  |                         |         |          |  |                  |        |        |  |          |         |          |  |        |         |         
|Production (mmcf/d) |  |                         | 107.4   |          |  |                  | 12.1   |        |  |          | 119.5   |          |  |        | 112.9   |          |  |   | 25.7   |   |  |   | 138.7   |   |  |   | 135.5   |   |  |  | (1 | )
|Price ($/mcf)       |  | $                       | 4.65    |          |  | $                | 3.00   |        |  | $        | 4.49    |          |  | $      | 2.61    |          |  | $ | 2.58   |   |  | $ | 2.60    |   |  | $ | 1.90    |   |  |  | (1 | )
|Revenue             |  | $                       | 182,727 |          |  | $                | 13,200 |        |  | $        | 195,927 |          |  | $      | 107,575 |          |  | $ | 24,230 |   |  | $ | 131,805 |   |  | $ | 93,974  |   |  |  | (1 | )
|Royalties           |  |                         | (35,191 | )        |  |                  | (3,602 | )      |  |          | (38,793 | )        |  |        | (22,773 | )        |  |   | (5,728 | ) |  |   | (28,501 | ) |  |   | (13,781 | ) |  |  | (1 | )
|Operating Costs     |  |                         | (24,146 | )        |  |                  | (1,195 | )      |  |          | (25,341 | )        |  |        | (18,111 | )        |  |   | (2,829 | ) |  |   | (20,940 | ) |  |   | (19,945 | ) |  |  | (1 | )
|                    |  |                         |         |          |  |                  |        |        |  |          |         |          |  |        |         |          |  |   |        |   |  |   |         |   |  |   |         |   |  |  |    |  
|Operating Income(2) |  | $                       | 123,390 |          |  | $                | 8,403  |        |  | $        | 131,793 |          |  | $      | 66,691  |          |  | $ | 15,673 |   |  | $ | 82,364  |   |  | $ | 60,248  |   |  |  | (1 | )
|                    |  |                         |         |          |  |                  |        |        |  |          |         |          |  |        |         |          |  |   |        |   |  |   |         |   |  |   |         |   |  |  |    |  

Notes:



| | (1) |  | Selected information has not been provided for the PRL
Northeast Alberta Properties for 1998 as stand-alone financial
statements were not prepared for that year.                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                               
| | --- |  | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|
| | (2) |  | For the purposes of the tables immediately above, operating
income excludes gains or losses related to hedging which are
considered corporate rather than operating activities.                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                 
|
| | (3) |  | Amounts shown are with respect to the PET Assets pursuant to
continuity of interests accounting for the three months ended March
31, 2003 and 2002 and for the PRL Northeast Alberta properties for
the other periods presented. The operations of PRL in its northeast
Alberta core area are presented in the financial statements for
PRLs Northeast Alberta Properties presented elsewhere in this
prospectus. The Northeast Alberta Properties include the PET Assets
and the Excluded Assets. The Excluded Assets consist of certain
exploration properties, gas properties in the Cold Lake Elizabeth
area and gas properties shut-in due to the Surmont co-production
issue. The Excluded Assets generated $2.4 million of revenue for
the year ended December 31, 2002.

The information set out above should be read in conjunction with the
Financial Statements for PRLs Northeast Alberta Properties for the years ended

2



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December 31, 2002, 2001 and 2000 (Exhibit 12.5 to this report) and the
unaudited consolidated financial statements of Paramount Energy Trust for the
three month interim periods ended March 31, 2003 and 2002 (Exhibit 12.3 to this
report).

Exchange Rate Table

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

|                           |  |           |        |                         |  |      |        |      |  |      |        |      |  |   |        |  |  |   |        |  |  |   |        | 
|-------------------------- |  | --------- | ------ | ----------------------- |  | ---- | ------ | ---- |  | ---- | ------ | ---- |  | - | ------ |  |  | - | ------ |  |  | - | ------ | 
|                           |  | 3 months  |        |                         |  |      |        |      |  |      |        |      |  |   |        |  |  |   |        |  |  |  
|                           |  | ended     |        | Year ended December 31,
|                           |  | March 31, |        |                        
|                           |  | 2003      |        | 2002                    |  | 2001 |        | 2000 |  | 1999 |        | 1998
|Rate at end of
period      |  | $         | 0.6805 |                         |  | $    | 0.6329 |      |  | $    | 0.6279 |      |  | $ | 0.6669 |  |  | $ | 0.6925 |  |  | $ | 0.6504 | 
|Average rate during
period |  |           | 0.6689 |                         |  |      | 0.6368 |      |  |      | 0.6444 |      |  |   | 0.6725 |  |  |   | 0.6745 |  |  |   | 0.6714 | 
|High                       |  |           | 0.6822 |                         |  |      | 0.6612 |      |  |      | 0.6697 |      |  |   | 0.6969 |  |  |   | 0.6925 |  |  |   | 0.7105 | 
|Low                        |  |           | 0.6349 |                         |  |      | 0.6209 |      |  |      | 0.6241 |      |  |   | 0.6410 |  |  |   | 0.6535 |  |  |   | 0.6341 | 

|     |  |                     |           |  |  |   |            |  |  |   |            |  |  |   |            |  |  |   |            |  |  |   |            | 
|---- |  | ------------------- | --------- |  |  | - | ---------- |  |  | - | ---------- |  |  | - | ---------- |  |  | - | ---------- |  |  | - | ---------- | 
|     |  | Previous Six Months |           |  |  |   |            |  |  |   |            |  |  |  
|     |  |                     | May, 2003 |  |  |   | Apr., 2003 |  |  |   | Mar., 2003 |  |  |   | Feb., 2003 |  |  |   | Jan., 2003 |  |  |   | Dec., 2002 | 
|High |  | $                   | 0.7437    |  |  | $ | 0.6975     |  |  | $ | 0.6822     |  |  | $ | 0.6720     |  |  | $ | 0.6570     |  |  | $ | 0.6462     | 
|Low  |  |                     | 0.7032    |  |  |   | 0.6737     |  |  |   | 0.6709     |  |  |   | 0.6530     |  |  |   | 0.6349     |  |  |   | 0.6330     | 

On June 25, 2003 the noon buying rate for $1.00 Canadian was $0.7447 United
States.






|B. |  | CAPITALIZATION AND INDEBTEDNESS
|-- |  | -------------------------------
|  
|   |  | Not applicable.                






|C. |  | REASONS FOR THE OFFER AND USE OF PROCEEDS
|-- |  | -----------------------------------------
|  
|   |  | Not applicable.                          

3



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|D. |  | Risk Factors
|-- |  | ------------

Investors should carefully consider the risks described below before making an
investment decision. Investors should also refer to the other information
included in this report, 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 Alberta Energy and Utilities Board (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 this 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 Unitholders. See Item 5.A, Government Regulation 
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, described under the caption Government Regulation in
Item 5.A of this report, may have a material adverse effect on our production
and cash flow, and on the amount of income available for distribution to our
Unitholders.

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 Unitholders 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.

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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 Unitholders will be reduced.

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

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



| |  |  | whether the prevailing tax rules and other government regulations,
contracts and oil, natural gas and other prices, will remain the same
as on the date estimates are made;
| | - |  | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|
| |  |  | the production performance of our reservoirs;                                                                                                                              
|
| |  |  | extensive engineering judgments;                                                                                                                                           
|
| |  |  | the price at which recovered oil and natural gas can be sold;                                                                                                              
|
| |  |  | the costs associated with recovering oil and natural gas;                                                                                                                  
|
| |  |  | the prevailing environmental conditions associated with drilling
and production sites;                                                                                     
|
| |  |  | the availability of enhanced recovery techniques; and                                                                                                                      
|
| |  |  | the ability to transport oil and natural gas to markets.                                                                                                                   

A change in any one or more of these factors could result in known
quantities of oil and natural gas previously estimated as proved reserves
becoming unrecoverable. For example, a decline in the market price of oil or
natural gas to an amount that is less than the cost of recovery of such oil and
natural gas in a particular location could make production thereof commercially
impracticable. Each of these factors, by having an impact on the cost of
recovery and the rate of production, will also affect the present value of
future net cash flows from estimated reserves. Many of the factors, assumptions
and variables involved in estimating reserves are beyond our control and may
prove to be incorrect over time. Results of drilling, testing and production
after the date of the

5



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estimates may require substantial upward or downward
revisions in our reserve data. Any downward adjustment could lead to lower
future production and thus adversely affect our financial condition, future
prospects and market value.

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 the 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 Unitholders.

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 labor problems. Our operations will
also often require the use of new and advanced technologies, which can be
expensive to develop, purchase and implement, and may not function as we
expect. We may experience substantial cost overruns caused by changes in the
scope and magnitude of our operations, employee strikes and 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.

We will encounter competition in all areas of our business and may not be able
to

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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 an investment in Trust Units is highly dependent on our key
personnel.

Unitholders will be entirely dependent on our management in respect of
administration of all matters relating to our assets and securities. Investors
not willing to rely on our management 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.

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

7



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

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

The continuing production from approximately 6% 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 distributions to Unitholders.

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
Unitholders.

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

Under Canadian and United States accounting rules, the net amounts at
which petroleum and natural gas costs on a property or project basis are
carried are subject to a cost-recovery test which is based in part upon
estimated future net cash flows from reserves. If our net capitalized costs
exceed the estimated recoverable amounts, we will have to charge the amounts of
the excesses to earnings. A decline in oil and natural gas prices could cause
our capitalized costs to exceed the cost ceiling, resulting in a charge against
earnings. The market may view the charge to earnings unfavorably. The charge to
earnings may also limit our ability to borrow funds.

8



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We may be unable to secure additional financing.

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

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

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

It may be difficult for an investor to dispose of Trust Units or recoup an
investment in Trust Units.

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.

Unitholders may suffer dilution of their interests in PET.

To maintain or expand PETs oil and natural gas reserves we will need to
finance capital expenditures and property acquisitions. Consequently,
Unitholders 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 investors 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

9



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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 investors to
personal 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
favorable.

The trust indenture which established PET as a trust restricts the
ownership of Trust Units by Unitholders who are non-residents of Canada.
Unitholders who are non-residents of Canada for the purposes of the Income Tax
Act (Canada) and the regulations thereunder (Tax Act) face the risk of being
forced to sell some or all of their Trust Units, when market conditions may not
be favorable, in order to comply with these restrictions.

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
current production is weighted exclusively to natural gas and we may be more
subject to price fluctuations in natural gas than our competitors whose
production is more diversified than ours.

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



| |  |  | the demand for oil and natural gas;                                                                                                                                                      
| | - |  | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|
| |  |  | the proximity and capacity of oil and natural gas pipelines and
processing equipment;                                                                                                    
|
| |  |  | changes in government regulations (including regulations relating
to environmental protection, royalties, allowable production, pricing,
importing and exporting of oil and natural gas);
|
| |  |  | weather;                                                                                                                                                                                 
|
| |  |  | general economic conditions; and                                                                                                                                                         
|
| |  |  | conditions in other natural gas producing regions.                                                                                                                                       

The negative impact of any one of these or other factors could
significantly affect our

10



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results of operations, our distributable income and
our overall financial condition.

Variations in interest rates may limit our distributions to Unitholders.

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 Unitholders. Certain covenants in our loan agreements with our
lenders could limit distributions to Unitholders. 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 distributions to Unitholders.

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

Our operating costs, including costs of production, are generally paid in
Canadian dollars. World oil prices are quoted in U.S. dollars and the price
Canadian producers receive is therefore affected by the Canadian/U.S. dollar
exchange rate that will fluctuate over time. A material increase in the value
of the Canadian dollar may negatively impact our production revenue.

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
| | - |  | -----------------------------------------------------------------------------------

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| |   |  | 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.

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

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

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us without needing to demonstrate
that the damage is due to any fault on our part.

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



| |  |  | modify operations;                  
| | - |  | ------------------------------------
|
| |  |  | install pollution control equipment;
|
| |  |  | perform site clean-ups; or          
|
| |  |  | curtail or cease certain operations.

In particular, the Canadian government has adopted the 1997 Kyoto Protocol to
the United Nations Framework Convention on Climate Change, known as the Kyoto
Protocol. As a result, new requirements and regulations may be implemented
which would require us to incur significant costs to comply. In addition, increasingly
strict environmental requirements affect product specifications and operational
practices. Future expenditures to meet such specifications could have a
material adverse effect on our operations or financial condition. Any
abandonment costs we incur will reduce distributions to Unitholders.

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

The Tax Act imposes penalties for the acquisition or holding of
non-qualified or ineligible investments by registered retirement savings plans,
deferred profit sharing plans, registered retirement income funds and
registered education savings plans. Should the Trust Units become ineligible or
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.

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

PET could be a passive foreign investment company (or PFIC) for United
States federal income tax purposes. If PET were considered a PFIC, then United
States persons holding Trust Units would be subject to materially adverse
United States federal income tax consequences with respect to distributions
received on, and dispositions of, Trust Units.

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

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



| |  |  | effect service of process within the United States on us or any of
our directors and officers, or                                                                                     
| | - |  | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|
| |  |  | enforce judgments obtained in the United States courts against us
or our directors and officers based upon the civil liability provisions
of the United States federal securities law.

We have been advised by our Canadian counsel, Burnet, Duckworth & Palmer
LLP, that there is doubt as to:



| |  |  | whether a judgment of a United States court based solely upon the
civil liability provisions of the United States federal securities laws
would be enforceable in Canada against us or our directors and
officers, and
| | - |  | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|
| |  |  | whether an original action could be brought in Canada against us or
such others to enforce liabilities based solely upon the United States
federal securities law.                                                    




ITEM 4. INFORMATION ON THE COMPANY




A.     HISTORY AND DEVELOPMENT OF THE COMPANY

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 settler, and the
Administrator. This trust indenture was subsequently amended and restated
effective as of August 1, 2002 (the PET Trust Indenture). Computershare
Trust Company of Canada has been appointed as the trustee (the Trustee) of
PET. PETs assets consist primarily of the POT Royalty, certain debt owing by
POT to PET, 100% ownership of the Administrator and the ownership of 100% of
the beneficial interest in POT.

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

In April and May of 2002, the board of directors of PRL gave its initial
approval to the formation and structuring of a trust to hold a number of mature
producing properties of PRL. Pursuant to the proposal, PRL would distribute
the units of such trust to the holders of its common shares through a
dividend-in-kind. The mature, net cash generating, producing properties to be
transferred to the trust were considered to be suitable for a trust and
management of PRL believed the transaction would be financially beneficial to
shareholders of PRL. A fundamental underlying business purpose of the
transaction was to eliminate the layer of corporate income tax attributable to
the

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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 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 assets
POT acquired from PRL pursuant to the transactions above are referred
to herein as the PET Assets. PRLs remaining assets in northeast
Alberta, not acquired by POT are referred to herein as the Excluded
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

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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 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.

On April 10, 2003, the Trust announced the closing of the acquisition from
PRL of the 100% working interest in the Ells natural gas property in northeast
Alberta at a purchase price of approximately $19.9 million. The acquisition
was funded through PETs existing credit facility with $6.0 million paid on
March 19, 2003 and the remainder paid on April 30, 2003. The Ells Property is
located immediately east of the Trusts East Legend property. At the time of
its acquisition, the Ells Property was non-producing but has recently commenced
initial production at approximately 8.0 mmcf/d from the Wabiskaw and McMurray
formations. The Administrator estimates the PET interest in the total proved
reserves in the Ells Property at 6.75 bcf and probable reserves (risked at 50%)
at 0.7 bcf. The acquisition of the Ells Property also includes a dedicated gas
plant with capacity to process 8.5 to 10 mmcf/d, a compressor station and a
gathering system.

On May 30, 2003, PET closed the issuance of 5,000,000 Trust Units on
bought deal basis to a syndicate of underwriters at $12.65 per Trust Unit for
net proceeds of $60,087,500. Proceeds of the financing were used to repay a
portion of PETs indebtedness to its bankers.

As
noted under Item 4.B below under the caption Acquisitions, PET is
continually reviewing opportunities to acquire additional properties. If it
decides to pursue an opportunity it deems attractive, it may seek to finance
the same through bank borrowings or the sale of additional Trust Units or a
combination of the two.




B.     BUSINESS OVERVIEW

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. Our 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 our
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.

Historically, production from the properties comprising part of our assets
was marketed internally by PRLs gas marketers. POTs internal marketing group
will continue to market production from these assets with a view to optimizing
gas netbacks

16



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by seeking out the best markets. Transportation of our production
will be continually monitored to obtain the lowest possible transportation
fees. We currently have 88 full and part-time employees. The technical staff
at PRL who were responsible for managing our current assets for a number of
years are now employed by the Administrator for and on behalf of POT and will
be responsible for the ongoing management of these properties on behalf of POT.
The continuity of this technical team should ensure the continued efficient
exploitation of our asset base.

Exploitation Drilling

We intend to optimize the value of our assets by exploiting the natural
gas production potential associated with these properties. We will focus our
capital expenditures on drilling low risk development wells to maximize
production and cash flow. We believe that 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 farm out higher risk exploration projects, by entering into agreements with
third parties whereby they will provide exploration funding in exchange for an
earned interest, or sell properties which we do not feel will provide adequate
returns or do not have an acceptable risk profile.

Acquisitions

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

Drilling Activity

PRL or PET, as the case may be, drilled, or participated in drilling,
exploratory and development wells located on the PET Assets for the periods
indicated as shown in the following table. The natural gas wells listed below
comprise all natural gas wells capable of production, whether producing or
capped, in which an interest is included in the PET Assets.

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|                  |  |                    |     |                         |  |                         |      |        |  |          |    |        |  |  |      |  |  |  |    |  |  |  |      | 
|----------------- |  | ------------------ | --- | ----------------------- |  | ----------------------- | ---- | ------ |  | -------- | -- | ------ |  |  | ---- |  |  |  | -- |  |  |  | ---- | 
|                  |  | Three Months Ended |     | Year Ended December 31, |  | Year Ended December 31,
|                  |  | March 31, 2003     |     | 2002                    |  | 2001                   
|                  |  |                    |     |                         |  |                        
|                  |  | Gross(1)           |     | Net(2)                  |  | Gross(1)                |      | Net(2) |  | Gross(1) |    | Net(2)
|                  |  |                    |     |                         |  |                         |      |        |  |          |    |       
|Natural Gas       |  |                    | 16  |                         |  |                         | 11.4 |        |  |          | 16 |        |  |  | 13.1 |  |  |  | 38 |  |  |  | 33.8 | 
|Service           |  |                    | 1   |                         |  |                         | 0.5  |        |  |          | 2  |        |  |  | 1.4  |  |  |  | 1  |  |  |  | 0.5  | 
|Dry and Abandoned |  |                    |    |                         |  |                         |     |        |  |          | 2  |        |  |  | 1.5  |  |  |  | 3  |  |  |  | 2.5  | 
|                  |  |                    |     |                         |  |                         |      |        |  |          |    |        |  |  |      |  |  |  |    |  |  |  |      | 
|Total             |  |                    | 17  |                         |  |                         | 11.9 |        |  |          | 20 |        |  |  | 16.0 |  |  |  | 42 |  |  |  | 36.8 | 
|                  |  |                    |     |                         |  |                         |      |        |  |          |    |        |  |  |      |  |  |  |    |  |  |  |      | 
|Success Rate (%)  |  |                    | 100 |                         |  |                         | 100  |        |  |          | 90 |        |  |  | 91   |  |  |  | 93 |  |  |  | 93   | 
|Exploratory (3)   |  |                    |    |                         |  |                         |     |        |  |          |   |        |  |  |     |  |  |  | 12 |  |  |  | 11.0 | 
|Development (4)   |  |                    | 17  |                         |  |                         | 11.9 |        |  |          | 20 |        |  |  | 16.0 |  |  |  | 30 |  |  |  | 25.8 | 
|                  |  |                    |     |                         |  |                         |      |        |  |          |    |        |  |  |      |  |  |  |    |  |  |  |      | 
|Total             |  |                    | 17  |                         |  |                         | 11.9 |        |  |          | 20 |        |  |  | 16.0 |  |  |  | 42 |  |  |  | 36.8 | 
|                  |  |                    |     |                         |  |                         |      |        |  |          |    |        |  |  |      |  |  |  |    |  |  |  |      | 

Notes:



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

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 our financial condition.

Future Commitments and Natural Gas Marketing

PET currently has no material future contracts to buy, sell, exchange or
transport natural gas from its assets. PET currently sells approximately 56%
of its gas production at AECO market prices. An additional 40% is directed to
the Progas and PanAlberta aggregator pools. PET currently has one financial
natural gas hedge in place; a costless collar for 15,000 GJ/day for the period
from July through September 2003 with a floor of $7.00 per GJ and a ceiling of
$7.37 per GJ. PET currently has no other financial hedges or physical fixed
price sales contracts in place for commodity, currency or interest rates.

It is expected that, on average, 30% to 50% of PETs production will be
subject to various hedging arrangements. PET intends to limit the use of
derivative financial instruments to hedging purposes and it does not intend to
engage in speculative transactions for which there is no underlying offsetting
position. PET also intends to limit credit risk by entering into hedging
arrangements with only the most financially secure of counterparties.

