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2006



MANAGEMENTS DISCUSSION AND ANALYSIS



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HIGHLIGHTS



|                                                                          |                                |                        |          |          |         |         
|------------------------------------------------------------------------- | ------------------------------ | ---------------------- | -------- | -------- | ------- | --------
|FINANCIAL AND OPERATING HIGHLIGHTS                                        | Three months ended December 31 | Year ended December 31
|($CDN thousands, except volume and per Trust Unit amounts)                | 2006                           | 2005                   | % change | 2006     | 2005    | % change
|FINANCIAL                                                                 |                                |                        |          |          |         |         
|Revenue, including realized gains and losses on financial instruments (2) | 104,166                        | 129,233                | (19)     | 420,846  | 424,741 | (1)     
|Cash flow (2)                                                             | 58,166                         | 78,200                 | (26)     | 236,653  | 260,218 | (9)     
|Per Trust Unit (1) (2)                                                    | 0.69                           | 0.96                   | (28)     | 2.82     | 3.47    | (19)    
|Net earnings (loss)                                                       | (68,254)                       | 17,928                 | (481)    | (18,850) | 61,870  | (130)   
|Per Trust Unit (1)                                                        | (0.80)                         | 0.22                   | (464)    | (0.22)   | 0.82    | (127)   
|Cash distributions                                                        | 50,968                         | 58,990                 | (14)     | 221,789  | 205,032 | 8       
|Per Trust Unit (3)                                                        | 0.60                           | 0.72                   | (17)     | 2.64     | 2.72    | (3)     
|Payout ratio (%) (2)                                                      | 87.6                           | 75.4                   | 16       | 93.7     | 78.8    | 19      
|Total assets                                                              | 805,764                        | 820,408                | (2)      | 805,764  | 820,408 | (2)     
|Net bank and other debt outstanding (7)                                   | 245,484                        | 166,975                | 47       | 245,484  | 166,975 | 47      
|Convertible debentures                                                    | 157,391                        | 64,888                 | 143      | 157,391  | 64,888  | 143     
|Total net debt (7)                                                        | 402,875                        | 231,863                | 74       | 402,875  | 231,863 | 74      
|Unitholders equity                                                       | 202,713                        | 394,643                | (49)     | 202,713  | 394,643 | (49)    
|Capital expenditures                                                      |                                |                        |          |          |         |         
|Exploration and development                                               | 24,104                         | 11,402                 | 111      | 138,259  | 59,896  | 131     
|Acquisitions, net                                                         | 2,536                          | 88                     | 2,782    | 79,760   | 276,671 | (71)    
|Other                                                                     | 456                            | 718                    | (36)     | 1,267    | 1,267   | -       
|Net capital expenditures                                                  | 27,096                         | 12,208                 | 122      | 219,286  | 337,834 | (35)    
|TRUST UNITS OUTSTANDING (thousands)                                       |                                |                        |          |          |         |         
|End of period                                                             | 85,186                         | 82,482                 | 3        | 85,186   | 82,482  | 3       
|Weighted average                                                          | 84,841                         | 81,625                 | 4        | 83,940   | 74,998  | 12      
|Diluted                                                                   | 84,841                         | 82,804                 | 2        | 83,940   | 75,738  | 11      
|March 5, 2007                                                             | 86,032                         |                        |          | 86,032   |         |         