Government regulations materially affecting PETs business and operations
are described under the caption Government Regulation in Item 5.A of this
report.




C.     ORGANIZATIONAL STRUCTURE

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PET

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 Alberta Royalty Tax Credits, 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.

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.

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.

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

Public Unitholder Flowchart




D.     PROPERTY, PLANTS AND EQUIPMENT

The natural gas properties and facilities referred to in this section,
other than the Ells property, which was acquired in April 2003, were acquired
by PET from PRL in February and March of 2003. 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, except for the
Ells property which was effective March 19, 2003 and the cash flow from the
effective date to closing date in each instance accrued to PET.

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Reference is made to the material under Government Regulation in Item
5.A of this report for a discussion of the material effects of various
governmental regulations (including environmental regulations) affecting PET.

Reserves

The McDaniel Report evaluates the proved natural gas reserves attributable
to the properties comprising the PET Assets using a constant price of $5.29 per
Mmbtu as provided by PRL, being the price received by PRL from sales of natural
gas on December 31, 2002, based upon Remaining Reserves (as defined below) as
at January 1, 2003. These reserves are all located in Canada. For the
purposes of this report on Form 20-F we are utilizing only the proved reserves.

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

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

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

|                                  |  |                      |         |              |  |      |         |  |  |                    |         | 
|--------------------------------- |  | -------------------- | ------- | ------------ |  | ---- | ------- |  |  | ------------------ | ------- | 
|                                  |  |                      |         |              |  |      |         |  |  | Present Value Cash
|                                  |  |                      |         |              |  |      |         |  |  | Flow Discounted at
|                                  |  | Remaining Reserves   |         | 10% (Net)   
|Reserves Categories               |  | of Natural Gas(1)(2) |         | (Before Tax)
|                                  |  |                      |         |             
|                                  |  | Gross(3)             |         | Net(4)       |  |      |         | 
|                                  |  | mmcf                 |         | Mmcf         |  | (M$)
|                                  |  |                      |         |              |  |     
|Proved Developed Producing(7)     |  |                      | 158,792 |              |  |      | 126,746 |  |  |                    | 354,954 | 
|Proved Developed
Non-Producing(7) |  |                      | 3,195   |              |  |      | 2,677   |  |  |                    | 2,754   | 
|Proved Undeveloped(8)             |  |                      | 2,279   |              |  |      | 1,637   |  |  |                    | 5,109   | 
|                                  |  |                      |         |              |  |      |         |  |  |                    |         | 
|Total Proved(6)                   |  |                      | 164,266 |              |  |      | 131,060 |  |  |                    | 362,817 | 
|                                  |  |                      |         |              |  |      |         |  |  |                    |         | 

Notes:

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| | (1)  |  | Natural Gas means the
lighter hydrocarbons and associated non-hydrocarbon substances occurring naturally in an underground
reservoir, which under atmospheric conditions is essentially a gas,
but which may contain liquids. The natural gas reserve estimates
are reported on a marketable basis, that is the gas which is
available to a transmission line after removal of certain
hydrocarbons and non-hydrocarbon compounds present in the raw
natural gas and which meets specifications for use as a domestic,
commercial or industrial fuel.                                                                                                                                                                                                                                                                                                                          
| | ---- |  | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|
| | (2)  |  | Remaining Reserves means those quantities of crude oil,
natural gas, natural gas liquids and sulphur remaining after
deducting those quantities produced up to the reference date of the
study.                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                
|
| | (3)  |  | Gross Reserves are the total of the working interests
and/or royalty interests share of reserves before deducting
royalties owned by others.                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                   
|
| | (4)  |  | Net Reserves are the total of the working interests and/or
royalty interests share of reserves after deducting the amount
attributable to the royalties owned by others.                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                       
|
| | (5)  |  | The term royalties, as used in the McDaniel Report, refers
to royalties paid to others. The royalties deducted from the
reserves are based on the royalty percentage calculated by applying
the applicable Royalty Rate or formula. In the case of Crown
sliding scale royalties which are dependent on selling price, the
price forecasts for the individual properties in question has been
employed.                                                                                                                                                                                                                                                                                                                                                                                                                                                                        
|
| | (6)  |  | Proved Reserves are the estimated quantities of crude oil,
natural gas, and natural gas liquids which geological and
engineering data demonstrate with reasonable certainty to be
recoverable in future years from known reservoirs under existing
economic and operating conditions, i.e. prices and costs as of the
date the estimate is made. Prices include consideration of changes
in existing prices provided only by contractual arrangements, but
not on escalations based upon future conditions.                                                                                                                                                                                                                                                                                                                                                                    
|
| | (7)  |  | Proved Developed Reserves are reserves that can be expected
to be recovered through existing wells with existing equipment and
operating methods. Additional oil and gas expected to be obtained
through the application of fluid injection or other improved
recovery techniques for supplementing the natural forces and
mechanisms of primary recovery should be included as proved
developed reserves only after testing by a pilot project or after
the operation of an installed program has confirmed through
production response that increased recovery will be achieved.                                                                                                                                                                                                                                                                                           
|
| | (8)  |  | Proved Undeveloped Reserves are reserves that are expected
to be recovered from new wells on undrilled acreage, or from
existing wells where a relatively major expenditure is required for
recompletion. Reserves on undrilled acreage shall be limited to
those drilling units offsetting productive units that are reasonably
certain of production when drilled. Proved reserves for other
undrilled units can be claimed only where it can be demonstrated
with certainty that there is continuity of production from the
existing productive formation. Under no circumstances should
estimates for proved undeveloped reserves be attributable to any
acreage for which an application of fluid injection or other
improved recovery technique is contemplated, unless such techniques
have been proved effective by actual tests in the area and in the
same reservoir.
|
| | (9)  |  | Sales Gas includes pipeline and solution gas reserves.                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                           
|
| | (10) |  | The product price used in the constant price evaluations was
Cdn $5.29 per Mmbtu as furnished to McDaniel by PET. The constant
price assumptions assume the continuance of current laws,
regulations and operating costs in effect on the effective date of
the McDaniel Report.                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                 
|
| | (11) |  | The McDaniel Report estimates total net proven capital
investment necessary to achieve the estimated future net cash flow
to be $3,037,000, of which 2,321,000 is to be spent in 2003 based on
constant cost assumptions, in respect of the PET Assets.                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                          

Historical Reserves

The following table sets out the proved natural gas reserves at December 31,
2002, 2001,

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2000 and 1999 (before deducting amounts attributable to royalties
owned by others) of the PET Assets and based upon constant price and cost
assumptions. All of these reserves were located in Canada:

|                  |                                 |  |                             |       |  
|----------------- | ------------------------------- |  | --------------------------- | ----- | -
|                  |                                 |  | Proved Natural Gas Reserves
|                  |                                 |  | (bcf)                      
|                  |                                 |  |                            
|December 31, 1999 |                                 |  | 315.7                       |      
|                  | Revisions to previous estimates |  |                             | (62.9 | )
|                  | Purchase (sale of reserves)     |  |                             | 2.9   |  
|                  | Discoveries and extensions      |  |                             | 2.7   |  
|                  | Production                      |  |                             | (39.3 | )
|December 31, 2000 |                                 |  | 219.1                       |      
|                  | Revisions to previous estimates |  |                             | 3.4   |  
|                  | Purchase (sale of reserves)     |  |                             | 0.3   |  
|                  | Discoveries and extensions      |  |                             |      |  
|                  | Production                      |  |                             | (37.5 | )
|December 31, 2001 |                                 |  | 185.3                       |      
|                  | Revisions to previous estimates |  |                             | 3.8   |  
|                  | Purchase (sale of reserves)     |  |                             | 9.8   |  
|                  | Discoveries and extensions      |  |                             |      |  
|                  | Production                      |  |                             | (34.6 | )
|December 31, 2002 |                                 |  | 164.3                       |      

Land Holdings

The following table sets out the developed and undeveloped land holdings
in which PET has an interest as of April 1, 2003:

|                        |  |                 |         |                         |  |          |         |        |  |  |        |  |  |  |        | 
|----------------------- |  | --------------- | ------- | ----------------------- |  | -------- | ------- | ------ |  |  | ------ |  |  |  | ------ | 
|                        |  | Developed Acres |         | Undeveloped Acres(3)(4)
|                        |  |                 |         |                        
|Name of Area (Alberta)  |  | Gross(1)        |         | Net(2)                  |  | Gross(1) |         | Net(2)
|                        |  |                 |         |                         |  |          |         |       
|Bohn Lake               |  |                 | 46,400  |                         |  |          | 14,272  |        |  |  | 1,600  |  |  |  | 533    | 
|Chard                   |  |                 | 19,840  |                         |  |          | 15,476  |        |  |  | 6,400  |  |  |  | 6,244  | 
|Chard Southwest         |  |                 | 7,680   |                         |  |          | 3,118   |        |  |  | 9,600  |  |  |  | 5,186  | 
|Clyde                   |  |                 | 12,800  |                         |  |          | 11,771  |        |  |  | 14,080 |  |  |  | 14,080 | 
|Cold Lake               |  |                 | 59,201  |                         |  |          | 45,233  |        |  |  | 22,720 |  |  |  | 17,769 | 
|Cold Lake Sonoma        |  |                 | 36,800  |                         |  |          | 27,990  |        |  |  | 13,440 |  |  |  | 12,800 | 
|Corner                  |  |                 | 74,240  |                         |  |          | 73,155  |        |  |  | 28,160 |  |  |  | 27,200 | 
|Ells                    |  |                 | 23,040  |                         |  |          | 23,040  |        |  |  | 5,760  |  |  |  | 5,760  | 
|Hoole                   |  |                 | 7,040   |                         |  |          | 4,160   |        |  |  | 5,120  |  |  |  | 2,880  | 
|Kettle River            |  |                 | 33,920  |                         |  |          | 31,831  |        |  |  | 0      |  |  |  | 0      | 
|Legend                  |  |                 | 109,440 |                         |  |          | 91,927  |        |  |  | 40,960 |  |  |  | 40,422 | 
|Legend East             |  |                 | 27,520  |                         |  |          | 27,520  |        |  |  | 24,960 |  |  |  | 24,960 | 
|Leismer / Leismer South |  |                 | 134,400 |                         |  |          | 127,728 |        |  |  | 97,280 |  |  |  | 90,911 | 
|Liege East              |  |                 | 10,560  |                         |  |          | 9,471   |        |  |  | 1,920  |  |  |  | 1,686  | 
|Liege North             |  |                 | 69,760  |                         |  |          | 63,333  |        |  |  | 0      |  |  |  | 0      | 

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|                       |  |                 |           |                         |  |          |         |        |  |  |         |  |  |  |         | 
|---------------------- |  | --------------- | --------- | ----------------------- |  | -------- | ------- | ------ |  |  | ------- |  |  |  | ------- | 
|                       |  | Developed Acres |           | Undeveloped Acres(3)(4)
|                       |  |                 |           |                        
|Name of Area (Alberta) |  | Gross(1)        |           | Net(2)                  |  | Gross(1) |         | Net(2)
|                       |  |                 |           |                         |  |          |         |       
|Liege South            |  |                 | 86,880    |                         |  |          | 79,834  |        |  |  | 31,360  |  |  |  | 12,163  | 
|Pony                   |  |                 | 10,880    |                         |  |          | 4,240   |        |  |  | 7,040   |  |  |  | 3,040   | 
|Quigley                |  |                 | 52,160    |                         |  |          | 52,160  |        |  |  | 13,760  |  |  |  | 13,760  | 
|Saleski                |  |                 | 66,560    |                         |  |          | 62,876  |        |  |  | 22,080  |  |  |  | 19,424  | 
|Surmont                |  |                 | 5,760     |                         |  |          | 1,440   |        |  |  | 5,120   |  |  |  | 1,280   | 
|Teepee Creek           |  |                 | 76,399    |                         |  |          | 39,481  |        |  |  | 61,440  |  |  |  | 46,720  | 
|Thornbury              |  |                 | 48,640    |                         |  |          | 34,892  |        |  |  | 3,200   |  |  |  | 1,152   | 
|Winefred               |  |                 | 69,760    |                         |  |          | 62,848  |        |  |  | 29,440  |  |  |  | 22,000  | 
|                       |  |                 |           |                         |  |          |         |        |  |  |         |  |  |  |         | 
|Total                  |  |                 | 1,089,680 |                         |  |          | 907,796 |        |  |  | 445,440 |  |  |  | 369,970 | 
|                       |  |                 |           |                         |  |          |         |        |  |  |         |  |  |  |         | 

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 2003, 78,208 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.                                                                                                                                                                                                

The Administrator estimates that PETs undeveloped net acreage would have
a market value of approximately $24 million.

Principal Properties

The following table provides selected operational information in respect
of the Trusts principal properties:

|                        |  |              |       |          |  |               |      |                  |  |  |         | 
|----------------------- |  | ------------ | ----- | -------- |  | ------------- | ---- | ---------------- |  |  | ------- | 
|                        |  |              |       |          |  | Production(2) |      | Undeveloped Land
|                        |  | Reserves(1)  |       |          |  |              
|Name of Area (Alberta)  |  | Proved (bcf) |       | (mmcf/d) |  | (net acres)  
|                        |  |              |       |          |  |              
|Bohn Lake               |  |              | 4.6   |          |  |               | 1.9  |                  |  |  | 533     | 
|Chard                   |  |              | 1.7   |          |  |               | 2.0  |                  |  |  | 6,244   | 
|Chard Southwest         |  |              | 1.6   |          |  |               | 0.7  |                  |  |  | 5,186   | 
|Clyde                   |  |              | 2.2   |          |  |               | 2.1  |                  |  |  | 14,080  | 
|Cold Lake               |  |              | 7.5   |          |  |               | 4.5  |                  |  |  | 17,769  | 
|Cold Lake Sonoma        |  |              | 5.4   |          |  |               | 3.0  |                  |  |  | 12,800  | 
|Corner                  |  |              | 18.9  |          |  |               | 12.9 |                  |  |  | 27,200  | 
|Ells                    |  |              | 6.7   | (1)      |  |               | 4.0  |                  |  |  | 5,760   | 
|Hoole                   |  |              | 0.0   |          |  |               | 0.3  |                  |  |  | 2,880   | 
|Kettle River            |  |              | 6.4   |          |  |               | 3.7  |                  |  |  | 0       | 
|Legend                  |  |              | 52.8  |          |  |               | 20.0 |                  |  |  | 40,422  | 
|Legend East             |  |              | 3.7   |          |  |               | 3.0  |                  |  |  | 24,960  | 
|Leismer / Leismer South |  |              | 9.8   |          |  |               | 8.8  |                  |  |  | 90,911  | 
|Liege East              |  |              | 3.0   |          |  |               | 1.5  |                  |  |  | 1,686   | 
|Liege North             |  |              | 5.7   |          |  |               | 2.3  |                  |  |  | 0       | 
|Liege South             |  |              | 5.0   |          |  |               | 3.8  |                  |  |  | 12,163  | 
|Pony                    |  |              | 0.9   |          |  |               | 0.5  |                  |  |  | 3,040   | 
|Quigley                 |  |              | 3.6   |          |  |               | 3.2  |                  |  |  | 13,760  | 
|Saleski                 |  |              | 9.7   |          |  |               | 4.0  |                  |  |  | 19,424  | 
|Surmont                 |  |              | 0.0   |          |  |               | 0.1  |                  |  |  | 1,280   | 
|Teepee Creek            |  |              | 0.7   |          |  |               | 1.8  |                  |  |  | 46,720  | 
|Thornbury               |  |              | 11.8  |          |  |               | 4.5  |                  |  |  | 1,152   | 
|Winefred                |  |              | 9.2   |          |  |               | 3.5  |                  |  |  | 22,000  | 
|                        |  |              |       |          |  |               |      |                  |  |  |         | 
|Total                   |  |              | 171.0 |          |  |               | 92.1 |                  |  |  | 369,970 | 
|                        |  |              |       |          |  |               |      |                  |  |  |         | 

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Notes:



|(1) |  | Derived from McDaniel Report based on price as at January 1, 2003, except
with respect to Ells property which represent Managements estimates at
March 31, 2003.
|--- |  | ----------------------------------------------------------------------------------------------------------------------------------------------------------------
|   
|(2) |  | Average volume for the month of April 2003.                                                                                                                     

As at April 1, 2003, approximately 92 mmcf/d or 100% of PETs proved producing
reserves were on production. The following is a narrative description of the
Trusts principal properties.

Bohn Lake, Alberta

The Bohn Lake Area is in northeast Alberta approximately 90 kilometers
south of Fort McMurray. The area comprises 48,000 gross acres (14,805 net
acres) including an average 27.6% working interest in 26 (7.2 net) producing
natural gas wells. The average daily production for the month of April, 2003
from the Bohn Lake Area was approximately 1.9 mmcf/d of natural gas (net). The
McDaniel Report evaluated PETs total proved reserves at 4.62 bcf (gross) of
natural gas for the Bohn Lake Area. Production from the Bohn Lake Area is
processed through one gas plant owned and operated by Canadian Natural
Resources Limited.

Chard, Alberta

The Chard Area is in northeast Alberta approximately 85 kilometers south
of Fort McMurray. The area comprises 26,240 gross acres (21,720 net acres)
including an average 81.7% working interest in 16 (13.1 net) producing natural
gas wells. The average daily production for the month of April, 2003 from the
Chard Area was approximately 2.0 mmcf/d of natural gas (net). The McDaniel
Report evaluated PETs total proved reserves at 1.65 bcf (gross) of natural gas
for the Chard Area. Production from the Chard Area is processed through one
booster compressor owned 100% by PET.

Chard Southwest, Alberta

The Chard Southwest Area is in northeast Alberta approximately 85
kilometers south of Fort McMurray. The area comprises 17,280 gross acres
(8,304 net acres) including an average 40.7% working interest in 9 (3.7 net)
producing natural gas wells. The average daily production for the month of
April, 2003 from the Chard Southwest Area was approximately 0.7 mmcf/d of
natural gas (net). The McDaniel Report evaluated PETs total proved reserves
at 1.63 bcf (gross) of natural gas for the Chard Southwest Area. Production
from the Chard Southwest Area is processed through one booster compressor owned
by Superman Resources Inc. and one gas plant owned by Canadian Natural
Resources Limited. PETs interest in the gas plant is 33.3%.

Clyde, Alberta

The Clyde Area is in northeast Alberta approximately 85 kilometers
southwest of Fort McMurray. The area comprises 26,880 gross acres (25,851 net
acres) including an average 94.2% working interest in 12 (11.3 net) producing
natural gas wells. The average daily production for the month of April, 2003
from the Clyde Area was approximately 2.1 mmcf/d of natural gas (net). The
McDaniel Report evaluated PETs total proved

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reserves at 2.21 bcf (gross) of
natural gas for the Clyde Area. Production from the Clyde Area is processed
through one gas plant owned 100% by PET.

Cold Lake, Alberta

The Cold Lake Area is in northeast Alberta approximately 250 kilometers
southeast of Fort McMurray. The Cold Lake area comprises 81,921 gross acres
(63,002 net acres) including an average 78.4% working interest in 45 (35.3 net)
producing natural gas wells. The average daily production for the month of
April, 2003 from the Cold Lake Area was approximately 4.5 mmcf/d of natural gas
(net). The McDaniel Report evaluated PETs total proved reserves at 7.50 bcf
(gross) of natural gas for the Cold Lake Area. Production from the Cold Lake
Area is processed through 14 booster and/or compressor stations owned by
Altagas Services Inc.

Cold Lake Sonoma, Alberta

The Cold Lake Sonoma Area is in northeast Alberta approximately 250
kilometers southeast of Fort McMurray. The Cold Lake Sonoma area comprises
50,240 gross acres (40,790 net acres) including an average 71.2% working
interest in 30 (21.4 net) producing natural gas wells. The average daily
production for the month of April, 2003 from the Cold Lake Sonoma Area was
approximately 3.0 mmcf/d of natural gas (net). The McDaniel Report evaluated
PETs total proved reserves at 5.40 bcf (gross) of natural gas for the Cold
Lake Sonoma Area. Production from the Cold Lake Sonoma Area is processed
through four compressor stations, three at Marie Lake and one at Wolf Lake
which are 100% owned by PET.

Corner, Alberta

The Corner Area is in northeast Alberta approximately 80 kilometers
southwest of Fort McMurray. The area comprises 102,400 gross acres (72,433 net
acres) including an average 99.0% working interest in 59 (58.4 net) producing
natural gas wells. The average daily production for the month of April, 2003
from the Corner Area was approximately 12.9 mmcf/d of natural gas (net). The
McDaniel Report evaluated PETs total proved reserves at 18.85 bcf (gross) of
natural gas for the Corner Area. Production from the Corner Area is processed
through one gas plant owned 100% by PET.

Ells, Alberta

The Ells Property was acquired by the Trust effective March 19, 2003 for
$19.9 million. Prior to closing, the asset was non-producing; however,
production commenced on March 19, 2003. Ells is located in northeast Alberta
approximately 50 kilometers northwest of Fort McMurray, and 16 kilometers 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 8 producing natural
gas wells, 14 non-producing natural gas wells, which subsequently commenced
production in June 2003, and 3 suspended potential gas wells. The Ells
Property acquisition also included the purchase of related facilities including
a gas plant, a booster compressor station and 36 kilometers of gathering
system.

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The average daily production for the month of April, 2003 from the Ells
Property was approximately 4.0 mmcf/d (net) of natural gas. The Administrator
estimates the PET interest in the total proved reserves in the Ells Property at
6.75 bcf (gross).

Hoole, Alberta

The Hoole Area is in northeast Alberta approximately 175 kilometers
southwest of Fort McMurray. The area comprises 12,160 gross acres (7,040 net
acres) including an average 70% working interest in 5 (3.5 net) producing
natural gas wells. The average daily production for the month of April, 2003
from the Hoole Area was approximately 0.3 mmcf/d of natural gas (net). The
McDaniel Report evaluated PETs total proved reserves at 0.02 bcf (gross) of
natural gas for the Hoole Area. Production from the Hoole Area is processed
through one gas plant owned by Husky Energy Inc.

Kettle River, Alberta

The Kettle River Area is in northeast Alberta approximately 80 kilometers
south of Fort McMurray. The area comprises 33,920 gross acres (31,831 net
acres) including an average 94.7% working interest in 24 (22.7 net) producing
natural gas wells. The average daily production for the month of April, 2003
from the Kettle River Area was approximately 3.7 mmcf/d of natural gas (net).
The McDaniel Report evaluated PETs total proved reserves at 6.35 bcf (gross)
of natural gas for the Kettle River Area. Production from the Kettle River
Area is processed through one gas plant owned 92.5% by PET.

Legend, Alberta

The Legend Area is approximately 120 kilometers northwest of Fort
McMurray. The area comprises 150,400 gross acres (132,349 net acres) including
an average 82% working interest in 59 gross (48.4 net) producing natural gas
wells. The average daily production for the month of April, 2003 based upon
such working interest from the Legend Area was approximately 20.0 mmcf/d of
natural gas (net). The McDaniel Report evaluated PETs proved reserves at
52.77 bcf (gross) of natural gas for the Legend Area. PET has a 77.9% interest
in and currently operates one gas plant and six field booster compressors that
process the natural gas from this area.

Legend East, Alberta

The Legend East Area is in northeast Alberta approximately 120 kilometers
west of Fort McMurray. The area comprises 52,480 gross acres (52,480 net
acres) including a 100% working interest in 17 producing natural gas wells.
The average daily production for the month of April, 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 3.73 bcf (gross) 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.

27



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Leismer / Leismer South, Alberta

The Leismer / Leismer South Area is in northeast Alberta approximately 90
kilometers southwest of Fort McMurray. The area comprises 231,680 gross acres
(218,639 net acres) including a 91.6% working interest in 53 (48.6 net)
producing natural gas wells. The average daily production for the month of
April, 2003 from the Leismer / Leismer South Area was approximately 8.8 mmcf/d of natural gas (net). The
McDaniel Report evaluated PETs total proved reserves at 9.82 bcf (gross) of
natural gas for the Leismer / Leismer South Area. Production from the Leismer
/ Leismer South Area is processed through one gas plant owned 32.5% by PET and
three field booster compressors owned by PET.

Liege East, Alberta

The Liege East Area is in northeast Alberta approximately 120 kilometers
west of Fort McMurray. The area comprises 12,480 gross acres (11,157 net
acres) including an average 89.70% working interest in 10 (9.0 net) producing
natural gas wells. The average daily production for the month of April, 2003
from the Liege East Area was approximately 1.5 mmcf/d of natural gas (net).
The McDaniel Report evaluated PETs total proved reserves at 3.0 bcf (gross) of
natural gas for the Liege East Area. Production from the Liege East Area is
processed through the Liege South gas plant owned 80.5% by PET and one Liege
East field booster compressor owned 90.2% by PET.

Liege North, Alberta

The Liege North Area is in northeast Alberta approximately 120 kilometers
west of Fort McMurray. The area comprises 69,760 gross acres (63,333 net
acres) including an average 94.9% working interest in 14 (13.3 net) producing
natural gas wells. The average daily production for the month of April, 2003
from the Liege North Area was approximately 2.3 mmcf/d of natural gas (net).
The McDaniel Report evaluated PETs total proved reserves at 5.73 bcf (gross)
of natural gas for the Liege North Area. Production from the Liege North Area
is processed through one gas plant owned 94.6% by PET.

Liege South, Alberta

The Liege South Area is in northeast Alberta approximately 120 kilometers
west of Fort McMurray. The area comprises 118,240 gross acres (91,997 net
acres) including an average 96.8% working interest in 25 (24.2 net) producing
natural gas wells. The average daily production for the month of April, 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 5.03 bcf (gross)
of natural gas for the Liege South Area. Production from the Liege South Area
is processed through one gas plant owned 80.5% by PET and three field
compressors owned by PET.

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Pony, Alberta

The Pony Area is in northeast Alberta approximately 75 kilometers
southwest of Fort McMurray. The area comprises 17,920 gross acres (7,280 net
acres) including an average 52.5% working interest in 5 (2.6 net) producing
natural gas wells. The average daily production for the month of April, 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 0.94 bcf (gross) 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 kilometers south
of Fort McMurray. The area comprises 65,920 gross acres (65,920 net acres)
including a 100% working interest in 22 producing natural gas wells. The
average daily production for the month of April, 2003 from the Quigley Area was
approximately 3.2 mmcf/d of natural gas (net). The McDaniel Report evaluated
PETs total proved reserves at 3.6 bcf (gross) of natural gas for the Quigley
Area. Production from the Quigley Area is processed through one gas plant and
one field compressor owned by PET.

Saleski, Alberta

The Saleski Area is in northeast Alberta approximately 110 kilometers west
of Fort McMurray. The area comprises 88,640 gross acres (82,300 net acres)
including an average 95.1% working interest in 19 (18.1 net) producing natural
gas wells. The average daily production for the month of April, 2003 from the
Saleski Area was approximately 4.0 mmcf/d of natural gas (net). The McDaniel
Report evaluated PETs total proved reserves at 9.72 bcf (gross) of natural gas
for the Saleski Area. Production from the Saleski Area is processed through
one gas plant owned 95.8% by PET.

Surmont, Alberta

The Surmont Area is in northeast Alberta approximately 65 kilometers
southwest of Fort McMurray. The area comprises 10,880 gross acres (2,720 net
acres) including an average 25% working interest in 1 (0.3 net) producing
natural gas well. The average daily production for the month of April, 2003
from the Surmont Area was approximately 0.1 mmcf/d of natural gas (net). The
McDaniel Report evaluated PETs total proved reserves at 0.02 bcf (gross) of
natural gas for the Surmont Area. Production from the Surmont Area is
processed through one gas plant owned by Devon Canada Corporation.

Teepee Creek, Alberta

The Teepee Creek Area is in northeast Alberta approximately 175 kilometers
southwest of Fort McMurray. The area comprises 137,839 gross acres (86,201 net
acres) including an average 50% working interest in 17 (8.5 net) producing
natural gas wells. The average daily production for the month of April, 2003
from the Teepee Creek Area was approximately 1.8 mmcf/d of natural gas (net).
The McDaniel Report evaluated PETs total proved reserves at 0.71 bcf (gross)
of natural gas for the Teepee Creek Area.

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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 kilometers
southwest of Fort McMurray. The area comprises 51,840 gross acres (36,044 net
acres) including an average 73.5% working interest in 41 (30.2 net) producing
natural gas wells. The average daily production for the month of April, 2003
from the Thornbury Area was approximately 4.5 mmcf/d of natural gas (net). The
McDaniel Report evaluated PETs total proved reserves at 11.82 bcf (gross) of
natural gas for the Thornbury Area.
Production from the Thornbury Area is processed through four gas plants
and a field booster compressor owned by Altagas Services Inc.

Winefred, Alberta

The Winefred Area is in northeast Alberta approximately 200 kilometers
southeast of Fort McMurray. The area comprises 99,200 gross acres (84,848 net
acres) including an average 88.5% working interest in 39 (34.5 net) producing
natural gas wells. The average daily production for the month of April, 2003
from the Winefred Area was approximately 3.5 mmcf/d of natural gas (net). The
McDaniel Report evaluated PETs total proved reserves at 9.16 bcf (gross) of
natural gas for the Winefred Area. Production from the Winefred Area is
processed through two gas plants and a field booster compressor owned by
Altagas Services Inc.




ITEM 5. OPERATING AND FINANCIAL REVIEW AND PROSPECTS

You should read the following discussion of our financial condition and results
of operations together with our consolidated financial statements, which
information is incorporated by reference herein.

General

As of January 1, 2003, the estimated gross proved natural gas reserves of
the PET Assets were 164.3 bcf. For the three months ended March 31, 2003, the
PET Assets produced an average of 84.2 mmcf/d of natural gas. The PET Assets
are located entirely in the Province of Alberta, Canada and produce only
natural gas. Consequently, our initial operations comprise one geographic and
one business segment.

The PET Assets earn income from the sale of natural gas within the
Province of Alberta, Canada.

The expenses of the PET Assets include:



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

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

Period to period fluctuations in the operating income of the PET Assets
are the result of a combination of a number of factors including:



| |  | The volume of natural gas produced and sold.                                                                                                         
|- |  | -----------------------------------------------------------------------------------------------------------------------------------------------------
| 
| |  | The exchange rate between Canadian and U.S. dollars as Canadian natural gas prices tend to fluctuate, in part, in relation
to changes in U.S. prices.
| 
| |  | Changes in the Royalty Rates.                                                                                                                        
| 
| |  | Changes in the operating costs of producing natural gas from the PET Assets.                                                                         
| 
| |  | Changes in Canadian and North American natural gas prices.                                                                                           

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

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




A.     OPERATING RESULTS

Results of Operations

The financial and operating information of the Northeast Alberta
Properties has been prepared in accordance with Canadian generally accepted
accounting principles (Canadian GAAP). Canadian GAAP differs in some
respects from generally accepted accounting principles in the United States,
such differences are described in note 6 to the historical financial statements
of the Northeast Alberta Properties included as Exhibit 12.5 to this report.

The following analysis considers the combined results of operations for
the Northeast Alberta Properties for periods prior to the acquisition of the
PET Assets in the first quarter of 2003 followed by a separate discussion of
the PET Assets (production, revenues, royalties and operating costs) for each
of the periods plus the three months

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ended March 31, 2003. Pursuant to
continuity of interests accounting, this information is presented as if PET
owned the PET Assets for all periods presented.

PRL Northeast Alberta Assets

Year Ended December 31, 2002 Compared to the Year Ended December 31, 2001

Natural gas sales for the Northeast Alberta Properties decreased 46% to
$126.1 million for the year ended December 31, 2002 compared to $235.6 million
in 2001. Significantly lower natural gas prices in 2002 decreased revenue by
$89.3 million coupled with the effects of natural production declines which
reduced revenue by a further $20.3 million. The Northeast Alberta Properties
realized an average natural gas price of $3.58
per mcf in 2002, a decrease of 41% from $6.11 per mcf in 2001. Average
Alberta Reference Prices decreased 35% over the same period from $6.30 per mcf
in 2001 to $4.07 per mcf in 2002. During the same period NYMEX natural gas
prices decreased by 26% from U.S.$4.40 per Mmbtu to U.S.$3.25 per Mmbtu in
2001. Prices remained low through much of 2002 as demand weakened and supply
responded to increased North American drilling activity.

Average natural gas production for the Northeast Alberta Properties
decreased 9% in 2002 to 96.5 mmcf/d from 105.6 mmcf/d in 2001. Production
additions from the drilling of 16 (13.1 net) natural gas wells with a 90%
success rate in 2002 were offset by natural production declines.

The average Royalty Rate for the Northeast Alberta Properties for 2002
decreased to 17.8% from 20.1% in 2001 consistent with lower gas prices in 2002.

Unit production costs in 2002 were consistent with 2001 at $0.87 per mcf
compared to $0.88 per mcf in 2001 and total operating costs decreased by $3.3
million. The decrease in total costs was a result of lower production volumes.

Lower commodity prices in 2002 and natural production declines resulted in
operating income for the Northeast Alberta Properties decreasing by 53% to
$72.9 million from $154.4 million in 2001 as follows:

|                                 |  |   |       |  
|-------------------------------- |  | - | ----- | -
|($Cdn millions)                  |  |   |       |  
|                                 |  |   |       |  
|Production decrease              |  | $ | (20.3 | )
|Price decrease                   |  |   | (89.3 | )
|Royalty decrease                 |  |   | 24.8  |  
|Operating cost decrease          |  |   | 3.3   |  
|                                 |  |   |       |  
|Decrease in net operating income |  | $ | (81.5 | )
|                                 |  |   |       |  

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

Natural gas sales for the Northeast Alberta Properties increased 20% to
$235.6 million for the year ended December 31, 2001 compared to $195.9 million
in 2000. Significantly higher natural gas prices in 2001 increased revenue by
$63.0 million offsetting the effects of natural production declines which
reduced revenue by $23.3

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million. The Northeast Alberta Properties realized an
average natural gas price of $6.11 per mcf in 2001, an increase of 36% from
$4.48 per mcf in 2000. Average Alberta Reference Prices increased 25% over the
same period from $5.02 per mcf in 2000 to $6.30 per mcf in 2001. During the
same period NYMEX natural gas prices increased by 13% to U.S.$4.40 per Mmbtu
from U.S.$3.91 per Mmbtu in 2000. Canadian reference prices increased by more
than U.S. reference prices due to the combination of a 4% decrease in the
Canada/U.S. exchange rate and lower transportation differentials between
Canadian and U.S. gas prices related to increased pipeline capacity from
Canada. Continued concerns about gas supply contributed to very high prices in
early 2001 and resulted in the increase in the average price over 2000. Prices
fell through much of 2001 as demand weakened and supply responded to increased
North American drilling activity. The Northeast Alberta Properties realized an
increase in average natural gas prices greater
than that for the Reference Prices due to the fact that production was
higher in the early part of 2001 when prices were higher and then declined
later in the year.

Average natural gas production for the Northeast Alberta Properties
decreased 12% in 2001 to 105.6 mmcf/d from 119.5 mmcf/d in 2000. Production
additions from the drilling of 38 (33.8 net) natural gas wells with a 93%
success rate in 2001 were offset by natural production declines.

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

Unit production costs in 2001 increased 52% to $0.88 per mcf from $0.58
per mcf in 2000 and total operating costs increased by $8.6 million. The
Northeast Alberta Properties include plant facilities and gathering systems
intended to control the flow of our natural gas to market. These facilities
incur fixed costs, which are in addition to costs incurred at the well level,
thereby increasing total production costs. As production declines in more
mature areas, such as those areas comprising the Northeast Alberta Properties,
per unit production costs increase. Furthermore, with increased levels of
industry activity in 2001 compared to 2000, competition for services increased
labor costs, including well supervision and contract operating of wells, as
well as related aviation support and overhead. There were also an unusually
large amount of repairs, maintenance and overhaul expenditures on the Northeast
Alberta Properties in 2001 related to the start-up of amine treatment
facilities in a number of areas.

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

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|                                 |  |   |       |  
|-------------------------------- |  | - | ----- | -
|($Cdn millions)                  |  |   |       |  
|                                 |  |   |       |  
|Production decrease              |  | $ | (23.3 | )
|Price increase                   |  |   | 63.0  |  
|Royalty increase                 |  |   | (8.5  | )
|Operating cost increase          |  |   | (8.6  | )
|                                 |  |   |       |  
|Increase in net operating income |  | $ | 22.6  |  
|                                 |  |   |       |  

PET Assets

Three Months Ended March 31, 2003 Compared to the Three Months Ended March 31,
2002

Natural gas sales for the PET Assets increased 185% to $62.1 million for
the three months ended March 31, 2003, compared to $21.8 million for the three
months ended March 31, 2002. Decreased production volumes resulted in a $2.2
million decrease in revenue while higher natural gas prices increased revenue
by $42.5 million. Realized natural gas prices increased by 217% for the three
months ended March 31, 2003 to $8.19 per mcf from $2.59 per mcf in 2002.
Average Alberta Reference Prices increased 137%
from $3.34 per mcf for the three months ended March 31, 2002 to $7.92 per
mcf for the three months ended March 31,2003. During the same period, NYMEX
natural gas prices increased 169% to an average of U.S.$6.41 per Mmbtu for the
three months ended March 31, 2003 from an average of U.S.$2.38 per Mmbtu in the
2002 period. The increase in gas prices resulted from higher demand due to a
colder winter, decreased supply and lower storage levels offset by weak
economic conditions and increased political uncertainty.

Natural gas production for the PET Assets decreased 10% during the period
to 84.2 mmcf/d from 93.5 mmcf/d in the three months ended March 31, 2002.
Production additions realized from the drilling of 16 (13.1 net) natural gas
wells drilled in the first quarter of 2002 and brought onto production during
the second quarter of 2002 did not fully offset natural production declines.

For the three months ended March 31, 2003, the Royalty Rate for the PET
Assets was 22.9% compared to 16.7% for the three months ended March 31, 2002.
Royalty Rates in Alberta are on a sliding scale sensitive to prices.
Consequently, the increase in the average Royalty Rate is consistent with the
increase in the Alberta Reference Price in the three month period ended March
31, 2003.

Total production costs decreased $2.0 million in the three months ended
March 31, 2003 compared to the same period in 2002. Unit production costs were
$1.13 per mcf in the three months ended March 31, 2003 compared to $1.26 per
mcf for the same period in 2002. The reduction in unit costs arises as a
result of a decrease in average costs in the petroleum services industry and an
increased concentration on cost control on the PET Assets as well as routine
rotation in the facility maintenance schedules. First and second quarter
production costs are typically higher on the PET Assets due to their
winter-access only nature. Full year unit operating costs are estimated to be
$0.85 per mcf.

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The significantly higher commodity prices combined with lower production
volumes, higher royalties and lower production costs resulted in a $31.9
million increase in operating income for the PET Assets from $7.5 million for
the three months ended March 31, 2002 to $39.4 million for the three months
ended March 31, 2003:

|                                 |  |   |       |  
|-------------------------------- |  | - | ----- | -
|($Cdn millions)                  |  |   |       |  
|                                 |  |   |       |  
|Production decrease              |  | $ | (2.2  | )
|Price increase                   |  |   | 42.5  |  
|Royalty increase                 |  |   | (10.4 | )
|Operating cost decrease          |  |   | 2.0   |  
|                                 |  |   |       |  
|Increase in net operating income |  | $ | 31.9  |  
|                                 |  |   |       |  

General administrative expenses were $766,000 ($0.10 per mcf) in the first
three months of 2003 compared to $975,000 ($0.12 per mcf) in the comparative
2002 quarter. The 2002 figure represented an allocation of PRLs overall
administrative costs.

Interest expense was $451,000 in the first quarter of 2003 compared to nil
in the 2002 comparative quarter. In 2002 no bank debt was attributed to the
PET Assets as cash flow significantly exceeded capital expenditures, while in
2003 PET commenced bank borrowing on March 11.

The above factors combined to increase cash flow from operations to $37.8
million for the three months ended March 31, 2003 from $8.9 million in the
comparative 2002 period, a 325% increase.

Depletion and depreciation expense decreased from $12.5 million ($1.49 per
mcf) in the first quarter of 2002 to $11.0 million ($1.45 per mcf) in the 2003
quarter due to a decrease in the depletion rate related to reserve additions.

Net earnings were $26.4 million in the first quarter of 2003 compared to
loss of $4.4 million in the comparative 2002 period.

Year Ended December 31, 2002 Compared to the Year Ended December 31, 2001

Natural gas sales for the PET Assets decreased 46% to $123.7 million for
the year ended December 31, 2002 compared to $228.3 million in 2001.
Significantly lower natural gas prices in 2002 decreased revenue by $87.1
million coupled with the effects of natural production declines which reduced
revenue by a further $17.5 million. The PET Assets realized an average natural
gas price of $3.57 per mcf in 2002, a decrease of 41% from $6.09 per mcf in
2001. Average Alberta Reference Prices decreased 35% over the same period from
$6.30 per mcf in 2001 to $4.07 per mcf in 2002. During the same period NYMEX
natural gas prices decreased by 26% from U.S.$4.40 per Mmbtu to U.S.$3.25 per
Mmbtu in 2001. Prices remained low through much of 2002 as demand weakened and
supply responded to increased North American drilling activity.

Average natural gas production for the PET Assets decreased 8% in 2002 to
94.8 mmcf/d from 102.7 mmcf/d in 2001. Production additions from the drilling
of 16 (13.1 net) natural gas wells with a 90% success rate in 2002 were offset
by natural production declines.

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The average Royalty Rate for the PET Assets for 2002 decreased to 17.7%
from 20% in 2001 consistent with lower gas prices in 2002.

Unit production costs in 2002 were consistent with 2001 at $0.87 per mcf
compared to $0.88 per mcf in 2001 and total operating costs decreased by $2.6
million. The decrease in total costs was a result of lower production volumes.