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|                                                            |                                |                        |          |           |          |         
|----------------------------------------------------------- | ------------------------------ | ---------------------- | -------- | --------- | -------- | --------
|FINANCIAL AND OPERATING HIGHLIGHTS CONTINUED                | Three Months Ended December 31 | Year Ended December 31
|                                                            | 2006                           | 2005                   | % change | 2006      | 2005     | % change
|OPERATING                                                   |                                |                        |          |           |          |         
|Production                                                  |                                |                        |          |           |          |         
|Total natural gas (Bcf) (8)                                 | 13.3                           | 14.1                   | (6)      | 56.0      | 53.3     | 5       
|Average daily natural gas (MMcf/d) (8)                      | 144.6                          | 153.7                  | (6)      | 153.4     | 146.0    | 5       
|Per Trust Unit (cubic feet/d/Unit) (1)                      | 1.70                           | 1.88                   | (10)     | 1.83      | 1.94     | (6)     
|Gas over bitumen deemed production (MMcf/d) (9)             | 19.8                           | 21.6                   | (8)      | 20.8      | 22.4     | (7)     
|Average daily (actual and deemed  MMcf/d) (8) (9)          | 164.4                          | 175.3                  | (6)      | 174.2     | 168.4    | 3       
|Per Trust Unit (cubic feet/d/Unit) (1) (9)                  | 1.94                           | 2.15                   | (10)     | 2.08      | 2.25     | (8)     
|Average natural gas prices ($/Mcf)                          |                                |                        |          |           |          |         
|Before financial hedging and physical forward sales (10)    | 6.59                           | 11.41                  | (42)     | 6.61      | 8.71     | (24)    
|Including financial hedging and physical forward sales (10) | 7.83                           | 9.14                   | (14)     | 7.52      | 7.97     | (6)     
|RESERVES (Bcf)                                              |                                |                        |          |           |          |         
|Proved (5) (6)                                              | 175.1                          | 195.8                  | (11)     | 175.1     | 195.8    | (11)    
|Proved plus probable (5) (6)                                | 258.8                          | 282.6                  | (8)      | 258.8     | 282.6    | (8)     
|Per Trust Unit (Mcf/Unit) (4)                               | 3.04                           | 3.43                   | (11)     | 3.04      | 3.43     | (11)    
|Estimated present value before tax ($ millions) (6)         |                                |                        |          |           |          |         
|Proved                                                      | 605.4                          | 849.7                  | (29)     | 605.4     | 849.7    | (29)    
|Proved plus probable                                        | 811.0                          | 1,041.9                | (22)     | 811.0     | 1,041.9  | (22)    
|LAND (thousands of net acres)                               |                                |                        |          |           |          |         
|Total land holdings                                         | 2,637                          | 2,420                  | 9        | 2,637     | 2,420    | 9       
|Undeveloped land holdings                                   | 1,222                          | 1,022                  | 20       | 1,222     | 1,022    | 20      
|DRILLING (wells drilled gross/net)                          |                                |                        |          |           |          |         
|Gas                                                         | 19/13.0                        | 15/7.7                 | 27/69    | 148/111.8 | 102/54.6 | 45/105  
|Dry                                                         | -                              | -                      | -/-      | 4/1.9     | 4/4.0    | -/(53)  
|Total                                                       | 19/13.0                        | 15/7.7                 | 27/69    | 152/113.7 | 106/58.6 | 43/94   
|Success Rate                                                | 100/100                        | 100/100                | -/-      | 97/98     | 96/93    | 1/5     



(1)

Based on weighted average Trust Units outstanding for the period.

(2)

This is a non-GAAP measure; please refer to Significant accounting policies and non-GAAP measures included in Managements Discussion and Analysis.

(3)

Based on Trust Units outstanding at each cash distribution date.

(4)

Based on Trust Units outstanding at period end.

(5)

As evaluated by McDaniel & Associates Consultants Ltd. in accordance with National Instrument 51-101. See Reserves included in Managements Discussion and Analysis. Natural gas reserves presented exclude royalty interest volumes of 2.2 Bcf in 2006 and 2.9 Bcf in 2005.

(6)

Discounted at 10 percent using consultants forecast pricing. Includes gas over bitumen royalty adjustments (2006 - $76.6 million, 2005 - $100.9 million) and gas over bitumen shut-in reserves (probable: 2006  21.6 Bcf and $34.1 million, 2005  25.1 Bcf and $25.8 million).

(7)

Net debt is measured as at the end of the period and includes net working capital (deficiency) before short-term financial instrument assets and liabilities related to the Trusts hedging activities. Total net debt includes convertible debentures.

(8)

Production amounts are based on the Trusts interest before royalties.

(9)

The Trust has 24.7 MMcf/d of natural gas production shut-in or denied production pursuant to various Alberta Energy and Utilities Board (AEUB) decision reports, corresponding shut-in orders or general bulletins or through correspondence in relation to an AEUB ID 99-1 application on or prior to July 1, 2004. Deemed production is not actual gas sales but represents shut-in gas that is the basis of the gas over bitumen financial solution during the period which is received monthly from the Alberta Crown as a reduction against other royalties payable.

(10)

PETs commodity hedging strategy employs both financial forward contracts and physical natural gas delivery contracts at fixed prices or price collars. In calculating the Trusts natural gas price before financial and physical hedging, PET assumes all natural gas sales based on physical delivery fixed-price or price collar contracts during the period were instead sold at AECO daily index.



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MANAGEMENTS DISCUSSION AND ANALYSIS



The following is managements discussion and analysis (MD&A) of Paramount Energy Trusts (PET or the Trust) operating and financial results for the year ended December 31, 2006 as well as information and estimates concerning the Trusts future outlook based on currently available information.  This discussion should be read in conjunction with the Trusts audited consolidated financial statements for the years ended December 31, 2006 and 2005, together with accompanying notes.  Readers are referred to the legal advisories regarding forward-looking information contained in the Forward Looking Information section of this MD&A.  The date of this MD&A is March 6, 2007.