Lower commodity prices in 2002 and natural production declines resulted in
operating income for the PET Assets decreasing by 52% to $71.6 million from
$149.7 million in 2001 as follows:

|                                 |  |   |       |  
|-------------------------------- |  | - | ----- | -
|($Cdn millions)                  |  |   |       |  
|                                 |  |   |       |  
|Production decrease              |  | $ | (17.5 | )
|Price decrease                   |  |   | (87.1 | )
|Royalty decrease                 |  |   | 23.9  |  
|Operating cost decrease          |  |   | 2.6   |  
|                                 |  |   |       |  
|Decrease in net operating income |  | $ | (78.1 | )
|                                 |  |   |       |  

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

Natural gas sales for the PET Assets increased 25% to $228.3 million for
the year ended December 31, 2001 compared to $182.7 million in 2000.
Significantly higher natural gas prices in 2001 increased revenue by $54.1
million offsetting the effects of natural production declines which reduced
revenue by $8.5 million. The PET Assets realized an average natural gas price
of $6.09 per mcf in 2001, an increase of 31% from $4.65 per mcf in 2000.
Average Alberta Reference Prices increased 25% over the same period from $5.02
per mcf in 2000 to $6.30 per mcf in 2001. During the same period NYMEX natural
gas prices increased by 13% to U.S.$4.40 per Mmbtu from U.S.$3.91 per Mmbtu in
2000. Canadian reference prices increased by more than U.S. reference prices
due to the combination of a 4% decrease in the Canada/U.S. exchange rate and
lower transportation differentials between Canadian and U.S. gas prices related
to increased pipeline capacity from Canada. Continued concerns about gas
supply contributed to very high prices in early 2001 and resulted in the
increase in the average price over 2000. Prices fell through much of 2001 as
demand weakened and supply responded to increased North American drilling
activity. The PET Assets realized an increase in average natural gas prices
greater than that for the Reference Prices due to the fact that production was
higher in the early part of 2001 when prices were higher and then declined
later in the year.

Average natural gas production for the PET Assets decreased 4% in 2001 to
102.7 mmcf/d from 107.4 mmcf/d in 2000. Production additions from the drilling
of 38 (33.8 net) natural gas wells with a 93% success rate in 2001 were offset
by natural production declines.

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The average Royalty Rate for the PET Assets for 2001 increased to 20% from
19.3% in 2000. While Royalty Rates in Alberta are sensitive to prices, the
2001 rate increase was less than the natural gas price increase for the PET
Assets, as Royalty Rates reach maximum amounts at higher price levels such as
those achieved in 2001.

Unit production costs in 2001 increased 43% to $0.88 per mcf from $0.61
per mcf in 2000 and total operating costs increased by $8.7 million. The PET
Assets include plant facilities and gathering systems intended to control the
flow of our natural gas to market. These facilities incur fixed costs, which
are in addition to costs incurred at the well level, thereby increasing total
production costs. As production declines in more mature areas, such as those
areas comprising the PET Assets, per unit production costs increase.
Furthermore, with increased levels of industry activity in 2001 compared to
2000, competition for services increased labor costs, including well
supervision and contract operating of wells, as well as related aviation
support and overhead. There were also an unusually large amount of repairs,
maintenance and overhaul expenditures on the PET Assets in 2001 related to the
start-up of amine treatment facilities in a number of areas.

Higher commodity prices in 2001 more than offset production declines and
higher unit production costs resulting in operating income for the PET Assets
increasing by 21% to $149.7 million from $123.4 million in 2000 as follows:

|                                 |  |   |       |  
|-------------------------------- |  | - | ----- | -
|($Cdn millions)                  |  |   |       |  
|                                 |  |   |       |  
|Production decrease              |  | $ | (8.5  | )
|Price increase                   |  |   | 54.1  |  
|Royalty increase                 |  |   | (10.6 | )
|Operating cost increase          |  |   | (8.7  | )
|                                 |  |   |       |  
|Increase in net operating income |  | $ | 26.3  |  
|                                 |  |   |       |  

Sensitivities

The following table summarizes the effects on estimated 2003 cash
available for distributions (prior to any reduction in production resulting
from the proposed ruling by the AEUB; see Government Regulation below) of
changes in natural gas production, prices, exchange rates and interest rates:

|                                  |  |           |     |          |       |                                            |       |  |      |  |      | 
|--------------------------------- |  | --------- | --- | -------- | ----- | ------------------------------------------ | ----- |  | ---- |  | ---- | 
|                                  |  |           |     |          |       | Effect on Cash Available for Distributions
|                                  |  |           |     |          |       |                                           
|Variable                          |  | Change    |     | ($000s) |       | ($/Trust Unit)(1)                         
|                                  |  |           |     |          |       |                                           
|Natural Gas Production (mmcf/d)   |  |           | 1.0 |          |       | $                                          | 1,080 |  |      |  | 0.03 | 
|Natural Gas Price ($/mcf)         |  | Cdn $0.10 |     | $        | 2,350 |                                            |       |  | 0.06 | 
|Canada  US Exchange (U.S.$/Cdn$) |  | US $0.01  |     | $        | 2,100 |                                            |       |  | 0.05 | 
|Interest Rates (%)                |  |           | 1   | %        |       | $                                          | 775   |  |      |  | 0.02 | 

Note:



|(1) |  | Assumes that 39,638,376 Trust Units are outstanding.
|--- |  | ----------------------------------------------------

Production and revenue have been estimated in the McDaniel Report
utilizing the McDaniel January 1, 2003 price forecast. Three factors in the
North American gas market: gas supply, gas storage and gas demand, could affect
future realized gas prices for the production from the PET Assets. Increases
in gas storage levels and/or increases in gas supply tend to decrease gas
prices. In addition, extreme weather-related short-term

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gas price increases
could lead to demand erosion as users of natural gas reduce their usage of
natural gas which may in turn result in decreased gas prices.

Government Regulation

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

Regulatory Rulings

In February of 1999, the AEUB issued Interim Directive 99-1 (ID 99-1)
which outlined new AEUB requirements regarding gas/bitumen production in
defined oil sands areas of Northeast Alberta. ID 99-1 contained provisions
regarding the grandfathering of gas production from wells completed in oil
sands strata prior to July 1, 1998 and for the application, notification and
drilling and production of wells in such areas subsequent to July 1, 1998.

In April of 2001, the AEUB, as part of its Decision 2000-22, issued an
order shutting-in 146 natural gas wells in the Surmont area of Northeast
Alberta on the basis that natural gas production would likely have a
detrimental effect on recovery of the underlying bitumen. PRL owned working
interests in 77 of the shut-in wells. The application that resulted in the
order was made by another resource company which successfully argued that it
would not be in the public interest to put the recovery of
bitumen at risk by allowing continued natural gas production. As a result
of an agreement subsequently reached among the relevant parties and the
Province of Alberta, compensation was paid to the owners of the shut-in wells,
including PRL, which received approximately $46 million. None of such shut-in
wells are included in the PET Assets.

During the period November 2001 to June 2002, the AEUB held a hearing (the
Chard/Leismer Hearing) to consider 27 applications incorporating 146 wells
from various parties, some respecting the shut-in of gas wells on the basis
that natural gas production could have a detrimental effect on recovery of the
underlying bitumen, and others for the approval to produce gas from wells in
the Chard area and Leismer Field. Specifically relating to PET, the hearing
included one application by a bitumen lease holder for shutting-in 40 existing
natural gas wells in the Chard area of Northeastern Alberta and three
applications by PRL on behalf of PET for approval to commence production of
natural gas from four wells in the Leismer area of Alberta. The AEUB had
previously granted an interim order shutting-in 10 of the 40 wells in the Chard
area. None of the 10 shut-in wells are included in the PET Assets; however, 18
of the remaining 30 wells and the four wells for which PRL made application are
included in the PET Assets. At issue in the Chard/Leismer Hearing was the
effect, if any, of natural gas production on future production of the
underlying bitumen. Other issues at the hearing included the appropriate
criteria to be used by the AEUB in determining whether to approve future
applications to produce natural gas and in determining whether to approve
future applications to shut-in existing natural gas wells in Northeast Alberta.
The PET Assets are all located in Northeast Alberta.

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On March 18, 2003 the AEUB issued Decision 2003-23 in regard to the
Chard-Leismer Hearing. The AEUB reaffirmed many of its previous findings as
set out in Interim Directive 99-1 and its decision 2000-22 on the gas over
bitumen dispute in the Surmont area. With respect to PETs assets, three of
four application wells were granted the right to commence production from
specific perforated intervals and two of 18 PET-interest wells being considered
for shut-in were ordered shut-in at specific perforated intervals effective May
1, 2003. The estimated production loss of 110 mcf/d from the gas wells
affected by the shut-in order was more than offset by the potential gain in
production of 250 to 500 mcf/d from the three newly-approved wells, for a net
gain in production.

On April 15, 2003, PRL and PET jointly filed an application with the Court
of Appeal of Alberta seeking leave to appeal the AEUB decision. The Court has
not yet heard arguments or made a decision on the application. We expect that
the operator and co-owner of the two affected PET interest wells will seek
compensation for any damages caused by the decision.

In addition, the AEUB indicated in Decision 2003-23 that it intended to
pursue development and implementation of a process to address production from
grandfathered (wells producing prior to July 1, 1998) and previously approved
gas wells in the vicinity of the Chard and Leismer areas. PET has a working
interest in 56 of the 117 grandfathered wells and 14 of the 22 previously
approved wells identified in the decision.

On April 3, 2003, the AEUB issued General Bulletin 2003-12, which sought
comment on the advisability of continuing gas production from existing wells
producing from the Wabiskaw and McMurray formations in the AEUB-defined
Athabasca Oil Sands
Area of Northeast Alberta that are currently grandfathered for production
on the basis that they may have an adverse effect on future bitumen recovery.
PET filed a submission in this regard on May 12, 2003.

On June 3, 2003 the AEUB released General Bulletin 2003-16 (GB 2003-16),
announcing a proposed change in policy respecting gas production from the
Wabiskaw and McMurray Formations in the AEUB-defined Athabasca Oil Sands Area.
GB 2003-16 provides a description of the policy it proposes to implement,
outlines a deadline for written submissions of June 26, 2003 with respect to
the proposed policy and provides notification of a two day consultation meeting
with interested parties beginning July 3, 2003, at which time the Trust will be
afforded 45 minutes to speak to its own submissions and those of other
interested parties. PET intends to make submissions as outlined in GB 2003-16.
Following these additional consultation steps and consideration of any evidence
put forward, the AEUB will issue its new policy.

The proposed policy contemplates the shut-in of all Wabiskaw-McMurray gas
production, without benefit of public hearing, within a 5.5 million acre area
in Northeastern Alberta, the Reduced Application Area (RAA). The Trust is at
risk of having up to a net 44 MMcf/d of natural gas production affected,
representing up to approximately 50 percent of its current production,
following a proposed shut-in on August 1, 2003.

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According to the proposed policy, after the shut-in has been implemented
the AEUB intends to complete a detailed review of shut-in gas production to
determine what, if any, gas should be allowed to re-commence production. GB
2003-16 also announced the immediate implementation of a reduced Wabiskaw and

McMurray gas production application area. The effect of this change is that
any outstanding gas production applications outside the RAA will be closed and
returned to the applicant. This allowed for the commencement of an additional
four mmcf/d of production net to PET in the Ells and Legend East fields in June
2003. In addition, new applications for gas production will only be required
within the RAA or where wells encounter Wabiskaw-McMurray gas pools which
overlap the RAA boundary.

At this time the ultimate policy resulting from GB 2003-16 is uncertain.
We cannot 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.

The North American Free Trade Agreement

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

Land Tenure

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

Royalties and Incentives

In addition to federal regulation, the province of Alberta has legislation
and regulations which govern land tenure, royalties, production rates,
environmental protection and other matters. The royalty regime is a significant
factor in the profitability of oil and natural gas production. Negotiations
between the mineral owner and the lessee determines royalties payable on
production from lands other than Crown lands.

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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 meter
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 meter), and 25% (when the RTCRP exceeds $210 per cubic meter). 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. The wells
currently drilled on the properties comprising the PET Assets are not eligible
for ARTC.

Environmental Regulation

The oil and natural gas industry is subject to environmental regulation
pursuant to local, provincial and federal legislation. Environmental
legislation provides for restrictions and prohibitions on releases or emissions
of various substances produced in association with certain oil and natural gas
industry operations. Such legislation can affect the location and operation of
wells and other facilities and the extent to which exploration and development
is permitted. Such legislation requires that well and facility

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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.

Critical Accounting Assumptions

PET follows the successful efforts method of accounting. Under this
method, PET will capitalize only those costs that result directly in the
discovery of petroleum and natural gas reserves. Exploration expenses,
including geological and geophysical costs, lease rentals and exploratory dry
hole costs, are charged to earnings as incurred. Leasehold acquisition costs,
including costs of drilling and equipping successful wells, are capitalized.
The net cost of unproductive wells, abandoned wells and surrendered leases are
charged to earnings in the year of abandonment or surrender. Gains or losses
are recognized on the disposition of properties and equipment.

The net amount at which petroleum and natural gas costs on a property or
project are carried is subject to a cost-recovery test. Any impairment loss is
the difference between the carrying value of the asset and its recoverable
amount (undiscounted).

Production from the PET Assets will deplete over time as outlined in the
McDaniel Report. To the extent that production declines exceed those expected
and to the extent that the PET Assets are not replaced by the acquisition of
additional assets, our cash flow will decline in the future.

Operating costs and unit operating costs are a factor of, among other
things, the cost and availability of labor and other oil and gas services,
power prices, the general level of activity in the oil and gas industry and the
individual performance of the wells in the PET Assets. To the extent that the
industry competition for labor and services rises, power prices increase or
individual wells require a higher level of repairs and maintenance, operating
costs could increase in the future.




B.     LIQUIDITY AND CAPITAL RESOURCES

PET Assets

Our 2003 budget presently totals $9.0 million for the drilling, completion
and tie-in of 17 wells as well as facility upgrades principally in the Legend
area. A total of $8.7 million had been spent to March 31, 2003 as the entire
drilling program had been completed by that date. PRLs capital expenditures
on the PET Assets totaled $11.1 million in 2002. The cost of drilling and
completing a well in these areas is approximately $300,000 to $400,000.

The McDaniel Report includes a total of $4.8 million in estimated future
capital costs over the life of the reserves required for the drilling,
completion, equipping and tie-in of up to 6 wells and the equipping, tie-in and
recompletion of up to 22 wells included in the proved plus probable reserves of
the PET Assets. We have no known additional

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material future capital
requirements to recover the reserves recognized in the McDaniel Report. While
there are no significant seasonal limitations on gas production from the PET
Assets, the PET Assets are located in winter access areas and consequently,
capital and operating expenditures tend to be higher in winter months.

Mineral and surface rentals for the PET Assets are payable to the Province
of Alberta and others for both producing and non-producing acreage. Such
payments are estimated to total $1,665,274, $1,153,272, $1,087,007, $1,050,984
and $959,144 in 2003, 2004, 2005, 2006 and 2007, respectively.

Paramount Energy Trust

Our only internal source of cash is currently the net operating income
generated by our assets and distributions to Unitholders will be limited to
available cash after costs of operation and capital expenditures related to the
properties as well as any debt repayments. In addition to available bank
financing and cash flow from the PET Assets, we may issue additional Trust
Units in the future.

On May 30, 2003, PET closed the issuance of 5,000,000 Trust Units on a
bought deal basis to a syndicate of underwriters at $12.65 per Trust Unit for
net proceeds of $60,087,500. Proceeds of the financing were used to repay a
portion of PETs indebtedness to its bankers.

A syndicate of financial institutions have agreed to provide PET with a
demand credit facility in the maximum amount of $115,000,000 which amount
includes a $10,000,000 working capital component. Actual borrowings under the
credit facility will be limited to a borrowing base as determined from time to
time by our lenders. Under the
credit facility PET will pay interest rates and commitment fees on undrawn
amounts on terms negotiated and at rates agreed to between us and our lenders
from time to time.

We commenced distributions to Unitholders in the month of April 2003 with
a distribution of cash flow from the PET Assets for the three months ended
March 31, 2003 totalling $0.83 per Trust Unit. For the period from July 1,
2002 to December 31, 2002, cash flow from the PET Assets was used to fund
production and administrative expenses, interest, capital expenditures and to
accumulate working capital for our ongoing operations.

Management believes that PETs working capital is sufficient for its
present requirements.






|C. |  | RESEARCH AND DEVELOPMENT                                   
|-- |  | -----------------------------------------------------------
|  
|   |  | PET does not engage in research and development activities.






|D. |  | TREND INFORMATION                                                                                                               
|-- |  | --------------------------------------------------------------------------------------------------------------------------------
|  
|   |  | We perceive a number of trends that may materially affect our business,
financial condition or results of operations, including:

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| |  |  | Price Volatility. Our income and the value of the Trust
Units will be affected by fluctuations in the price of natural gas.
Natural gas pricing is largely a function of supply and demand and
has been very volatile. For example, prices per GJ, based on the
average monthly Alberta Reference Price, fluctuated between $2.50
and $8.29 in 2000, $2.40 and $11.21 in 2001, and $2.71 and $4.94 in
2002. The price of natural gas in the North American markets
reached record highs in late 2000 and early 2001, partly because of
the demand created by new gas-fired electrical generating
facilities, and ultimately led to fuel switching in an effort by
some consumers to minimize its effect. This switching, along with a
number of other factors, including mild weather during late 2001,
caused a material shift in demand for natural gas and resulted in
large volumes of natural gas being stored. This led to a sharp
decline in natural gas prices. A cooler winter, decreased gas in
storage and limited production increases resulted in increased
prices through the first four months of 2003 with monthly average
prices per GJ fluctuating between $6.44 and $10.13.                                                                                                                                                                                        
| | - |  | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|
| |  |  | Consolidation of Industry Participants. Our industry has
been experiencing a large number of business combinations, involving
companies of all sizes. This consolidation process has resulted in
a number of asset rationalization programs pursuant to which assets
have become available for acquisition. This same consolidation
process has resulted in some of the industry participants with whom
we will be competing for attractive large asset or share
acquisitions having become larger and more competitive, which may
increase the demand for acquisitions.                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                              
|
| |  |  | Investor Focus. Investors are becoming increasingly aware of
the oil and natural gas royalty trust sector and the income trust
sector (referred to in this paragraph as the Trust Sector). We
believe that due to the nature of the assets held by royalty trusts,
as well as their focus on development and exploitation rather than
exploration, investor interest in the oil and natural gas sector has
increased with the growing perception that royalty trusts, such as
PET, offer a vehicle to invest in the oil and natural gas industry
with less risk than more traditional oil and natural gas
investments. Consequently, the Trust Sector has recently been able
to access the capital markets more readily than traditional oil and
gas companies. This access to capital has made the Trust Sector a
competitor for oil and natural gas property and corporate
acquisitions. The Trust Sector has an advantage over oil and gas
companies in corporate taxation. A number of Canadian-based oil and
gas companies are currently taxable, having depleted their
accumulated tax pools, and therefore they generally assess the
merits of potential acquisitions on an after-tax basis. Oil and
gas royalty trusts and income trusts distribute income to their
unitholders. Units of these royalty and income trusts are often
held in tax sheltered vehicles such as

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| |  |  | registered retirement savings plan accounts, and distributions on
the units held in such vehicles are thus generally sheltered from
immediate taxation.
| |  |  | -------------------------------------------------------------------------------------------------------------------------------------------------------




E.     OFF-BALANCE SHEET ARRANGEMENTS

Not applicable.




F.     TABULAR DISCLOSURE OF CONTRACTUAL OBLIGATIONS

Not applicable.




ITEM 6. DIRECTORS, SENIOR MANAGEMENT AND EMPLOYEES




A.     DIRECTORS AND SENIOR MANAGEMENT

As a trust, PET has no officers, directors or employees. The
Administrator is responsible for the day to day operations and management of
PET. 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 constituting 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 of                  |  |     |    |                   |  | Offices held with                                           |  |                      |  |                                                                                             
|Residence                                 |  | Age |    | the Administrator |  | Director Since                                              |  | Principal Occupation
|                                          |  |     |    |                   |  |                                                             |  |                     
|Clayton H.
Riddell(4)
Calgary, Alberta    |  |     | 65 |                   |  | Chairman of the
Board, Chief
Executive Officer
and Director |  | June 28, 2002        |  | Chairman of the
Board of PRL and
Chief Executive
Officer of PRL                             
|Susan L. Riddell
Rose(3)
Calgary, Alberta |  |     | 38 |                   |  | President, Chief
Operating Officer
and Director             |  | June 28, 2002        |  | President and Chief
Operating Officer
of the
Administrator                                  
|Cameron R. Sebastian
Calgary, Alberta     |  |     | 40 |                   |  | Vice-President,
Finance and Chief
Financial Officer         |  |                     |  | Vice-President,
Finance and Chief
Financial Officer
of the
Administrator since
June 28, 2002
|Gary C. Jackson
Calgary, Alberta          |  |     | 49 |                   |  | Vice-President,
Land, Legal and
Acquisitions                |  |                     |  | Vice-President,
Land, Legal and
Acquisitions of the
Administrator since
June 28, 2002       
|Myra Jones
Calgary, Alberta               |  |     | 57 |                   |  | Corporate Secretary                                         |  |                     |  | Corporate Secretary
of the
Administrator since
June 28, 2002                                

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|                                                    |  |     |    |                   |  |                            |  |                      |  |                                                                      
|--------------------------------------------------- |  | --- | -- | ----------------- |  | -------------------------- |  | -------------------- |  | ---------------------------------------------------------------------
|Name and Municipality of                            |  |     |    |                   |  | Offices held with          |  |                      |  |                                                                      
|Residence                                           |  | Age |    | the Administrator |  | Director Since             |  | Principal Occupation
|                                                    |  |     |    |                   |  |                            |  |                     
|Kevin J. Marjoram
Calgary, Alberta                  |  |     | 46 |                   |  | Vice-President,
Operations |  |                     |  | Vice-President,
Operations of the
Administrator since
July 1, 2002   
|Donald J.
Nelson(1)(3)(4)(7)
Calgary, Alberta       |  |     | 55 |                   |  | Director                   |  | June 28, 2002        |  | Private Businessman                                                  
|John W. (Jack)
Peltier(1)(2)(3)(7)
Calgary, Alberta |  |     | 64 |                   |  | Director                   |  | June 28, 2002        |  | President of
Ipperwash Resources
Ltd., a private
investment company  
|Karen A.
Genoway(2)(4)(7)
Calgary, Alberta          |  |     | 48 |                   |  | Director                   |  | June 28, 2002        |  | Vice-President,
Land, Onyx Energy
Inc., a private oil
and gas company
|Howard R.
Ward(1)(2)(7)
Calgary, Alberta            |  |     | 58 |                   |  | Director                   |  | June 28, 2002        |  | Partner with International
Energy Counsel, 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 19,782,810 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, Honors 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 and the American Association of Petroleum Geologists. Mr.
Riddell is or has been a director of the following publicly traded entities
during the periods indicated: Newalta Corporation (July 1988  present); and
Berkley Petroleum Corp. (1993  March 2001). Mr. Riddell is the father of Ms.
Susan L. Riddell Rose.

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

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

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

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

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

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

Myra Jones, Corporate Secretary

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

Kevin Marjoram, Vice-President of Operations

Mr. Marjoram graduated from the University of Calgary with a Bachelor of
Science Degree in Chemical Engineering in 1983. Mr. Marjoram has been the
Vice-President of Operations of the Administrator since July 1, 2002. Prior
thereto he

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was Area Engineering Manager, N.E.
Alberta  West Side for PRL from
July 2000 to June 2002. Prior thereto he held positions in an operations
managerial capacity for Spire Energy Ltd. and Northrock Resources Ltd. (both
public oil and gas companies). Mr. Marjoram is a member of the Association of
Professional Engineers, Geologists and Geophysicists of Alberta.

John W. (Jack) Peltier, Director

Mr. Peltier graduated from the Royal Military College of Canada with a
Bachelor of Science degree and Queens University at Kingston with an M.B.A.
Mr. Peltier received his Chartered Financial Analyst designation in 1974 and is
a member of the Association for Investment Management and Research. Since 1978
he has been President of Ipperwash Resources Ltd. and predecessor companies, a
private company providing management and financial consulting services. From
March 2001 he was a trustee and, most recently, Chairman of the Board of
Trustees of Request Income Trust until its acquisition by Pulse Data Inc. in
January 2002. From 1986 to June 2001 he was a member and, most recently,
Chairman of the board of directors of Enermark Inc. and concurrently of the
Board of Trustees of Enermark Income Fund. From May 2000 to June 2001 he was a
member of the board of directors of Enerplus Resources Corporation, and
concurrently a member of the Board of Trustees of Enerplus Resources Fund. The
aforementioned entities merged to continue as Enerplus Resources Fund in June
2001. Mr. Peltier was Chief Financial Officer of Thunder Energy Ltd. from
October 1995 to September 2000 where he has been a director from October 1995
to present. From July 1995 to October 1996 he was the Chief Financial Officer
of Bow Valley Energy Ltd. where he was a director from 1996 to February 2002.
In the past 5 years Mr. Peltier has held numerous directorships in public
entities in addition to those described above as follows: Belfast Petroleum
Ltd., director (1995 to July 1999); Courage Energy Inc., director (November
2000 to July 2001); Westbrook Energy Corporation, director (November 1997 to
October 1999); Manhattan Resources Ltd. (acquirer of Westbrook Energy
Corporation), director (October 2001 to January 2003); 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

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

Karen A. Genoway, Director

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

Howard R. Ward, Director

Mr. Ward holds a Bachelor of Arts Degree (1967) and a Bachelor of Law
Degree (1969) from the University of New Brunswick. He has been a member of
the Law Society of Alberta since 1975 and is a member of the Canadian Bar
Association and the Calgary Bar Association. From 1978 to 2000 he was a
partner of Burstall Ward, Barristers and Solicitors. From 2000 to June of 2002
he was counsel with Donahue & Partners LLP. From June 2002 to December of 2002
he was counsel with McCarthy Tetrault LLP. Effective December of 2002 he
became a partner with International Energy Counsel, 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

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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.




B.     COMPENSATION

Directors Fees

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.

Executive Compensation

We have employment agreements with the following executive officers:

Susan L. Riddell Rose, President and Chief Operating Officer



| |  |  | annual compensation (including allowances)  $232,250
| | - |  | -----------------------------------------------------
|
| |  |  | Unit Incentive Rights  200,000 Incentive Rights     
|
| |  |  | reviewable annually                                  

Clayton H. Riddell, Chairman, Chief Executive Officer



| |  |  | annual compensation (including allowances)  $175,000
| | - |  | -----------------------------------------------------
|
| |  |  | Unit Incentive Rights  200,000 Incentive Rights     
|
| |  |  | reviewable annually                                  

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



| |  |  | annual compensation (including allowances)  $190,750
| | - |  | -----------------------------------------------------
|
| |  |  | Unit Incentive Rights  80,000 Incentive Rights      
|
| |  |  | retention bonus paid during 2003  $50,000           
|
| |  |  | reviewable annually                                  

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



| |  |  | annual compensation (including allowances)  $190,750                                                                                                                                                                                                                                        
| | - |  | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|
| |  |  | Unit Incentive Rights  100,000 Incentive Rights                                                                                                                                                                                                                                             
|
| |  |  | reviewable annually                                                                                                                                                                                                                                                                          
|
| |  |  | termination payment, in the event of termination without cause,
material reduction in salary, benefits or status of employee or POG
selling more than 60% of its Trust Units, equal to the greater of one
and one-half years salary and benefits or industry standard severance
compensation

Kevin Marjoram, Vice-President, Operations

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| |  |  | annual compensation (including
allowances)  $156,250
| | - |  | -----------------------------------------------------
|
| |  |  | Unit Incentive Rights  80,000 Incentive Rights      
|
| |  |  | reviewable annually                                  

Neither the Administrators Chief Executive Officer nor the
Administrators four most highly compensated executive officers during the
financial period from PETs inception on June 28, 2002 to December 31, 2002
received any compensation from PET during such period. In addition, no
options, stock appreciation rights or incentive rights were granted during the
period ended December 31, 2002.




C.     BOARD PRACTICES

The terms of office of all directors of the Administrator will expire on
the date of the next annual shareholders meeting of the Administrator.

Corporate Governance Committee

The Corporate Governance Committee is responsible for the governance of
the Administrators Board of Directors 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 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

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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.




D.     EMPLOYEES

The Administrator currently retains approximately 88 full and part-time
employees for the purposes of operating POTs oil and gas operations. Our
employees also render services to the Administrator and PET. Our employees
consist of approximately 55 field employees and approximately 33 office
personnel, and we have approximately 22 independent contractors. Concurrent
with retention of these employees in August of 2002, we entered into the
Administrative Services Agreement with PRL under which PRL agreed to provide to
POT certain administrative, financial, accounting, land management, engineering
and other technical services for a transitional period scheduled to end on July
31, 2003 and the Administrator on POTs behalf agreed to provide to PRL certain
administrative, financial, accounting, land management, engineering and other
technical services relating to our assets and the business and affairs of PRL
for a transitional period that will end on July 31, 2003. The Administrator
does not have any temporary, seasonal or unionized employees and its
relationships with its employees are satisfactory




E.     SHARE OWNERSHIP

Trust Unit Ownership

The following table sets forth information concerning beneficial ownership
of Trust Units as of June 23, 2003 by the directors and senior management of
the Administrator named in Item 6.B above.

The information provided in the table is based on our records and
information provided to us. The number of Trust Units beneficially owned by
each person is determined under rules of the Securities and Exchange
Commission, and the information is not necessarily indicative of beneficial
ownership for any other purpose. Unless otherwise indicated, each person has
sole voting and investment power (or shares such powers with his or her spouse)
with respect to the Trust Units set forth in the following table.

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|                      |  |                    |            |            |  |           |      |  |  |  |         | 
|--------------------- |  | ------------------ | ---------- | ---------- |  | --------- | ---- |  |  |  | ------- | 
|Name of Beneficial    |  | Trust Units        |            | Percent of |  | Incentive
|Owner                 |  | Beneficially Owned |            | Class      |  | Rights(1)
|Clayton H. Riddell    |  |                    | 19,651,603 | (2)        |  |           | 44.0 |  |  |  | 200,000 | 
|Susan L. Riddell Rose |  |                    | 111,403    | (3)        |  |           | *    |  |  |  | 200,000 | 
|Cameron R. Sebastian  |  |                    |           |            |  |           | *    |  |  |  | 80,000  | 
|Gary C. Jackson       |  |                    |           |            |  |           | *    |  |  |  | 100,000 | 
|Kevin Marjoram        |  |                    |           |            |  |           | *    |  |  |  | 80,000  | 
|Myra Jones            |  |                    | 13,276     | (5)        |  |           | *    |  |  |  |        | 
|John W. Peltier       |  |                    | 8,245      | (4)        |  |           | *    |  |  |  | 15,000  | 
|Donald J. Nelson      |  |                    | 5,000      |            |  |           | *    |  |  |  | 15,000  | 
|Karen A. Genoway      |  |                    | 5,232      |            |  |           | *    |  |  |  | 15,000  | 
|Howard R. Ward        |  |                    | 1,316      |            |  |           | *    |  |  |  | 15,000  | 

*     Represents holdings of less than 1%.

(1)  No incentive rights are presently exercisable or are exercisable within 60
days after the date of this report.

(2)  Includes 19,149,947 Trust Units held by Paramount Oil & Gas Ltd. and its
subsidiaries Treherne Resources Ltd. and 409790 Alberta Ltd. as to which Trust
Units Mr. Riddell has the power to direct the vote and disposition. Also
includes 315,872 Trust Units owned by Mr. Riddells spouse.

(3)  Includes 22,282 Trust Units owned by Ms. Riddell Roses spouse.

(4)  Includes 4,718 Trust Units owned by Mr. Peltiers spouse.

(5)  Includes 13,276 Trust Units owned by Ms. Jones spouse.

As at June 23, 2003, the directors and senior officers of the
Administrator, as a group, beneficially owned, directly and indirectly, or
exercised control or direction over, 19,782,810 Trust Units (44.3% of the
issued and outstanding Trust Units). None of these individuals has control or
direction over greater than 5% of the Trust Units with the exception of Mr.
Riddell.

Unit Incentive Plan

Subject to regulatory approval, PET has adopted a unit incentive plan (the
Unit Incentive Plan) which permits the Administrators board of directors to
grant non-transferable rights to purchase Trust Units (Incentive Rights) to
our employees, officers, directors and other service providers. The purpose of
the Unit Incentive Plan is

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to provide an effective long term incentive to
eligible participants and to reward them on the basis of our long term
performance and distributions.

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

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

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

All 1,003,000 Unit Incentive Rights granted to date have a grant price and
strike price of $5.05 per Trust Unit and expire on January 28, 2008.

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ITEM 7. MAJOR SHAREHOLDERS AND RELATED PARTY TRANSACTIONS




A.     MAJOR SHAREHOLDERS

To the knowledge of the directors and officers of the Administrator, the
only persons or entities who will beneficially own, directly or indirectly, or
exercise control or direction over, Trust Units carrying more than 5% of the
voting rights attached to such Trust Units as at June 23, 2003 are as follows:

|                         |                          |                    |             |       |            |  |      |  | 
|------------------------ | ------------------------ | ------------------ | ----------- | ----- | ---------- |  | ---- |  | 
|                         |                          |                    | Trust Units |       | Percent of
|Name of Beneficial Owner |                          | Beneficially Owned |             | Class
|Clayton H. Riddell,(1)   |                          |                    | 19,651,603  |       |            |  | 44.0 | 
|                         | Calgary, Alberta, Canada |                    |             |       |            |  |      |  | 

Note:

(1)  Includes 19,149,947 Trust Units held by Paramount Oil & Gas Ltd. and its
subsidiaries Treherne Resources Ltd. and 409790 Alberta Ltd. as to which Trust
Units Mr. Riddell has the power to direct the vote and disposition. Also
includes 315,872 Trust Units owned by Mr. Riddells spouse. All Trust Units
beneficially owned by Mr. Riddell were acquired within the three years
preceding the date of this report.

The Trust Units beneficially owned by Mr. Riddell do not have voting rights
different from those held by any other Unitholder.

As at June 18, 2003, based upon the list maintained by PETs transfer
agent, 2,750,547 Trust Units (approximately 6.2% of the issued and outstanding
Trust Units) are held of record by 68 persons with addresses in the United
States.

Paramount Oil & Gas Ltd., an Alberta corporation controlled by Clayton H.
Riddell, controls PET within the meaning of U.S. securities laws by virtue of
its ownership of Trust Units.




B.     RELATED PARTY TRANSACTIONS

Effective July 1, 2002, PET entered into a series of agreements with its
then parent Paramount Resources Limited, to acquire certain natural gas
properties in northeast Alberta. The purchase price for the initial assets
acquired was $81 million funded by way of issue of units and promissory notes.
The purchase price for the remaining additional assets was $220 million funded
by way of cash received from the issue of Trust Units pursuant to a Rights
offering and bank debt.

On July 1, 2002, PET entered into an agreement with a related party,
Summit Resources Limited, to acquire all of the furniture, fixtures and
information technology infrastructure located in the Trusts current office
premises. The purchase price for these assets was $2,073,000 and was paid for
by way of issue of a promissory note.

Reference is made to Item 4.A for a description of our purchase from PRL
of the

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Ells natural gas property.




C.     INTERESTS OF EXPERTS AND COUNSEL

Not applicable.




ITEM 8. FINANCIAL INFORMATION




A.     CONSOLIDATED STATEMENTS AND OTHER FINANCIAL INFORMATION

See the financial statements included as Exhibits 12.3, 12.4 and 12.5.

Legal Proceedings

PET is not a party to any material legal or arbitration proceedings.
Reference is made to the discussion relating to recent announcements by the
Alberta Energy and Utilities Board appearing under the caption Significant
Changes in Item 8.B of this report.

Distributions

PET distributes to its Unitholders all of its income less expenses,
permitted deductions and payments required to be made to third parties.




B.     SIGNIFICANT CHANGES

In February of 1999, the AEUB issued Interim Directive 99-1 (ID 99-1)
which outlined new AEUB requirements regarding gas/bitumen production in
defined oil sands areas of Northeast Alberta. ID 99-1 contained provisions
regarding the grandfathering of gas production from wells completed in oil
sands strata prior to July 1, 1998 and for the application, notification and
drilling and production of wells in such areas subsequent to July 1, 1998.

In April of 2001, the AEUB, as part of its Decision 2000-22, issued an
order shutting-in 146 natural gas wells in the Surmont area of Northeast
Alberta on the basis that natural gas production would likely have a
detrimental effect on recovery of the underlying bitumen. PRL owns working
interests in 77 of the shut-in wells. The application that resulted in the
order was made by another resource company which successfully argued that it
would not be in the public interest to put the recovery of bitumen at risk by
allowing continued natural gas production. As a result of an agreement
subsequently reached among the relevant parties and the Province of Alberta,
compensation was paid to the owners of the shut-in wells, including PRL, which
received approximately $46 million. None of such shut-in wells are included in
the PET Assets.

During the period November 2001 to June 2002, the AEUB held a hearing (the
Chard/Leismer Hearing) to consider 27 applications incorporating 146 wells
from various parties, some respecting the shut-in of gas wells on the basis
that natural gas production could have a detrimental effect on recovery of the
underlying bitumen, and

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others for the approval to produce gas from wells in
the Chard area and Leismer Field. Specifically relating to PET, the hearing
included one application by a bitumen lease
holder for shutting-in 40 existing natural gas wells in the Chard area of
Northeastern Alberta and three applications by PRL on behalf of PET for
approval to commence production of natural gas from four wells in the Leismer
area of Alberta. The AEUB had previously granted an interim order shutting-in
10 of the 40 wells in the Chard area. None of the 10 shut-in wells are
included in the PET Assets; however, 18 of the remaining 30 wells and the four
wells for which PRL made application are included in the PET Assets. At issue
in the Chard/Leismer Hearing was the effect, if any, of natural gas production
on future production of the underlying bitumen. Other issues at the hearing
included the appropriate criteria to be used by the AEUB in determining whether
to approve future applications to produce natural gas and in determining
whether to approve future applications to shut-in existing natural gas wells in
Northeast Alberta. The PET Assets are all located in Northeast Alberta.

On March 18, 2003 the AEUB issued Decision 2003-23 in regard to the
Chard-Leismer Hearing. The AEUB reaffirmed many of its previous findings as
set out in Interim Directive 99-1 and its decision 2000-22 on the gas over
bitumen dispute in the Surmont area. With respect to PETs assets, three of
four application wells were granted the right to commence production from
specific perforated intervals and two of 18 PET-interest wells being considered
for shut-in were ordered shut-in at specific perforated intervals effective May
1, 2003. The estimated production loss of 110 mcf/d from the gas wells
affected by the shut-in order was more than offset by the potential gain in
production of 250 to 500 mcf/d from the three newly-approved wells, for a net
gain in production.

On April 15, 2003, PRL and PET jointly filed an application with the Court
of Appeal of Alberta seeking leave to appeal the AEUB decision. The Court has
not yet heard arguments or made a decision on the application. We expect that
the operator and co-owner of the two affected PET interest wells will seek
compensation for any damages caused by the decision.

In addition, the AEUB indicated in Decision 2003-23 that it intended to
pursue development and implementation of a process to address production from
grandfathered (wells producing prior to July 1, 1998) and previously approved
gas wells in the vicinity of the Chard and Leismer areas. PET has a working
interest in 56 of the 117 grandfathered wells and 14 of the 22 previously
approved wells identified in the decision.

On April 3, 2003, the AEUB issued General Bulletin 2003-12, which sought
comment on the advisability of continuing gas production from existing wells
producing from the Wabiskaw and McMurray formations in the AEUB-defined
Athabasca Oil Sands Area of Northeast Alberta that are currently grandfathered
for production on the basis that they may have an adverse effect on future
bitumen recovery. PET filed a submission in this regard on May 12, 2003.

On June 3, 2003 the AEUB released General Bulletin 2003-16 (GB 2003-16),
announcing a proposed change in policy respecting gas production from the
Wabiskaw and McMurray Formations in the AEUB-defined Athabasca Oil Sands Area.
GB 2003-

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16 provides a description of the policy it proposes to implement,
outlines a deadline for written submissions of June 26, 2003 with respect to
the proposed policy and provides notification of a two day consultation meeting
with interested parties beginning July 3, 2003, at which time the Trust will be
afforded 45 minutes to speak to its own submissions and those of other
interested parties. PET intends to make submissions as outlined in GB
2003-16. Following these additional consultation steps and consideration
of any evidence put forward, the AEUB will issue its new policy.

The proposed policy contemplates the shut-in of all Wabiskaw-McMurray gas
production, without benefit of public hearing, within a 5.5 million acre area
in Northeastern Alberta, the Reduced Application Area (RAA). The Trust is at
risk of having up to a net 44 MMcf/d of natural gas production affected,
representing up to approximately 50 percent of its current production,
following a proposed shut-in on August 1, 2003.

According to the proposed policy, after the shut-in has been implemented
the AEUB intends to complete a detailed review of shut-in gas production to
determine what, if any, gas should be allowed to re-commence production. GB
2003-16 also announced the immediate implementation of a reduced Wabiskaw and
McMurray gas production application area. The effect of this change is that
any outstanding gas production applications outside the RAA will be closed and
returned to the applicant. This allowed for the commencement of an additional
four mmcf/d of production net to PET in the Ells and Legend East fields in June
2003. In addition, new applications for gas production will only be required
within the RAA or where wells encounter Wabiskaw-McMurray gas pools which
overlap the RAA.

At this time the ultimate policy resulting from GB 2003-16 is uncertain.
We cannot 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.