The Trust follows the successful efforts method of accounting for its petroleum and natural gas operations.  This method differs from the full cost accounting method in that exploration expenditures, including exploratory dry hole costs, geological and geophysical costs, lease rentals on undeveloped properties as well as the cost of surrendered leases and abandoned wells, are expensed rather than capitalized in the year incurred.  However, to make reported cash flow results more comparable to industry practice, geological and geophysical costs as well as surrendered leases and dry hole costs are added back to cash flow (see cash flow definition and reconciliation in the Significant accounting policies and Non-GAAP measures section of this MD&A).



DISCLOSURE CONTROLS AND PROCEDURES



Disclosure controls and procedures have been designed to ensure that information required to be disclosed by the Trust is accumulated and communicated to the Trust's management, as appropriate, to allow timely decisions regarding required disclosure.  The Trust's Chief Executive Officer and Chief Financial Officer have concluded, based on their evaluation as of December 31, 2006 (the Evaluation Date), that the Trust's disclosure controls and procedures as of the Evaluation Date are effective to provide reasonable assurance that material information related to the Trust, including its consolidated subsidiaries, is made known to them by others within those entities.



INTERNAL CONTROLS OVER FINANCIAL REPORTING



Internal controls have been designed to provide reasonable assurance regarding the reliability of the Trust's financial reporting and the preparation of financial statements together with the other financial information for external purposes in accordance with Canadian Generally Accepted Accounting Principles (GAAP).  The Trust's Chief Executive Officer and Chief Financial Officer have designed or caused to be designed under their supervision internal controls over financial reporting related to the Trust, including its consolidated subsidiaries.



The Trust's Chief Executive Officer and Chief Financial Officer are required to cause the Trust to disclose herein any change in the Trust's internal control over financial reporting that occurred during the Trust's most recent interim period that materially affected, or is reasonably likely to materially affect the Trust's internal control over financial reporting.  During 2006, the Trust engaged external consultants to assist in documenting and assessing the Trust's design of internal controls over financial reporting.  No material changes were identified in the Trust's internal control of financial reporting during the three months ended December 31, 2006, that had materially affected, or are reasonably likely to materially affect, the Trust's internal control over financial reporting.



Management is prepared to complete certifications in accordance with Section 404 of the Sarbanes-Oxley Act, which will be included in PETs form 40-F filed on EDGAR in the United States.



It should be noted that a control system, including the Trust's disclosure and internal controls and procedures, no matter how well conceived can provide only reasonable, but not absolute, assurance that the objectives of the control system will be met and it should not be expected that the disclosure and internal controls and procedures will prevent all errors or fraud.



CHANGES TO INTERNAL CONTROLS AND PROCEDURES FOR FINANCIAL REPORTING



There were no significant changes to PETs internal controls or other factors that could significantly affect these controls subsequent to the Evaluation Date.



CORPORATE GOVERNANCE



PET is committed to maintaining high standards of corporate governance.  Each regulatory body, including the Toronto Stock Exchange, the Canadian provincial securities commissions and the Securities and Exchange Commission (whose responsibilities include implementing rules under the United States Sarbanes-Oxley Act of 2002) has a different set of rules pertaining to corporate governance. PET fully conforms to the rules of the governing bodies under which it operates and, in many cases, already complies with proposals and recommendations that have not come into force.



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FOURTH QUARTER 2006 HIGHLIGHTS



·

Production averaged 144.6 MMcf/d as compared to 153.7 MMcf/d for the fourth quarter of 2005. The drop in production was primarily related to the extremely cold weather in early November that caused unexpected downtime at several facilities for an extended period. Cash flow totaled $58.2 million for the quarter or $0.69 per Trust Unit as compared to $78.2 million or $0.96 per Trust Unit in the fourth quarter of 2005.



·

Capital spending totaled $24.1 million for the fourth quarter, including the drilling of 19 wells (13.0 net wells) primarily in east central Alberta with a 100 percent net success rate. Fourth quarter expenditures included $5 million recorded for capital activities budgeted for 2007.



·

PET finished planning and began the execution of an $80 million winter capital budget program targeting 25 to 35 MMcf/d of natural gas production additions through drilling, completion, tie-in and facility projects spread throughout the Trusts three core areas in northeast Alberta.



·

Distributions for the fourth quarter of 2006 totaled $0.60 per Trust Unit, paid on November 15, 2006, December 15, 2006 and January 15, 2007. PETs payout ratio for the quarter was 87.6 percent of its cash flow.



·

PET has taken a leadership role with the Coalition of Canadian Energy Trusts (CCET or the Coalition), a united organization of publicly-traded energy trusts that is dedicated to engaging the Government of Canada (federal government) in meaningful consultation surrounding the tax proposals announced by the federal government on October 31, 2006, in an effort to effect change to the proposed legislation and develop alternative solutions that will address the concerns of all stakeholders.



ANNUAL HIGHLIGHTS



|                                                           |            |            |             
|---------------------------------------------------------- | ---------- | ---------- | ------------
|(CDN$ millions, except volumes and per Trust Unit amounts) | 2006       | 2005       | 2004        
|Cash flow (1)                                              | $   236.7  | $   260.2  | $     143.6 
|Cash flow per Trust Unit                                   | $     2.82 | $     3.47 | $       2.65
|Net earnings (loss)                                        | $  (18.9)  | $     61.9 | $    (17.5) 
|Distributions                                              | $   221.8  | $   205.0  | $     121.3 
|Distributions per Trust Unit                               | $     2.64 | $     2.72 | $       2.18
|Payout ratio (%) (1)                                       | 93.7       | 78.8       | 84.5        
|Production (Mcf/d) (2)                                     |            |            |             
|Daily average production                                   | 153,393    | 146,031    | 102,472     
|Gas over bitumen deemed production                         | 20,762     | 22,413     | 16,724      
|Total average daily (actual and deemed)                    | 174,155    | 168,444    | 119,196     



(1)

These are non-GAAP measures; please refer to Significant Accounting Policies and Non-GAAP measures included in this MD&A.

(2)

Production amounts are based on company interest before royalties.

·

In February 2006 PET completed the acquisition of a private Alberta company (AcquireCo) for $91 million, adding 7.5 MMcf/d of operated high-netback shallow gas production in east central Alberta at the closing date of the acquisition.  The corporate acquisition also provided the Trust with 54,000 net acres of year-round access undeveloped land and over 50 defined prospects which met PETs risk profile. AcquireCos management team worked with PET through to the end of June 2006 in executing value-added capital projects on the lands acquired and identifying new low-risk, high deliverability prospects for future development.

·

Daily average production increased five percent to a record 153.4 MMcf/d in 2006. A full year of production from the shallow gas assets acquired in May 2005 (the Northeast Alberta Assets), the acquisition of AcquireCo in February 2006 and a successful 2006 winter capital program all contributed to the production increase.  Excluding average production from the AcquireCo assets of 7.7 MMcf/d, the Trusts exploration and development program of $126 million in 2006 essentially maintained production volumes at 146 MMcf/d.  Production additions from the 2006 capital program continue to enhance the Trusts base production as wells drilled in the Trusts all-weather access areas are completed, tied in and brought onstream in early 2007.





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·

Higher production, hedging gains and lower royalty rates in 2006 relative to 2005 were offset by lower natural gas prices and higher operating costs as the Trust recorded cash flow of $236.7 million or $2.82 per Trust Unit for the year as compared to $260.2 million or $3.47 per Trust Unit for 2005.



·

PETs average realized gas price was $7.52 per Mcf in 2006, down six percent from $7.97 per Mcf in 2005. PETs natural gas price before financial hedging and physical forward sales decreased 24 percent to $6.61 per Mcf in 2006 from $8.71 in 2005, in line with the decrease in AECO prices for the year. The $0.91 per Mcf increase in the Trusts realized natural gas price as compared to PETs gas price before financial hedging and physical forward sales can be attributed to fixed-price forward natural gas contracts entered into by the Trust in order to provide distribution stability for PETs Unitholders, lock in gas prices on the AcquireCo acquisition and take advantage of a strong forward price curve for natural gas in the first half of 2006. As a result of this price management strategy, PET realized $51 million of additional revenue and cash flow in 2006.



·

PET executed its most ambitious winter capital spending program in its four year history in the first quarter of 2006: an $80 million program focused in northeast Alberta pursuing shallow natural gas drilling targets, production optimization activities such as recompletions and workovers, pipeline construction to tie-in production from new wells and plant efficiency improvement activities. Also included were seismic data acquisition and land purchases of $8 million.  PET spent $45 million on its all-weather access properties primarily located in the Southern core area during the final three quarters of the year.  The Trust recorded $13 million in undeveloped land acquisition costs in 2006 which augmented the Trusts substantial prospect inventory.  These expenditures contributed to a 20 percent increase in the Trust's undeveloped land base in 2006.  PET has one of the most extensive inventories in the energy trust sector of undeveloped land relative to its production base.