ITEM 9. THE OFFER AND LISTING




A.     OFFER AND LISTING DETAILS



| | 1. |  | Not applicable.                                  
| | -- |  | -------------------------------------------------
|
| | 2. |  | Not applicable.                                  
|
| | 3. |  | Not applicable.                                  
|
| | 4. |  | Price Range and Trading Volume of the Trust Units

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There is no trading market for the Trust Units in the United States. The
outstanding Trust Units are traded on the TSX under the trading symbol
PMT.UN. The following table sets forth the price range (expressed in
Canadian dollars) and trading volume of the Trust Units as reported by the TSX
for the periods indicated.

|                       |  |              |       |     |  |        |       |  |  |  |           | 
|---------------------- |  | ------------ | ----- | --- |  | ------ | ----- |  |  |  | --------- | 
|Period                 |  | High         |       | Low |  | Volume
|                       |  |              |       |     |  |       
|                       |  | (Canadian $) |       |     |  |       
|2003                   |  |              |       |     |  |        |       |  |  |  |           | 
|February 7 to 28(1)    |  |              | 32.51 | (2) |  |        | 11.75 |  |  |  | 2,408,997 | 
|March                  |  |              | 15.45 |     |  |        | 12.70 |  |  |  | 4,291,899 | 
|April                  |  |              | 13.40 |     |  |        | 12.60 |  |  |  | 3,074,616 | 
|May                    |  |              | 14.46 |     |  |        | 12.69 |  |  |  | 4,682,153 | 
|June (through June 25) |  |              | 13.99 |     |  |        | 8.46  |  |  |  | 8,449,900 | 

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
|   
|   



| | 5. |  | Not applicable.
| | -- |  | ---------------
|
| | 6. |  | Not applicable.
|
| | 7. |  | Not applicable.




B.     PLAN OF DISTRIBUTION

Not applicable.




C.     MARKETS

The issued and outstanding Trust Units are listed on the Toronto Stock
Exchange under the symbol PMT.UN.




D.     SELLING SHAREHOLDERS

Not applicable.




E.     DILUTION

Not applicable.




F.     EXPENSE OF THE ISSUE

Not applicable.




ITEM 10. ADDITIONAL INFORMATION




A.     SHARE
CAPITAL - TREASURY SHARES

Not applicable.

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B.     MEMORANDUM AND ARTICLES OF ASSOCIATION

The constitutive documents of PET are summarized under the captions The
PET Trust Indenture and Description of the Trust Units and Special Voting
Rights in the Rule 424(b)(3) Prospectus dated February 3, 2003 constituting a
part of the Registration Statement on Form F-1 of PET (Registration No.
333-98233) filed as Exhibit 12.2 to this report, which summary is incorporated
herein by reference.




C.     MATERIAL CONTRACTS

The following are the material contracts to which the registrant or one of its
subsidiaries is currently a party or which were entered into by any such entity
within the two years preceding the date of this report:



|1. |  | First Amended and Restated Trust Indenture for Paramount Energy Trust
dated effective August 1, 2002 among BMO Nesbitt Burns Inc., Computershare
Trust Company of Canada and the Administrator (the summary of which
appearing under the caption the PET Trust Indenture in the Rule
424(b)(3) Prospectus dated February 3, 2003 constituting a part of the
Registration Statement on Form F-1 of PET (Registration No. 333-98233)
filed as Exhibit 12.2 to this report is hereby incorporated herein by
reference);                                
|-- |  | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|  
|2. |  | First Amended and Restated Trust Indenture for Paramount Operating Trust
dated effective August 1, 2002 between CIBC World Markets Inc. and the
Administrator (the summary of which appearing under the caption The POT
Trust Indenture in the Rule 424(b)(3) Prospectus dated February 3, 2003
constituting a part of the Registration Statement on Form F-1 of PET
(Registration No. 333-98233) filed as Exhibit 12.2 to this report is
hereby incorporated herein by reference);                                                                 
|  
|3. |  | Royalty Agreement dated effective July 1, 2002 between Computershare
Trust Company of Canada, as trustee of PET, and the Administrator, as
trustee of POT (the summary of which appearing under the caption The POT
Royalty Agreement in the Rule 424(b)(3) Prospectus dated February 3, 2003
constituting a part of the Registration Statement on Form F-1 of PET
(Registration No. 333-98233) filed as Exhibit 12.2 to this report is
hereby incorporated herein by reference);                                                                   
|  
|4. |  | Dealer Manager Agreement dated August 8, 2002, as amended on December 13,
2002, among PET, POT, the Administrator, PRL, and BMO Nesbitt Burns Inc.,
CIBC World Markets Inc. and FirstEnergy Capital Corp. (the summary of
which appearing in the second paragraph under the caption Plan of
Distribution in the Rule 424(b)(3) Prospectus dated February 3, 2003
constituting a part of the Registration Statement on Form F-1 of PET
(Registration No. 333-98233) filed as Exhibit 12.2 to this report is
hereby incorporated herein by reference);

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|5.  |  | Initial Assets Purchase Agreement dated effective July 1,2002 between PRL
and POT (the summary of which appearing in paragraph (a) under the caption
Formation of Trust Structure and Structuring Transactions  Trust
Structuring in the Rule 424(b)(3) Prospectus dated February 3, 2003
constituting a part of the Registration Statement on Form F-1 of PET
(Registration No. 333-98233) filed as Exhibit 12.2 to this report is
hereby incorporated herein by reference);                                                                                                                                                                                                           
|--- |  | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|   
|6.  |  | Take-up Agreement dated effective July 1,2002 between PRL and POT (the
summary of which appearing in paragraph (b) under the caption Formation
of Trust Structure and Structuring Transactions  Trust Structuring in
the Rule 424(b)(3) Prospectus dated February 3, 2003 constituting a part
of the Registration Statement on Form F-1 of PET (Registration No.
333-98233) filed as Exhibit 12.2 to this report is hereby incorporated
herein by reference);                                                                                                                                                                                                                           
|   
|7.  |  | Funding Agreement dated effective July 1, 2002 among PET, POT and PRL
(the summary of which appearing in paragraph (c) under the caption
Formation of Trust Structure and Structuring Transactions  Trust
Structuring in the Rule 424(b)(3) Prospectus dated February 3, 2003
constituting a part of the Registration Statement on Form F-1 of PET
(Registration No. 333-98233) filed as Exhibit 12.2 to this report is
hereby incorporated herein by reference);                                                                                                                                                                                                                       
|   
|8.  |  | Guarantee dated February 3, 2003 issued by POT to PRL (the summary of
which appearing in the last paragraph under the caption Bank Financing
and Guarantees in the Rule 424(b)(3) Prospectus dated February 3, 2003
constituting a part of the Registration Statement on Form F-1 of PET
(Registration No. 333-98233) filed as Exhibit 12.2 to this report is
hereby incorporated herein by reference);                                                                                                                                                                                                                                                                                  
|   
|9.  |  | Guarantee dated February 3, 2003 issued by PET and POT to certain banks
(the summary of which appearing in the last paragraph under the caption
Bank Financing and Guarantees in the Rule 424(b)(3) Prospectus dated
February 3, 2003 constituting a part of the Registration Statement on Form
F-1 of PET (Registration No. 333-98233) filed as Exhibit 12.2 to this
report is hereby incorporated herein by reference);                                                                                                                                                                                                                                                                
|   
|10. |  | Commitment Letter dated effective August 15, 2002, as amended on
September 30, 2002, November 29, 2002 and as of January 29, 2003, from
Bank of Montreal, Canadian Imperial Bank of Commerce and Bank of Nova
Scotia to Computershare Trust Company of Canada, as trustee of PET, and
the Administrator, as trustee of POT (the summary of which appearing in
the first and second paragraphs under the caption Bank Financing and
Guarantees in the Rule 424(b)(3) Prospectus dated February 3, 2003
constituting a part of the Registration Statement on Form F-1 of PET
(Registration No. 333-98233) filed as Exhibit 12.2 to this report is
hereby incorporated herein by reference);
|   
|11. |  | Administrative Services Agreement dated effective August 1, 2002 between
the Administrator, as trustee of POT, and PRL (the summary of which
appearing                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                     

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|    |  | under the caption The Administrator  Employees in the Rule
424(b)(3) Prospectus dated February 3, 2003 constituting a part of the
Registration Statement on Form F-1 of PET (Registration No. 333-98233)
filed as Exhibit 12.2 to this report is hereby incorporated herein by
reference).
|--- |  | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|   
|12. |  | Asset Sale Agreement dated March 19, 2003 (under which POT acquired from
PRL a 100% working interest in the Ells natural gas property in Northeast
Alberta for approximately $19.9 million).                                                                                                 




D.     EXCHANGE CONTROLS

Canada has a free market for foreign exchange, and the Canadian and U.S.
governments allow the Canadian Dollar to float freely against the U.S. Dollar.
There can be no assurance that these governments will maintain their current
foreign exchange policies. See Item 3.D, Risk Factors, and the exchange rate
table at the beginning of this report.




E.     TAXATION

MATERIAL CANADIAN FEDERAL INCOME TAX CONSIDERATIONS

This summary is of a general nature only and is not intended to be, nor
should it be construed to be, legal, business or tax advice to any particular
holder. Counsel recommends that holders consult their own tax advisors
regarding the income tax considerations applicable to them in their particular
circumstances.

Non-Residents of Canada

The following portion of this summary generally is applicable to a
Unitholder who at all relevant times, for the purposes of the Tax Act, is
neither resident nor deemed to be resident in Canada, and does not use or hold,
and is not deemed to use or hold, Trust Units in connection with carrying on a
business in Canada. Special rules, which are not discussed herein, may apply
to a non-resident that is an insurer carrying on business in Canada and
elsewhere.

Distributions by PET

A distribution of income of PET to a Unitholder not resident in Canada
will be subject to Canadian withholding tax at a rate of 25%, unless such rate
is reduced under the provisions of an income tax convention between Canada and
the Unitholders jurisdiction of residence. For example, Unitholders who are
residents of the United States for the purposes of the Canada   U.S. Income
Tax Convention (the Convention) will be entitled to have the rate of
withholding reduced to 15% of the amount of any income distribution. Certain
corporations resident in the United States but not subject to taxation therein
may not be considered by the CCRA to be residents of the United States for the
purposes of the Convention.

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Disposition of Trust Units

A non-resident Unitholder will not be subject to tax under the Tax Act in
respect of any capital gain realized on a disposition of Trust Units (whether
on redemption, by virtue of capital distributions in excess of the Unitholders
adjusted cost base or otherwise) unless the property disposed of constitutes
taxable Canadian property of the non-resident Unitholder and the non-resident
Unitholder is not entitled to relief under an applicable income tax convention.
Trust Units of a Unitholder generally will not be considered to be taxable
Canadian property unless: (a) the Unitholder holds or uses, or is deemed to
hold or use the Units in the course of carrying on business in Canada; (b) the
Trust Units are designated insurance property of the holder for purposes
of the Tax Act; (c) at any time during the 60 month period immediately
preceding the disposition of Trust Units by such Unitholder, not less than 25%
of the issued Trust Units were owned by the Unitholder, by persons with whom
the Unitholder did not deal at arms length or by any combination thereof; or
(d) at the time of disposition, PET is not a mutual fund trust as defined in
the Tax Act.

For the purposes of computing Canadian federal income tax, holders who are
not resident in Canada generally will compute the adjusted cost base of their
Trust Units under the same rules as apply to residents of Canada as described
above.

MATERIAL UNITED STATES FEDERAL INCOME TAX CONSIDERATIONS

The following is a summary of certain material U.S. federal income tax
consequences that generally will apply to the ownership and disposition of
Trust Units by a U.S. Holder. This description is based on the United States
Internal Revenue Code of 1986, as amended (the Code), Treasury regulations
promulgated thereunder, and judicial and administrative interpretations
thereof, and the U.S.-Canada Tax Treaty, all as in effect on the date hereof
and all of which are subject to change either prospectively or retroactively.
The tax treatment of a U.S. Holder may vary depending upon his or her
particular situation. Certain owners (including persons who acquired Trust
Units pursuant to an exercise of right under the Unit Incentive Plan or
otherwise as compensation for the performance of services, banks, insurance
companies, tax-exempt organizations, financial institutions, persons whose
functional currency is not the United States dollar, persons subject to the
alternative minimum tax and broker-dealers) may be subject to special rules not
discussed below. The following summary is limited to U.S. Holders who hold
Trust Units as capital assets within the meaning of the Code at all relevant
times. The discussion below does not address the effect of U.S. federal estate
and gift tax or any state, local or foreign tax law on an owner of Trust Units.

Investors are urged to consult with their own tax advisors as to the
particular tax consequences to them of holding Trust Units, including the
applicability and effect of any state, local or foreign laws, and the effect of
possible changes in applicable tax laws.

For purposes of this summary, a U.S. Holder is a beneficial owner that,
for U.S. federal income tax purposes, is:

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| |  |  | an individual who is a citizen or, for U.S. federal income tax
purposes, a resident of the United States;                                                                                                                                                                                                               
| | - |  | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|
| |  |  | a partnership or corporation created or organized in or under the
laws of the United States or any political subdivision thereof;                                                                                                                                                                                       
|
| |  |  | an estate whose income is subject to U.S. federal income tax
regardless of its source; or                                                                                                                                                                                                                               
|
| |  |  | a trust if: (1) such trust validly elects to be treated as a United
States person, or (2) (a) a court within the United States is able to
exercise primary supervision over
administration of the trust, and (b) one or more United States persons
have the authority to control all substantial decisions of the trust.

Tax Consequences of Holding Trust Units

Classification of PET

PET has elected to be treated as an association taxable as a corporation
for U.S. federal tax purposes. As a corporation for U.S. federal tax purposes,
PET will be subject to U.S. corporate tax on its net income attributable to
earnings that are effectively connected with a U.S. trade or business. If PET
is subject to U.S. corporate tax, it will be required to file a U.S. federal
corporate income tax return. It is not anticipated, however, that PET will be
engaged in a U.S. trade or business.

Taxation of Cash Distributions from PET

Subject to the passive foreign investment company rules discussed below, a
U.S. Holder of Trust Units will be required to include in gross income as
ordinary income the gross amount of any distribution, including any Canadian
taxes withheld from the amount paid, to the extent the distribution is paid out
of PETs current or accumulated earnings and profits as determined for U.S.
federal income tax purposes (see -New Tax Law Applicable to Dividends and
Long-Term Capital Gain,below). Such dividends will not be eligible for the
dividends-received deduction otherwise allowed to U.S. corporations in respect
of dividends received from other U.S. corporations.

To the extent that the amount of any distribution exceeds PETs current
and accumulated earnings and profits, it will be treated first as a tax-free
return of the U.S. Holders tax basis in his or her Trust Units, to the extent
thereof, and then as capital gain.

Amounts considered to be dividends which are paid in Canadian dollars will
be included in the U.S. Holders gross income in a U.S. dollar amount
calculated by reference to the exchange rate in effect on the day such
dividends are received. A U.S. Holder who receives a dividend paid in Canadian
dollars and converts Canadian dollars into U.S. dollars at an exchange rate
other than the rate in effect on the date of receipt of the dividend may have a
foreign currency exchange gain or loss that would be treated as ordinary income
or loss. We recommend that U.S. Holders consult their own tax advisors

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concerning the U.S. tax consequences of acquiring, holding and disposing of
Canadian dollars.

Any Canadian withholding tax imposed on such dividends will be a foreign
income tax eligible for credit against a U.S. Holders U.S. federal income tax
liability, subject to certain complex limitations set out in the Code (or,
alternatively, for deduction against income in determining such tax liability).
The limitations set out in the Code include computational rules under which
foreign tax credits allowable with respect to specific classes of income cannot
exceed the U.S. federal income taxes otherwise payable with respect to each
such class of income (see -New Tax Law Applicable to Dividends and Long-Term
Capital Gain,below). Dividends generally will be treated as foreign-source
passive income or financial services income for United States foreign tax
credit purposes. Foreign income taxes exceeding the credit limitation for the
year of payment or accrual
may be carried back for two taxable years and forward for five taxable
years in order to reduce U.S. federal income taxes, subject to the credit
limitation applicable in each of such years. A U.S. Holder will be denied a
foreign tax credit with respect to Canadian income tax withheld from dividends
received on the Trust Units to the extent such U.S. Holder has not held the
Trust Units for at least 16 days of the 30-day period beginning on the date
which is 15 days before the ex-dividend date or to the extent such U.S. Holder
is under an obligation to make related payments with respect to substantially
similar or related property. Any days during which a U.S. Holder has
substantially diminished its risk of loss on the Trust Units are not counted
toward meeting the 16-day holding period required by the statute. The rules
relating to the determination of the foreign tax credit are complex, and
investors should consult with their personal tax advisors to determine whether
and to what extent they would be entitled to this credit.

Sale or Redemption of Trust Units

Any sale or redemption (except as described below) of Trust Units
generally will result in the recognition of gain or loss by a U.S. Holder for
U.S. federal income tax purposes in an amount equal to the difference between
the amount realized on the sale or redemption and the U.S. Holders adjusted
tax basis in the Trust Units. Subject to the passive foreign investment company
rules discussed below, such gain or loss generally will be capital gain or loss
and will be long-term capital gain or loss if the Trust Units were held for
more than one year at the time of the sale or redemption. For purposes of the
foreign tax credit, any gain that is recognized on the sale or redemption of
the Trust Units generally will be U.S. source income, and any losses recognized
generally will be applied to reduce U.S. source income. Deduction of capital
losses is subject to certain limitations under the Code.

In the case of a cash basis U.S. Holder who receives Canadian dollars in
connection with the sale or redemption of Trust Units, the amount realized will
be based on the U.S. dollar value of the Canadian dollars received with respect
to the Trust Units as determined on the settlement date, in the case of a sale,
or on the date on which the redemption price is paid by PET, in the case of a
redemption. A U.S. Holder who receives payment in Canadian dollars and converts
Canadian dollars into United States dollars at a conversion rate other than the
rate in effect on the settlement date, or the date on which

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the redemption
price is paid by PET, as the case may be, may have a foreign currency exchange
gain or loss that would be treated as ordinary income or loss.

An accrual basis U.S. Holder who receives Canadian dollars in connection
with the sale or redemption of Trust Units may elect the same treatment
required of cash basis taxpayers with respect to a sale or redemption of Trust
Units, provided that the election is applied consistently from year to year.
Such election may not be changed without the consent of the Internal Revenue
Service. In the event that an accrual basis U.S. Holder does not elect to be
treated as a cash basis taxpayer (pursuant to the Treasury regulations
applicable to foreign currency transactions), such U.S. Holder may have a
foreign currency gain or loss for U.S. federal income tax purposes because of
differences in the U.S. dollar value of the currency received on the trade date
and the settlement date, or on the date on which notice of redemption is given
to PET and the date on which the redemption price is paid by PET, in the case
of a redemption. Any such currency gain or
loss would be treated as ordinary income or loss and would be in addition to
gain or loss, if any, recognized by such U.S. Holder on the sale or disposition
of such Trust Units.

In certain circumstances, amounts received upon redemption of Trust Units
may be treated as a dividend, rather than as a payment in exchange for the
Trust Units which results in recognition of capital gain or loss, as described
above. In these circumstances, the redemption payment would be treated as
ordinary dividend income to the extent that such payment is made out of PETs
current or accumulated earnings and profits, as calculated for United States
federal income tax purposes. The determination of whether a redemption will be
treated as a dividend rather than as payment in exchange for the Trust Units
will depend upon whether and to what extent the redemption reduces the U.S.
Holders percentage stock ownership interest in PET. A redemption will be
treated as an exchange of stock that produces a capital gain or loss if the
redemption either (1) completely terminates the U.S. Holders interest in PET
under section 302(b)(3) of the Code, (2) is substantially disproportionate
with respect to the U.S. Holder under section 302(b)(2) of the Code, or (3) is
not essentially equivalent to a dividend under section 302(b)(1) of the Code.

A redemption will completely terminate a U.S. Holders interest in PET if,
as a result of the redemption, such holder no longer owns any Trust Units,
directly or constructively after application of the attribution rules of
sections 302(c) and 318 of the Code. A redemption generally will be
substantially disproportionate with respect to a U.S. Holder if (1) the ratio
of the Trust Units owned by such holder (including Trust Units attributed to
the holder under sections 302(c) and 318 of the Code) immediately after the
redemption to all the Trust Units of PET is less than 80% of the same ratio for
the Trust Units owned by the holder immediately before the redemption, and (2)
the holder owns less than 50% of the combined voting power of the Trust Units
immediately after the redemption. Whether a redemption is not essentially
equivalent to a dividend with respect to a U.S. Holder will depend upon the
holders particular circumstances. The Internal Revenue Service has ruled that
a redemption of a minority shareholder in a publicly held corporation whose
relative stock interest is minimal and who exercises no control with respect to
corporate affairs is not essentially equivalent to a dividend if such
shareholder has any reduction in his percentage stock ownership. In determining

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whether any of the foregoing tests have been satisfied, the U.S. Holder is
deemed, under the constructive ownership rules of sections 302(c) and 318 of
the Code, to own any Trust Units owned by certain related persons and entities
and any Trust Units which the holder or certain related persons and entities
have an option to acquire. However, because of the complexities in applying the
foregoing rules, we recommend that a U.S. Holder consult with his or her own
tax advisor to determine whether in the holders own particular case a
redemption of Trust Units will be treated as a dividend or as a payment in
exchange for the Trust Units.