·

During the third quarter the Trust completed an internal restructuring in order to enhance the value of certain minor assets south of its Athabasca core area.  An experienced technical team was recruited and assets in the Radway/Abee area producing approximately 1.4 MMcf/d (the Severo Assets) were transferred to a newly formed private company, Severo Energy Corporation (Severo or the Corporation) in exchange for common shares of Severo valued at $2.00 per common share.  Severo also raised $2 million through a private placement of shares to employees and consultants of Severo and PET, priced at the same $2.00 per common share, in exchange for a collective 6 percent interest in the Corporation. The independent members of PETs Board of Directors reviewed the transaction and determined the exchange to be at fair market value of the Severo Assets.  The remaining 94 percent of the Corporation is owned by the Trust and as such the financial results of Severo have been included in the consolidated results of the Trust.  The Severo Assets represent fragmented interests, many of which are non-operated; the Trust is confident that this approach will lead to value creation for Unitholders.



·

PET raised $36.3 million in 2006 through the Distribution Reinvestment Plan (DRIP), issuing 2,139,000 Trust Units at an average price of $16.96 per Trust Unit.



·

On April 6, 2006 PET closed its offering of $100 million of 6.25% convertible unsecured subordinated debentures (the 2006 6.25% Debentures). The 2006 6.25% Debentures have a maturity date of April 30, 2011, are convertible into Trust Units at a price of $23.80 per Trust Unit.



·

In conjunction with PETs capital spending programs and acquisition activity, the Trust continued to maintain financial discipline throughout 2006. PETs ratio of total net debt, including convertible debentures, at December 31, 2006 to annualized fourth quarter cash flow measured 1.7 times.



OPERATIONS



Properties



PET continued to expand the geographic boundaries of its operations with the AcquireCo acquisition in February 2006.  At the same time, the key attributes of PETs asset base remained unchanged. The Trusts assets are focused technically with shallow natural gas comprising 100 percent of production volumes, and focused geographically with over 85 percent of production coming from northeast Alberta.  Virtually all of PETs properties feature well established, high working interest production and most are operated by PET.  Production profiles are predictable due to the extensive production histories and the diversification of PETs asset base.  Relatively low operating costs and access to markets proximal to the assets combine to deliver high field netbacks. PET has an extensive inventory of low cost opportunities for value creation which extends throughout the asset base and the undeveloped lands, requiring modest capital expenditures to offset most of the annual natural production declines. Strategic infrastructure ownership throughout PETs asset base provides additional opportunities to add value through synergies and economies of scale.





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The Trusts asset base is divided operationally into four core areas:



·

West Side  includes assets west of Alberta Highway 63 which began with production from Devonian carbonate reservoirs;

·

East Side  is comprised of assets east of Alberta Highway 63 (including Cold Lake) and production is mainly from Cretaceous clastic reservoirs;

·

Athabasca  includes assets south and west of PETs original assets in the West Side core area and production is from both Cretaceous clastic reservoirs and Devonian carbonate reservoirs; and

·

Southern  includes assets in east central Alberta, southern Alberta and western Saskatchewan.



Production



|                                             |       |       |      
|-------------------------------------------- | ----- | ----- | -----
|Natural gas production by core area (MMcf/d) | 2006  | 2005  | 2004 
|West Side                                    | 46.3  | 45.3  | 38.0 
|East Side                                    | 26.4  | 28.8  | 34.5 
|Athabasca                                    | 69.0  | 65.4  | 24.9 
|Southern                                     | 11.7  | 6.5   | 5.1  
|Total                                        | 153.4 | 146.0 | 102.5
|Deemed production (1)                        | 20.8  | 22.4  | 16.7 
|Total actual plus deemed production          | 174.2 | 168.4 | 119.2

(1)Deemed production is a result of shut-in production volumes in the East Side core area. See Gas over bitumen royalty adjustments in this MD&A.



Production volumes increased five percent to 153.4 MMcf/d (56.0 Bcf total) in 2006 from 146.0 MMcf/d (53.3 Bcf total) in 2005. The increase in production in the West Side and Athabasca core areas is a result of a full year of production from the Northeast Alberta Assets and a successful 2006 winter capital program which reduced production declines in each of the three core areas in northeast Alberta. The increase in production in the Southern core area is due to the acquisition of AcquireCo in February 2006 and continuing development of these assets throughout the year, offset somewhat by production declines in western Saskatchewan.



In 2006, five properties located within the Trusts four core areas accounted for 41 percent of the Trusts production with the largest single property, Wabasca in the Athabasca core area, accounting for 11 percent of the total production.  This diversification of production minimizes the risk that operating problems at a specific property will materially impact the Trust.



Capital expenditures



|                                             |          |         |         
|-------------------------------------------- | -------- | ------- | --------
|Capital expenditures ($ thousands)           | 2006     | 2005    | 2004    
|Exploration and development expenditures (1) | 125,638  | 52,214  | 27,767  
|Undeveloped land purchases                   | 12,621   | 7,682   | 1,124   
|Acquisitions                                 | 97,449   | 285,956 | 417,779 
|Dispositions                                 | (17,689) | (9,285) | (32,750)
|Other                                        | 1,267    | 1,267   | 11,169  
|Total capital expenditures                   | 219,286  | 337,834 | 425,089 

(1)Exploration and development expenditures for 2006 include approximately $13.8 million in exploration costs which have been expensed directly on the Trusts statement of earnings (2005 - $16.8 million). Exploration costs include seismic expenditures, dry hole costs and expired leases and are considered by PET to be more closely related to investing activities than operating activities; as a result they are included with capital expenditures.



Exploration and development expenditures for 2006 included an $80 million capital program conducted in the first quarter that concentrated on the Trusts three winter-only access core areas in northeast Alberta, which included the drilling of 79 gas wells, over 175 recompletion and workover projects, acquisition of 875 km of 2D seismic, and facilities construction and optimization projects. Following up on the success of PETs winter capital activities, the Trust initiated a $45 million capital expenditure program for the remaining three quarters of 2006 focused on exploiting drilling opportunities in its year-round access areas, specifically in east central Alberta, the southern portion of the East Side core area and the properties operated by Severo directly south of the Athabasca core area. Undeveloped land acquisitions increased from $7.7 million in 2005 to $12.6 million in 2006 in order to continue to feed the inventory of low-risk shallow gas development prospects within PETs core areas.





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Acquisitions of $97.4 million in 2006 reflect primarily the AcquireCo transaction completed in February, as well as a minor consolidating acquisition in east central Alberta in the fourth quarter. The acquisition of the Northeast Alberta Assets comprised the majority of the $286.0 million in acquisitions in 2005.



Dispositions totaled $17.7 million in 2006, comprised primarily of the sale of certain shut-in gas over bitumen natural gas assets in the second quarter. As part of the transaction, PET continues to receive the monthly gas over bitumen royalty adjustments on the assets, thereby realizing significant proceeds on disposition without sacrificing cash flows.



Total capital expenditures of $219.3 million for 2006 were funded by cash flow in excess of distributions of $16.2 million, proceeds from the Trusts distribution reinvestment plan (DRIP) of $36.3 million, the offering of $100 million in 6.25% convertible debentures closed in April, 2006 and PETs available bank credit facilities.



The Board of Directors of Paramount Energy Operating Corp., PETs Administrator, has approved a budget for exploration and development capital expenditures of up to $128 million for 2007, of which approximately $5 million in preliminary costs were incurred in 2006. An $80 million winter capital program including $10 million in budgeted land and seismic expenditures is currently underway while the capital budget for the remainder of the year is adjustable depending on natural gas prices.



Drilling



|                 |       |       |       |      |       |     
|---------------- | ----- | ----- | ----- | ---- | ----- | ----
|                 | 2006  | 2005  | 2004 
|Wells drilled    | Gross | Net   | Gross | Net  | Gross | Net 
|Gas              | 148   | 111.8 | 102   | 54.6 | 45    | 28.5
|Service          | -     | -     | -     | -    | -     | -   
|Dry              | 4     | 1.9   | 4     | 4.0  | 1     | 0.4 
|Total            | 152   | 113.7 | 106   | 58.6 | 46    | 28.9
|Success rate (%) | 97    | 98    | 96    | 93   | 98    | 99  



PET drilled 113.7 net wells in 2006, an increase of 94 percent over 2005. The increase in wells drilled corresponds to the increase in 2006 capital expenditures as compared to 2005. Drilling activity in the first quarter of 2006 included 79 (65.4 net) wells spread throughout the Trusts three core areas in northeast Alberta, achieving a 99 percent net success rate.  The Trust was active in its Southern core area in 2006, drilling 35 wells (34.7 net) on the AcquireCo lands with a 94 percent net success rate and 20 wells (10.6 net) in other regions within the Southern core area and Cold Lake. PET also participated in 18 wells (3.0 net) in 2006 as part of a non-operated coalbed methane project in the Craigmyle area of southern Alberta.