New Tax Law Applicable to Dividends and Long-Term Capital Gain

Under recently enacted tax legislation, dividends received by individual
U.S. Holders from certain foreign corporations, and long-term capital gain
realized by individual U.S. Holders, generally are subject to a reduced maximum
tax rate of 15 percent through December 31, 2008. Dividends received with
respect to Trust Units should qualify for the 15 percent rate. The reduced
rate on capital gains applies to sales
and exchanges on or after May 6, 2003 and the reduced rates on dividend
income to dividends received after December 31, 2002. The rate reduction does
not apply to dividends received in respect of certain short-term or hedged
positions in the common stock or in certain other situations. The legislation
contains special rules for computing the foreign tax credit limitation of a
taxpayer who receives dividends subject to the rate reduction. U.S. Holders
should consult their own tax advisors regarding the implications of these rules
in light of their particular circumstances.

Passive Foreign Investment Company

For U.S. federal income tax purposes, PET will be considered a passive
foreign investment company (PFIC) for any taxable year in which either (1)
75% or more of its gross income is passive income, or (ii) at least 50% of the
average value of all of its assets for the taxable year produce or are held for
the production of passive income. For this purpose, passive income generally
includes dividends, interest, royalties, rents, annuities and the excess of
gains over losses from the disposition of assets which produce passive income.
Based on PETs current and projected income, assets and activities, and
disregarding the separate existence of POT, PETs management believes PET would
not presently be treated as a PFIC. PETs status in future years will depend on
its assets and activities (and those of POT) in those years. PETs management
has no reason to believe that its assets or activities (and those of POT) will
change in a manner that would cause it to be classified as a PFIC, but there
can be no assurance that PET will not be considered a PFIC for any taxable
year.

If PET is a PFIC for any taxable year, then, unless a U.S. Holder is
eligible to elect and does elect to treat his or her investment in the Trust
Units as an investment in a qualified electing fund (a QEF election) or to
mark-to-market his or her Trust Units, as described below,



| |  |  | such U.S. Holder would be required to allocate income recognized
upon receiving certain dividends, or gain recognized upon the sale or
redemption of Trust Units,
| | - |  | -----------------------------------------------------------------------------------------------------------------------------------------------------------------

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| |   |  | ratably over the holders entire holding period for such Trust Units,                                                                                                                                                                                                                                                                                        
| | - |  | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|
| |  |  | the amount allocated to each year during which PET is considered a
PFIC other than the year of the dividend payment, or sale or
redemption, would be subject to tax at the highest individual or
corporate tax rate, as the case may be, and an interest charge would be
imposed with respect to the resulting tax liability allocated to each
such year, and
|
| |  |  | gain recognized upon the sale or redemption of Trust Units would be
taxable as ordinary income.                                                                                                                                                                                                                                                              

If a U.S. Holder makes a timely QEF election in respect of its Trust
Units, such U.S. Holder would not be subject to the rules described above.
Instead, such U.S. Holder would be required to include in his or her income for
each taxable year his or her pro rata share of PETs ordinary earnings as
ordinary income and his or her pro rata share of PETs net capital gain as
long-term capital gain, whether or not such amounts are actually distributed.
However, U.S. Holders would not be eligible to make a QEF election unless PET
complied with certain applicable information reporting requirements, and PET
has
not determined whether it would comply with the accounting, record keeping
and reporting requirements necessary for U.S. Holders to make QEF elections
should it become a PFIC.

Alternatively, assuming the Trust Units qualify as marketable stock
within the meaning of section 1296(e) of the Code, if a U.S. Holder elects to
mark-to-market his or her Trust Units, such U.S. Holder generally would
include in income any excess of the fair market value of his or her Trust Units
as of the close of each tax year over his or her adjusted basis in the Trust
Units. If the fair market value of the Trust Units had depreciated below the
U.S. Holders adjusted basis as of the close of the tax year, the U.S. Holder
generally could deduct the excess of the adjusted basis of the Trust Units over
its fair market value at that time. However, such deductions generally would be
limited to the mark-to-market gains, if any, that the U.S. Holder included in
income with respect to such Trust Units in prior years. Income recognized and
deductions allowed under the mark-to-market provisions, as well as any gain
or loss on the disposition of Trust Units with respect to which the
mark-to-market election is made, would be treated as ordinary income or loss.

If PET is a PFIC for any taxable year, U.S. Holders would be required to
file an annual return on IRS Form 8621.

U.S. Taxation of U.S. Tax-Exempt Unitholders

In the case of Trust Units held by any U.S. tax-exempt organization (U.S.
TEO Unitholder), including an employee benefit plan which is exempt from U.S.
federal income tax under Sections 401(a) and 501(a) of the Code, the U.S. TEO
Unitholder generally would not be subject to U.S. federal income tax on income
realized from its holding of Trust Units, except to the extent such U.S. TEO
Unitholders Trust Units constitute debt-financed property within the meaning
of section 514(b) of the Code. A

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U.S. TEO Unitholder whose Trust Units
constitute debt-financed property will to that extent be subject to U.S.
federal income taxation under rules summarized above. We recommend each U.S.
TEO Unitholder consider with its tax advisor the possible application of these
rules.

U.S. Information Reporting and Backup Withholding Tax

United States backup withholding tax and information reporting
requirements generally would apply to certain distributions on, and to payments
of proceeds from the sale or redemption of, Trust Units made within the United
States to a holder of Trust Units, other than distributions or payments to an
exempt recipient, including a corporation, a payee that is not a United States
person that provides an appropriate certification, and certain other persons. A
payor will be required to withhold backup withholding tax from any
distributions on, or payment of the proceeds from the sale or redemption of,
Trust Units within the United States to a holder other than an exempt
recipient, if such holder fails to furnish its correct taxpayer identification
number or otherwise fails to comply with, or establish an exemption from, such
backup withholding tax requirements. The backup withholding tax rate is
currently 28%.

Backup withholding tax is not an additional tax. Amounts withheld under
the backup withholding tax rules may be credited against a U.S. Holders U.S.
federal income tax liability, and a U.S. Holder may obtain a refund of any
excess amounts withheld under the backup withholding tax rules by filing the
appropriate claim for refund with the Internal Revenue Service.

Any U.S. holder who holds or acquires 10% or more in vote or value of the
Trust Units will be subject to certain additional United States information
reporting requirements.




F.     DIVIDEND AND PAYING AGENTS

Not applicable.




G.     STATEMENT BY EXPERTS

Not applicable.




H.     DOCUMENTS ON DISPLAY

Not applicable.




I.     SUBSIDIARY INFORMATION

Not applicable.

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ITEM 11. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISKS

PET currently has no material future contracts to buy, sell, exchange or
transport natural gas from its assets. PET currently sells approximately 56%
of its gas production at AECO market prices. An additional 40% is directed to
the Progas and PanAlberta aggregator pools. PET currently has one financial
natural gas hedge in place; a costless collar for 15,000 GJ/day for the period
from July through September 2003 with a floor of $7.00 per GJ and a ceiling of
$7.37 per GJ. PET currently has no other financial hedges or physical fixed
price sales contracts in place for commodity, currency or interest rates. We
may use such derivative instruments for hedging purposes in the future to limit
the risks of commodity price, foreign currency and/or interest rate
fluctuations.

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

Governmental Regulation Risk

We operate in a highly regulated industry and it is possible any changes
in such regulation or adverse regulatory decisions could affect our production
which could reduce our distributions. See the discussion under the caption
Government Regulation in Item 5.A of this report.

Weather Risk

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

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

Foreign Exchange Risk

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

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Interest Rate Risk

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

Sensitivities

The table appearing under Item 5.A under the caption Sensitivities is
incorporated herein by reference.




ITEM 12. DESCRIPTION OF SECURITIES OTHER THAN EQUITY SECURITIES

Not applicable.




PART II




ITEM 13. DEFAULTS, DIVIDEND ARREARAGES AND DELINQUENCIES

Not applicable.




ITEM 14. MATERIAL MODIFICATIONS TO THE RIGHTS OF SECURITY HOLDERS AND USE
OF PROCEEDS



| | A. |  | Not applicable.
| | -- |  | ---------------
|
| | B. |  | Not applicable.
|
| | C. |  | Not applicable.
|
| | D. |  | Not applicable.
|
| | E. |  | Use of Proceeds

On March 11, 2003, the formation and structuring of PET, as described in
PETs Canadian prospectus dated January 29, 2003 and U.S. prospectus dated
February 3, 2003, was completed. The final transactions involved the closing of
the rights offering and the closing of the acquisition of certain assets from
PRL by POT, PETs operating subsidiary.

On March 11, 2003, PET closed its previously announced rights offering. A
total of 29,728,782 Trust Units were issued pursuant to the rights offering for
total gross proceeds to PET of $150.1 million. There are currently 44,638,376
Trust Units of PET outstanding. Also on March 11, 2003, POT and PRL closed the
acquisition by POT of natural gas assets in northeast Alberta for a purchase
price of $220 million. These assets consist of PRLs natural gas assets in the
Bohn Lake, Chard, Chard Southwest, Clyde,

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Cold Lake, Cold Lake Sonoma, Corner,
Hoole, Kettle River, Legend East, Leismer/Leismer South, Liege East, Liege
North, Liege South, Pony, Quigley, Saleski, Surmont, Teepee Creek, Thornbury
and Winefred areas. These assets had a combined average production of 74 mmcf
per day of natural gas during the six months ended December 31 2002. The
revenues and expenses associated with these assets accrued to POT for POTs
account as of July 1, 2002. The assets acquired by POT are in addition to the
natural gas assets in the Legend area that POT acquired from PRL in early
February of 2003. The combined production of natural gas from the assets in
the Legend area and the assets acquired by PET on March 11, 2003 averaged 94
mmcf per day during the six months ended December 31, 2002.

In connection with the above acquisition, PET obtained a secured demand
revolving credit facility with a syndicate of major Canadian banks in the
amount of $100 million. PET drew down the amount of $70 million on this
facility to complete the acquisition and provide working capital.

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

|               |  |                |  |      |       |                        |  | 
|-------------- |  | -------------- |  | ---- | ----- | ---------------------- |  | 
|               |  |                |  |      |       | Distribution per Trust
|Record Date    |  | Payment Date   |  | Unit
|               |  |                |  |     
|March 31, 2003 |  | April 15, 2003 |  | $    | 0.830 |                       
|April 30, 2003 |  | May 15, 2003   |  | $    | 0.277 |                       
|May 31, 2003   |  | June 16, 2003  |  | $    | 0.277 |                       
|June 30, 2003  |  | July 15, 2003  |  | $    | 0.250 |                       

On May 30, 2003, PET closed the issuance of 5,000,000 Trust Units on a bought
deal
basis to a syndicate of underwriters at $12.65 per Trust Unit for net proceeds
of $60,087,500. Proceeds of the financing were used to repay a portion of PETs
indebtedness to its bankers.




ITEM 15. CONTROLS AND PROCEDURES

(a)     Within the 90-day period prior to the filing of this report, an
evaluation was conducted under the supervision of and with the participation of
the Registrants management, including the Chief Executive Officer and Chief
Financial Officer, of the effectiveness of the Registrants disclosure controls
and procedures (as defined in Rule 13a-14(c) under the Securities Exchange Act
of 1934 (the Exchange Act)). Based on that evaluation, the Chief Executive
Officer and Chief Financial Officer concluded that the design and operation of
these disclosure controls and procedures were effective to ensure that material
information required to be disclosed by the Registrant in the reports that it
files or submits under the Exchange Act is recorded, processed, summarized and
reported within the time periods specified in the rules and forms of the
Securities and Exchange Commission.

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(b)     No significant changes were made in the Registrants internal controls
or in other factors that could significantly affect these controls subsequent
to the date of their evaluation, including any corrective actions with regard
to significant deficiencies and material weaknesses.

It should be noted that any system of controls, however well designed and
operated, can provide only reasonable, and not absolute, assurance that the
objectives of the system are met. In addition, the design of any control system
is based in part upon certain assumptions about the likelihood of future
events. Because of these and other inherent limitations of control systems,
there can be no assurance that any design will succeed in achieving its stated
goals under all potential future conditions, regardless of how remote.




ITEM 16.   [RESERVED]




PART III




ITEM 17.   FINANCIAL STATEMENTS

The Company has elected to furnish financial statements and related
information specified in Item 18.




ITEM 18.   FINANCIAL STATEMENTS

The financial statements required by Item 18 are annexed to this report as
Exhibits 12.3, 12.4 and 12.5.




ITEM 19.   EXHIBITS

Index to Exhibits

|        |  |                                                                                                                                                                                                                                                                                                                                   
|------- |  | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|Exhibit |  | Description                                                                                                                                                                                                                                                                                                                       
|        |  |                                                                                                                                                                                                                                                                                                                                   
|1.1     |  | First Amended and Restated Trust Indenture for Paramount
Energy Trust dated effective August 1, 2002 between ComputerShare
Trust Company of Canada and Paramount Energy Operating Corp. (filed
as Exhibit 3.1 to the Registration Statement of PET on Form F-1
(Registration No. 333-98233) and incorporated herein by
reference).
|        |  |                                                                                                                                                                                                                                                                                                                                   
|1.2     |  | First Amended and Restated Trust Indenture for Paramount
Operating Trust dated effective August 1, 2002 between CIBC World
Markets Inc. and the Administrator (filed as Exhibit 3.2 to the
Registration Statement of PET on Form F-1 (Registration No.
333-98233) and incorporated herein by reference).                          

73



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| |  |  |     |  |  |                                                                                                                                                                                                                                                                                                                                                                                      
| |  |  | --- |  |  | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
| |  |  | 4.1 |  |  | Royalty Agreement dated effective July 1, 2002 between
Computershare Trust Company of Canada, as trustee of PET, and the
Administrator, as trustee of POT (filed as Exhibit 10.1 to the
Registration Statement of PET on Form F-1 (Registration No.
333-98233) and incorporated herein by reference).                                                                                
| |  |  |     |  |  |                                                                                                                                                                                                                                                                                                                                                                                      
| |  |  | 4.2 |  |  | Dealer Manager Agreement dated August 8, 2002 among PET, POT,
the Administrator, PRL, and BMO Nesbitt Burns Inc., CIBC World
Markets Inc. and FirstEnergy Capital Corp. (filed as Exhibit 1.1 to
the Registration Statement of PET on Form F-1 (Registration No.
333-98233) and incorporated herein by reference).                                                                   
| |  |  |     |  |  |                                                                                                                                                                                                                                                                                                                                                                                      
| |  |  | 4.3 |  |  | Dealer Manager Amending Agreement dated December 13, 2002
among PET, POT, the Administrator, PRL, and BMO Nesbitt Burns Inc.,
CIBC World Markets Inc. and FirstEnergy Capital Corp. (filed as
Exhibit 1.1(a) to the Registration Statement of PET on Form F-1
(Registration No. 333-98233) and incorporated herein by
reference).                                                    
| |  |  |     |  |  |                                                                                                                                                                                                                                                                                                                                                                                      
| |  |  | 4.4 |  |  | Initial Assets Purchase Agreement dated effective July 1,2002
between PRL and POT (filed as Exhibit 2.1 to the Registration
Statement of PET on Form F-1 (Registration No. 333-98233) and
incorporated herein by reference).                                                                                                                                                         
| |  |  |     |  |  |                                                                                                                                                                                                                                                                                                                                                                                      
| |  |  | 4.5 |  |  | Take-up Agreement dated effective July 1,2002 between PRL and
POT (filed as Exhibit 2.2 to the Registration Statement of PET on
Form F-1 (Registration No. 333-98233) and incorporated herein by
reference).                                                                                                                                                                         
| |  |  |     |  |  |                                                                                                                                                                                                                                                                                                                                                                                      
| |  |  | 4.6 |  |  | Funding Agreement dated effective July 1, 2002 among PET, POT
and PRL (filed as Exhibit 2.3 to the Registration Statement of PET
on Form F-1 (Registration No. 333-98233) and incorporated herein by
reference).                                                                                                                                                                     
| |  |  |     |  |  |                                                                                                                                                                                                                                                                                                                                                                                      
| |  |  | 4.7 |  |  | Guarantee dated February 3, 2003 issued by POT to PRL (filed
as Exhibit 2.7 to the Registration Statement of PET on Form F-1
(Registration No. 333-98233) and incorporated herein by
reference).                                                                                                                                                                                     
| |  |  |     |  |  |                                                                                                                                                                                                                                                                                                                                                                                      
| |  |  | 4.8 |  |  | Guarantee dated February 3, 2003 issued by PET and POT to
certain banks (filed as Exhibit 2.8 to the Registration Statement of
PET on Form F-1 (Registration No. 333-98233) and incorporated herein
by reference).                                                                                                                                                                   
| |  |  |     |  |  |                                                                                                                                                                                                                                                                                                                                                                                      
| |  |  | 4.9 |  |  | Commitment Letter dated effective August 15, 2002 from Bank
of Montreal, Canadian Imperial Bank of Commerce and Bank of Nova
Scotia to Computershare Trust Company of Canada, as trustee of PET,
and the Administrator, as trustee of POT (filed as Exhibit 10.5 to
the Registration Statement of PET on Form F-1 (Registration No.
333-98233) and incorporated herein by reference).

74



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|     |  |                                                                                                                                                                                                                                                                                                                                                                                                                            
|---- |  | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|4.10 |  | First Amending Agreement dated effective September 30, 2002
to the Commitment Letter from Bank of Montreal, Canadian Imperial
Bank of Commerce and Bank of Nova Scotia to Computershare Trust
Company of Canada, as trustee of PET, and the Administrator, as
trustee of POT (filed as Exhibit 10.5(a) to the Registration
Statement of PET on Form F-1 (Registration No. 333-98233) and
incorporated herein by reference).
|     |  |                                                                                                                                                                                                                                                                                                                                                                                                                            
|4.11 |  | Second Amending Agreement dated effective November 29, 2002
to the Commitment Letter from Bank of Montreal, Canadian Imperial
Bank of Commerce and Bank of Nova Scotia to Computershare Trust
Company of Canada, as trustee of PET, and the Administrator, as
trustee of POT (filed as Exhibit 10.5(b) to the Registration
Statement of PET on Form F-1 (Registration No. 333-98233) and
incorporated herein by reference).
|     |  |                                                                                                                                                                                                                                                                                                                                                                                                                            
|4.12 |  | Third Amending Agreement dated effective January 29, 2003 to
the Commitment Letter from Bank of Montreal, Canadian Imperial Bank
of Commerce and Bank of Nova Scotia to Computershare Trust Company
of Canada, as trustee of PET, and the Administrator, as trustee of
POT (filed as Exhibit 10.5(c) to the Registration Statement of PET
on Form F-1 (Registration No. 333-98233) and incorporated herein by
reference).  
|     |  |                                                                                                                                                                                                                                                                                                                                                                                                                            
|4.13 |  | Administrative Services Agreement dated effective August 1,
2002 between the Administrator, as trustee of POT, and PRL (filed as
Exhibit 99.1 to the Registration Statement of PET on Form F-1
(Registration No. 333-98233) and incorporated herein by
reference).                                                                                                                                                         
|     |  |                                                                                                                                                                                                                                                                                                                                                                                                                            
|4.14 |  | Asset Sale Agreement dated March 19, 2003 between POT and
PRL.                                                                                                                                                                                                                                                                                                                                                             
|     |  |                                                                                                                                                                                                                                                                                                                                                                                                                            
|4.15 |  | Unit Incentive Plan of PET (filed as Exhibit 10.2 to the
Registration Statement of PET on Form F-1 (Registration No.
333-98233) and incorporated herein by reference).                                                                                                                                                                                                                                                     
|     |  |                                                                                                                                                                                                                                                                                                                                                                                                                            
|4.16 |  | Employment Agreement between the Administrator and Susan L.
Riddle Rose (filed as Exhibit 10.6 to the Registration Statement of
PET on Form F-1 (Registration No. 333-98233) and incorporated herein
by reference).                                                                                                                                                                                                        
|     |  |                                                                                                                                                                                                                                                                                                                                                                                                                            
|4.17 |  | Employment Agreement between the Administrator and Gary
Jackson (filed as Exhibit 10.7 to the Registration Statement of PET
on Form F-1 (Registration No. 333-98233) and incorporated herein by
reference).                                                                                                                                                                                                                
|     |  |                                                                                                                                                                                                                                                                                                                                                                                                                            
|4.18 |  | Employment Agreement between the Administrator and Cameron
Sebastian (filed as Exhibit 10.8 to the Registration Statement of
PET on Form F-1 (Registration No. 333-98233) and incorporated herein
by reference).                                                                                                                                                                                                           