Reserves



PETs complete National Instrument 51-101 reserves disclosure as at December 31, 2006, including underlying assumptions regarding commodity prices, expenses and other factors and reconciliation of reserves on a net interest basis (working interest less royalties payable), is contained in the Trusts Annual Information Form for the year ended December 31, 2006.





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The reserves data set out below (the Reserves Data) is based upon an evaluation by McDaniel and Associates Consultants Ltd. (McDaniel) with an effective date of December 31, 2006 contained in a report of McDaniel dated January 30, 2007 (the McDaniel Report). The Reserves Data summarizes the natural gas reserves of the Trust, including the reserves of Severo, and the net present values of future net revenue for these reserves using McDaniel forecast prices and costs. The oil and natural gas liquids volumes are immaterial and have therefore been excluded from the Reserves Data; however the net present values of future net revenue for these reserves are included in the following summary table.



|                                                             |         |         |        
|------------------------------------------------------------ | ------- | ------- | -------
|Natural gas reserves as at December 31 (MMcf)(1)             | 2006    | 2005    | 2004   
|Proved                                                       |         |         |        
|Developed producing                                          | 161,349 | 179,976 | 162,597
|Developed non-producing                                      | 7,023   | 6,860   | 3,647  
|Shut-in gas over bitumen reserves (2)                        | -       | -       | 11,988 
|Undeveloped                                                  | 6,703   | 9,006   | 3,181  
|Total proved                                                 | 175,075 | 195,842 | 181,413
|Probable                                                     |         |         |        
|Developed producing, developed non-producing and
undeveloped | 62,128  | 61,777  | 40,162 
|Shut-in gas over bitumen reserves (2)                        | 21,572  | 25,065  | 11,969 
|Total probable                                               | 83,700  | 86,842  | 52,131 
|Total proved & probable                                      | 258,775 | 282,684 | 233,544
|Trust Units outstanding (millions)                           | 85.2    | 82.5    | 65.3   
|Total proved & probable per Trust Unit (Mcf/Unit)            | 3.04    | 3.43    | 3.58   

(1)

Natural gas reserves presented exclude royalty interest volumes of 2,190 MMcf in 2006, 2,873 MMcf in 2005 and 2,093 MMcf in 2004.

(2)

See net present value of future net revenues table below.



The net present values of future net revenues for PETs reserves, using McDaniel forecast prices and costs at zero and   ten percent discount rates are presented in the table below. For income tax purposes PET is able to and intends to claim a deduction for all amounts paid or payable to the Unitholders and then allocate remaining taxable income, if any, to the Unitholders. The tax amounts related to the Severo reserves are immaterial. Accordingly, no income tax amounts have been reported in this Reserves Data (see Income Taxes in this MD&A).



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|                                                                 |           |         |           |           |         |        
|---------------------------------------------------------------- | --------- | ------- | --------- | --------- | ------- | -------
|Net present values of reserves as at December 31                 |           | 2006    |           | 2005      |         | 2004   
|($thousands, forecast prices and costs discounted at 0% and 10%) | 0%        | 10%     | 0%        | 10%       | 0%      | 10%    
|Proved                                                           |           |         |           |           |         |        
|Developed producing                                              | 666,344   | 533,683 | 878,485   | 727,775   | 541,810 | 426,559
|Developed non-producing (1)                                      | (8,100)   | (5,079) | 6,253     | 6,989     | (6,768) | (4,227)
|Gas over bitumen royalty
adjustments                             | 103,070   | 76,630  | 133,648   | 100,863   | 115,736 | 82,706 
|Shut-in gas over bitumen reserves (2)                            | (3,489)   | (2,603) | (6,503)   | (1,308)   | 23,024  | 8,710  
|Undeveloped                                                      | 6,738     | 2,785   | 22,218    | 15,363    | 6,597   | 4,265  
|Total proved                                                     | 764,563   | 605,416 | 1,034,102 | 849,682   | 680,399 | 518,013
|Probable                                                         |           |         |           |           |         |        
|Developed producing, developed
non-producing and undeveloped     | 275,360   | 171,484 | 265,100   | 166,441   | 136,331 | 79,826 
|Shut-in gas over bitumen reserves (2)                            | 88,506    | 34,067  | 77,718    | 25,785    | 28,753  | 8,383  
|Total probable                                                   | 363,866   | 205,551 | 342,818   | 192,226   | 165,084 | 88,209 
|Total proved & probable                                          | 1,128,429 | 810,967 | 1,376,920 | 1,041,908 | 845,483 | 606,223
|Trust Units outstanding (millions)                               | 85.2      | 85.2    | 82.5      | 82.5      | 65.3    | 65.3   
|Total proved & probable per Trust Unit ($/Unit)                  | 13.24     | 9.52    | 16.69     | 12.63     | 12.95   | 9.28   