75



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|     |  |                                                                                                                                                                                                                                                                                                                             
|---- |  | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|4.19 |  | Employment Agreement between the Administrator and Kevin
Marjoram (filed as Exhibit 10.9 to the Registration Statement of PET
on Form F-1 (Registration No. 333-98233) and incorporated herein by
reference).                                                                                                               
|     |  |                                                                                                                                                                                                                                                                                                                             
|4.20 |  | Employment Agreement between the Administrator and Clayton
Riddell (filed as Exhibit 10.4 to the Registration Statement of PET
on Form F-1 (Registration No. 333-98233) and incorporated herein by
reference).                                                                                                              
|     |  |                                                                                                                                                                                                                                                                                                                             
|8.1  |  | List of Subsidiaries of Registrant.                                                                                                                                                                                                                                                                                         
|     |  |                                                                                                                                                                                                                                                                                                                             
|12.1 |  | Certification by Chief Executive Officer and Chief Financial
Officer Pursuant to 18 U.S.C. Section 1350, As Adopted Pursuant to
Section 906 of the Sarbanes-Oxley Act of 2002.                                                                                                                                              
|     |  |                                                                                                                                                                                                                                                                                                                             
|12.2 |  | Prospectus dated February 3, 2002 filed with Securities and
Exchange Commission pursuant to Rule 424(b)(3) constituting part of
the Registration Statement of PET on Form F-1 (Registration No.
333-98233).                                                                                                                 
|     |  |                                                                                                                                                                                                                                                                                                                             
|12.3 |  | Consolidated Balance Sheets of Paramount Energy Trust as at
March 31, 2003 and December 31, 2002, and Consolidated Statements of
Earnings and Retained Earnings and Cash Flows of Paramount Energy
Trust for the three month period ending March 31, 2003 and 2002.                                                         
|     |  |                                                                                                                                                                                                                                                                                                                             
|12.4 |  | Consolidated Balance Sheet of Paramount Energy Trust as at
December 31, 2002 and Consolidated Statement of Earnings and
Retained Earnings (Deficit) and Cash Flows for the Period from
formation on June 28, 2002 to December 31, 2002, together with
Auditors report thereon.                                             
|     |  |                                                                                                                                                                                                                                                                                                                             
|12.5 |  | Balance Sheet of the Paramount Resources Ltd. Northeast
Alberta Properties as at December 31, 2002 and 2001 and Statements
of Earnings and Changes in Investment by Paramount Resources Ltd.
and Cash Flows for each of the years in the three year period ending
December 31, 2002, together with Auditors report thereon.
|     |  |                                                                                                                                                                                                                                                                                                                             
|12.6 |  | Indemnity Agreement from the Administrator and POT in favor
of Computershare Trust Company of Canada (filed as Exhibit 99.2 to
the Registration Statement of PET on Form F-1 (Registration No.
333-98233) and incorporated herein by reference).                                                                            
|     |  |                                                                                                                                                                                                                                                                                                                             
|12.7 |  | Form of Indemnity Agreement from the Administrator in favor
of the directors and officers of the Administrator (filed as Exhibit
99.3 to the Registration Statement of PET on Form F-1 (Registration
No. 333-98233) and incorporated herein by reference).                                                                  

76



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|     |  |                                                                                                                                                                                                                                             
|---- |  | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|12.8 |  | Form of Indemnity Agreement from PET in favor of the
directors and officers of the Administrator (filed as Exhibit 99.4
to the Registration Statement of PET on Form F-1 (Registration No.
333-98233) and incorporated herein by reference).
|     |  |                                                                                                                                                                                                                                             
|12.9 |  | Form of Indemnity Agreement from POT in favor of the
directors and officers of the Administrator (filed as Exhibit 99.5
to the Registration Statement of PET on Form F-1 (Registration No.
333-98233) and incorporated herein by reference).

77



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S I G N A T U R E S

The registrant hereby certifies that it meets all of the requirements for
filing on Form 20-F and that it has duly caused and authorized the undersigned
to sign this annual report on its behalf.*

| |  |                        |  |                                                  
| |  | ---------------------- |  | -------------------------------------------------
| |  | PARAMOUNT ENERGY TRUST
| |  | By:                    |  | Paramount Energy Operating Corp.                 
| |  |                        |  | (Administrator)                                  
| |  |                        |  |                                                  
| |  |                        |  |                                                  
| |  | By:                    |  | /s/Clayton H. Riddell                            
| |  |                        |  |                                                  
| |  |                        |  | Clayton H. Riddell                               
| |  |                        |  | Chairman of the
Board and
Chief Executive Officer

Dated: June 27, 2003

*     The Registrant is a trust and the person is signing in his capacity as an
officer and director of Paramount Energy Operating Corp., the administrator of
the Registrant.

78



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##### Table of Contents



CERTIFICATIONS

I, Clayton H. Riddell, Chairman of the Board and Chief Executive Officer of
Paramount Energy Operating Corp, the Administrator of Paramount Energy Trust,
certify that:

1.     I have reviewed this annual report on Form 20-F of Paramount Energy Trust;

2.     Based on my knowledge, this annual report does not contain any untrue
statement of a material fact or omit to state a material fact necessary to make
the statements made, in light of the circumstances under which such statements
were made, not misleading with respect to the period covered by this annual
report;

3.     Based on my knowledge, the financial statements, and other financial
information included in this annual report, fairly present in all material
respects the financial condition, results of operations and cash flows of the
registrant as of, and for, the periods presented in this annual report;

4.     The registrants other certifying officers and I are responsible for
establishing and maintaining disclosure controls and procedures (as defined in
Exchange Act Rules 13a-14 and 15d-14) for the registrant and have:



| | a) |  | designed such disclosure controls and procedures to
ensure that material information relating to the registrant,
including its consolidated subsidiaries, is made known to us by
others within those entities, particularly during the period in
which this annual report is being prepared;
| | -- |  | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|
| | b) |  | evaluated the effectiveness of the registrants
disclosure controls and procedures as of a date within 90 days
prior to the filing date of this annual report (the Evaluation
Date); and                                                                                                  
|
| | c) |  | presented in this annual report our conclusions about the
effectiveness of the disclosure controls and procedures based on
our evaluation as of the Evaluation Date.                                                                                                                        

5.     The registrants other certifying officers and I have disclosed, based on
our most recent evaluation, to the registrants auditors and the audit
committee of registrants board of directors (and persons performing the
equivalent function):



| | a) |  | all significant deficiencies in the design or operation
of internal controls which could adversely affect the registrants
ability to record, process, summarize and report financial data
and have identified for the registrants auditors any material
weaknesses in internal controls; and
| | -- |  | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------





---



##### Table of Contents





| | b) |  | any fraud, whether or not material, that involves
management or other employees who have a significant role in the
registrants internal controls.
| | -- |  | --------------------------------------------------------------------------------------------------------------------------------------------------

6.     The registrants other certifying officers and I have indicated in this
annual report whether there were significant changes in internal controls or in
other factors that could significantly affect internal controls subsequent to
the date of our most recent evaluation, including any corrective actions with
regard to significant deficiencies and material weaknesses.

|                    |  |     |  |                          
|------------------- |  | --- |  | -------------------------
|Date: June 27, 2003 |  | By: |  | /s/ Clayton H. Riddell   
|                    |  |     |  |                          
|                    |  |     |  | Clayton H. Riddell       
|                    |  |     |  | Chairman of the Board and
|                    |  |     |  | Chief Executive Officer  

I, Cameron R. Sebastian, Vice-President, Finance and Chief Financial Officer of
Paramount Energy Operating Corp., certify that:

1.     I have reviewed this annual report on Form 20-F of Paramount Energy Trust;

2.     Based on my knowledge, this annual report does not contain any untrue
statement of a material fact or omit to state a material fact necessary to make
the statements made, in light of the circumstances under which such statements
were made, not misleading with respect to the period covered by this annual
report;

3.     Based on my knowledge, the financial statements, and other financial
information included in this annual report, fairly present in all material
respects the financial condition, results of operations and cash flows of the
registrant as of, and for, the periods presented in this annual report;

4.     The registrants other certifying officers and I are responsible for
establishing and maintaining disclosure controls and procedures (as defined in
Exchange Act Rules 13a-14 and 15d-14) for the registrant and have:



| | a) |  | designed such disclosure controls and procedures to
ensure that material information relating to the registrant,
including its consolidated subsidiaries, is made known to us by
others within those entities, particularly during the period in
which this annual report is being prepared;
| | -- |  | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|
| | b) |  | evaluated the effectiveness of the registrants
disclosure controls and procedures as of a date within 90 days
prior to the filing date of this annual report (the Evaluation
Date); and                                                                                                  





---



##### Table of Contents





| | c) |  | presented in this annual report our conclusions about the
effectiveness of the disclosure controls and procedures based on
our evaluation as of the Evaluation Date.
| | -- |  | --------------------------------------------------------------------------------------------------------------------------------------------------------------------

5.     The registrants other certifying officers and I have disclosed, based on
our most recent evaluation, to the registrants auditors and the audit
committee of registrants board of directors (and persons performing the
equivalent function):



| | a) |  | all significant deficiencies in the design or operation
of internal controls which could adversely affect the registrants
ability to record, process, summarize and report financial data
and have identified for the registrants auditors any material
weaknesses in internal controls; and
| | -- |  | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|
| | b) |  | any fraud, whether or not material, that involves
management or other employees who have a significant role in the
registrants internal controls.                                                                                                                                            

6.     The registrants other certifying officers and I have indicated in this
annual report whether there were significant changes in internal controls or in
other factors that could significantly affect internal controls subsequent to
the date of our most recent evaluation, including any corrective actions with
regard to significant deficiencies and material weaknesses.

|                    |  |     |  |                            
|------------------- |  | --- |  | ---------------------------
|Date: June 27, 2003 |  | By: |  | /s/ Cameron R. Sebastian   
|                    |  |     |  |                            
|                    |  |     |  | Cameron R. Sebastian       
|                    |  |     |  | Vice-President, Finance and
|                    |  |     |  | Chief Financial Officer    





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##### Table of Contents



EXHIBIT INDEX

|            |  |                                                                                                                                                                                                                                                                                                                                   
|----------- |  | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|Exhibit No. |  | Description of Exhibit                                                                                                                                                                                                                                                                                                            
|            |  |                                                                                                                                                                                                                                                                                                                                   
|1.1         |  | First Amended and Restated Trust Indenture for Paramount
Energy Trust dated effective August 1, 2002 between
ComputerShare Trust Company of Canada and Paramount Energy
Operating Corp. (filed as Exhibit 3.1 to the Registration
Statement of PET on Form F-1 (Registration No. 333-98233) and
incorporated herein by reference).
|            |  |                                                                                                                                                                                                                                                                                                                                   
|1.2         |  | First Amended and Restated Trust Indenture for Paramount
Operating Trust dated effective August 1, 2002 between CIBC
World Markets Inc. and the Administrator (filed as Exhibit 3.2
to the Registration Statement of PET on Form F-1 (Registration
No. 333-98233) and incorporated herein by reference).                          
|            |  |                                                                                                                                                                                                                                                                                                                                   
|4.1         |  | Royalty Agreement dated effective July 1, 2002 between
Computershare Trust Company of Canada, as trustee of PET, and
the Administrator, as trustee of POT (filed as Exhibit 10.1 to
the Registration Statement of PET on Form F-1 (Registration
No. 333-98233) and incorporated herein by reference).                             
|            |  |                                                                                                                                                                                                                                                                                                                                   
|4.2         |  | Dealer Manager Agreement dated August 8, 2002 among PET, POT,
the Administrator, PRL, and BMO Nesbitt Burns Inc., CIBC World
Markets Inc. and FirstEnergy Capital Corp. (filed as Exhibit
1.1 to the Registration Statement of PET on Form F-1
(Registration No. 333-98233) and incorporated herein by
reference).                
|            |  |                                                                                                                                                                                                                                                                                                                                   
|4.3         |  | Dealer Manager Amending Agreement dated December 13, 2002
among PET, POT, the Administrator, PRL, and BMO Nesbitt Burns
Inc., CIBC World Markets Inc. and FirstEnergy Capital Corp.
(filed as Exhibit 1.1(a) to the Registration Statement of PET
on Form F-1 (Registration No. 333-98233) and incorporated
herein by reference). 
|            |  |                                                                                                                                                                                                                                                                                                                                   
|4.4         |  | Initial Assets Purchase Agreement dated effective July 1,2002
between PRL and POT (filed as Exhibit 2.1 to the Registration
Statement of PET on Form F-1 (Registration No. 333-98233) and
incorporated herein by reference).                                                                                                      
|            |  |                                                                                                                                                                                                                                                                                                                                   
|4.5         |  | Take-up Agreement dated effective July 1,2002 between PRL and
POT (filed as Exhibit 2.2 to the Registration Statement of PET
on Form F-1 (Registration No. 333-98233) and incorporated
herein by reference).                                                                                                                      
|            |  |                                                                                                                                                                                                                                                                                                                                   
|4.6         |  | Funding Agreement dated effective July 1, 2002 among PET, POT
and PRL (filed as Exhibit 2.3 to the Registration Statement of
PET on Form F-1 (Registration No. 333-98233) and incorporated
herein by reference).                                                                                                                  
|            |  |                                                                                                                                                                                                                                                                                                                                   
|4.7         |  | Guarantee dated February 3, 2003 issued by POT to PRL (filed
as Exhibit 2.7 to the Registration Statement of PET on
Form F-1.                                                                                                                                                                                                     





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##### Table of Contents



|     |  |                                                                                                                                                                                                                                                                                                                                                                                                                            
|---- |  | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|     |  | Exhibit 2.7 to the Registration Statement of PET on Form F-1
(Registration No. 333-98233) and incorporated herein by
reference).                                                                                                                                                                                                                                                                                           
|     |  |                                                                                                                                                                                                                                                                                                                                                                                                                            
|4.8  |  | Guarantee dated February 3, 2003 issued by PET and POT to
certain banks (filed as Exhibit 2.8 to the Registration
Statement of PET on Form F-1 (Registration No. 333-98233) and
incorporated herein by reference).                                                                                                                                                                                                         
|     |  |                                                                                                                                                                                                                                                                                                                                                                                                                            
|4.9  |  | Commitment Letter dated effective August 15, 2002 from Bank of
Montreal, Canadian Imperial Bank of Commerce and Bank of Nova
Scotia to Computershare Trust Company of Canada, as trustee of
PET, and the Administrator, as trustee of POT (filed as
Exhibit 10.5 to the Registration Statement of PET on Form F-1
(Registration No. 333-98233) and incorporated herein by
reference).                                      
|     |  |                                                                                                                                                                                                                                                                                                                                                                                                                            
|4.10 |  | First Amending Agreement dated effective September 30, 2002 to
the Commitment Letter from Bank of Montreal, Canadian Imperial
Bank of Commerce and Bank of Nova Scotia to Computershare
Trust Company of Canada, as trustee of PET, and the
Administrator, as trustee of POT (filed as Exhibit 10.5(a) to
the Registration Statement of PET on Form F-1 (Registration
No. 333-98233) and incorporated herein by reference).
|     |  |                                                                                                                                                                                                                                                                                                                                                                                                                            
|4.11 |  | Second Amending Agreement dated effective November 29, 2002 to
the Commitment Letter from Bank of Montreal, Canadian Imperial
Bank of Commerce and Bank of Nova Scotia to Computershare
Trust Company of Canada, as trustee of PET, and the
Administrator, as trustee of POT (filed as Exhibit 10.5(b) to
the Registration Statement of PET on Form F-1 (Registration
No. 333-98233) and incorporated herein by reference).
|     |  |                                                                                                                                                                                                                                                                                                                                                                                                                            
|4.12 |  | Third Amending Agreement dated effective January 29, 2003 to
the Commitment Letter from Bank of Montreal, Canadian Imperial
Bank of Commerce and Bank of Nova Scotia to Computershare
Trust Company of Canada, as trustee of PET, and the
Administrator, as trustee of POT (filed as Exhibit 10.5(c) to
the Registration Statement of PET on Form F-1 (Registration
No. 333-98233) and incorporated herein by reference).  
|     |  |                                                                                                                                                                                                                                                                                                                                                                                                                            
|4.13 |  | Administrative Services Agreement dated effective August 1,
2002 between the Administrator, as trustee of POT, and PRL
(filed as Exhibit 99.1 to the Registration Statement of PET on
Form F-1 (Registration No. 333-98233) and incorporated herein
by reference).                                                                                                                                                         
|     |  |                                                                                                                                                                                                                                                                                                                                                                                                                            
|4.14 |  | Asset Sale Agreement dated March 19, 2003 between POT and PRL.                                                                                                                                                                                                                                                                                                                                                             
|     |  |                                                                                                                                                                                                                                                                                                                                                                                                                            
|4.15 |  | Unit Incentive Plan of PET (filed as Exhibit 10.2 to the
Registration Statement of PET on Form F-1 (Registration No.
333-98233) and incorporated herein by reference).                                                                                                                                                                                                                                                     





---



##### Table of Contents



|     |  |                                                                                                                                                                                                                                                                                
|---- |  | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|4.16 |  | Employment Agreement between the Administrator and Susan L.
Riddle Rose (filed as Exhibit 10.6 to the Registration
Statement of PET on Form F-1 (Registration No. 333-98233) and
incorporated herein by reference).                                                            
|     |  |                                                                                                                                                                                                                                                                                
|4.17 |  | Employment Agreement between the Administrator and Cameron
Sebastian (filed as Exhibit 10.8 to the Registration Statement
of PET on Form F-1 (Registration No. 333-98233) and
incorporated herein by reference).                                                               
|     |  |                                                                                                                                                                                                                                                                                
|4.18 |  | Employment Agreement between the Administrator and Cameron
Sebastian (filed as Exhibit 10.8 to the Registration Statement
of PET on Form F-1 (Registration No. 333-98233) and
incorporated herein by reference).                                                               
|     |  |                                                                                                                                                                                                                                                                                
|4.19 |  | Employment Agreement between the Administrator and Kevin
Marjoram (filed as Exhibit 10.9 to the Registration Statement
of PET on Form F-1 (Registration No. 333-98233) and
incorporated herein by reference).                                                                  
|     |  |                                                                                                                                                                                                                                                                                
|4.20 |  | Employment Agreement between the Administrator and Clayton
Riddell (filed as Exhibit 10.4 to the Registration Statement
of PET on Form F-1 (Registration No. 333-98233) and
incorporated herein by reference).                                                                 
|     |  |                                                                                                                                                                                                                                                                                
|8.1  |  | List of Subsidiaries of Registrant.                                                                                                                                                                                                                                            
|     |  |                                                                                                                                                                                                                                                                                
|12.1 |  | Certification by Chief Executive Officer and Chief Financial
Officer Pursuant to 18 U.S.C. Section 1350, As Adopted
Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.                                                                                                 
|     |  |                                                                                                                                                                                                                                                                                
|12.2 |  | Prospectus dated February 3, 2002 filed with Securities and
Exchange Commission pursuant to Rule 424(b)(3) constituting
part of the Registration Statement of PET on Form F-1
(Registration No. 333-98233).                                                                    
|     |  |                                                                                                                                                                                                                                                                                
|12.3 |  | Consolidated Balance Sheets of Paramount Energy Trust as at
March 31, 2003 and December 31, 2002, and Consolidated
Statements of Earnings and Retained Earnings and Cash Flows of
Paramount Energy Trust for the three month period ending March 31, 2003 and 2002.            
|     |  |                                                                                                                                                                                                                                                                                
|12.4 |  | Consolidated Balance Sheet of Paramount Energy Trust as at
December 31, 2002 and Consolidated Statement of Earnings and
Retained Earnings (Deficit) and Cash Flows for the Period from
formation on June 28, 2002 to December 31, 2002, together with
Auditors report thereon.
|     |  |                                                                                                                                                                                                                                                                                
|12.5 |  | Balance Sheet of the Paramount Resources Ltd. Northeast
Alberta Properties as at December 31, 2002 and 2001 and
Statements of Earnings and Changes in Investment by Paramount
Resources Ltd. and                                                                               





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##### Table of Contents



|     |  |                                                                                                                                                                                                                                                           
|---- |  | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|     |  | Cash Flows for each of the years in the
three year period ending December 31, 2002, together with
Auditors report thereon.                                                                                                                               
|     |  |                                                                                                                                                                                                                                                           
|12.6 |  | Indemnity Agreement from the Administrator and POT in favor of
Computershare Trust Company of Canada (filed as Exhibit 99.2
to the Registration Statement of PET on Form F-1 (Registration
No. 333-98233) and incorporated herein by reference).          
|     |  |                                                                                                                                                                                                                                                           
|12.7 |  | Form of Indemnity Agreement from the Administrator in favor of
the directors and officers of the Administrator (filed as
Exhibit 99.3 to the Registration Statement of PET on Form F-1
(Registration No. 333-98233) and incorporated herein by
reference).
|     |  |                                                                                                                                                                                                                                                           
|12.8 |  | Form of Indemnity Agreement from POT in favor of the directors
and officers of the Administrator (filed as Exhibit 99.5 to
the Registration Statement of PET on Form F-1 (Registration
No. 333-98233) and incorporated herein by reference).              
|     |  |                                                                                                                                                                                                                                                           
|12.9 |  | Form of Indemnity Agreement from POT in favor of the directors
and officers of the Administrator (filed as Exhibit 99.5 to
the Registration Statement of PET on Form F-1 (Registration
No. 333-98233) and incorporated herein by reference).