(1)

The McDaniel Report incorporates an estimate for abandonment costs for producing and non-producing wells.  This results in a net liability to PET for wells in this category.The McDaniel Report assumes that the shut-in gas over bitumen reserves are probable but the future abandonment and reclamation liability associated with the wells is proved, that the reserves return to production after ten years of shut-in and that such production is subject to an incremental ten percent gross overriding royalty pursuant to the amended Royalty Regulation. In 2004, 50 percent of the shut-in gas over bitumen reserves were classified as proved. The negative value of proved shut-in gas over bitumen reserves represents an estimate of the future abandonment costs of the affected wells.



The following table sets forth a reconciliation of the changes in reserves for the year ended December 31, 2006 from the opening balance on December 31, 2005 derived from the McDaniel Reports at those dates, using McDaniel forecast prices.



|                                  |        |          |                  
|--------------------------------- | ------ | -------- | -----------------
|Reserves reconciliation (Bcf)     | Proved | Probable | Proved & Probable
|December 31, 2005                 | 195.8  | 86.8     | 282.6            
|Discoveries and extensions        | 20.2   | 5.3      | 25.5             
|Technical revisions               | 9.7    | (6.1)    | 3.6              
|Acquisitions, net of dispositions | 5.4    | (2.3)    | 3.1              
|Production                        | (56.0) | -        | (56.0)           
|December 31, 2006                 | 175.1  | 83.7     | 258.8            



According to the McDaniel Report, over 92 percent of the Trusts proved reserves are developed producing reserves.  The McDaniel report identifies minimal future capital expenditures to realize the estimated production potential of the reserves identified: $31 million for the proved reserves and $9 million for the probable reserves, $15 million of which are specified for 2007.  Internally, the Trust has a significant inventory of opportunities which exceeds the forecast future capital expenditures recognized in the reserve report, including the opportunities currently being pursued in the Trusts 2007 exploration and development capital program.



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As a result of the Trusts growth strategy of using acquisitions to supplement its list of drilling prospects and the lead time involved in developing core areas in Northeast Alberta due to the short drilling season, PET feels that finding, development and acquisition costs as measured over a rolling three year period are a better indicator of the Trusts ability to acquire and develop new reserves as opposed to an annual calculation. The Trusts three year FD&A costs including future capital expenditures for proved and probable reserves were $3.71 per Mcf for 2006.



Three year finding, development and acquisition costs



|                                                                      |         |                  
|--------------------------------------------------------------------- | ------- | -----------------
|Capital expenditures ($millions)                                      | Proved  | Proved & Probable
|Exploration and development                                           | 206.7   | 206.7            
|Undeveloped land                                                      | 20.3    | 20.3             
|Acquisitions                                                          | 802.5   | 802.5            
|Dispositions                                                          | (59.8)  | (59.8)           
|Total exploration and development expenditures                        | 969.7   | 969.7            
|Less increase in net book value of undeveloped land                   | (46.6)  | (46.6)           
|Add increase in future development capital                            | 21.7    | 28.5             
|FD&A net capital expenditures (1)                                     | 944.8   | 951.6            
|Reserve additions (Bcf)                                               |         |                  
|Increase  in reserves over the three year period                      | 51.8    | 110.0            
|Reclassification of gas over bitumen reserves from proved to probable | 18.8    | -                
|Production over the three year period                                 | 146.8   | 146.8            
|Reserve additions                                                     | 217.4   | 256.8            
|2006 FD&A costs ($/Mcf) (1)                                           | $  4.35 | $  3.71          

(1) FD&A is finding, development and acquisition costs.



Land



|               |           |                              |           |                             
|-------------- | --------- | ---------------------------- | --------- | ----------------------------
|               | 2006      | 2005                        
|Land inventory | Net acres | Average working interest (%) | Net acres | Average working interest (%)
|Developed      | 1,415,215 | 72.1                         | 1,398,194 | 74.0                        
|Undeveloped    | 1,221,684 | 76.7                         | 1,021,976 | 74.8                        
|Total          | 2,636,899 | 74.2                         | 2,420,170 | 74.4                        



PETs undeveloped acreage position increased by 20 percent in 2006.  The 54,000 acres of undeveloped land included with the AcquireCo transaction and participation in Crown land offerings to build PETs opportunity inventory contributed to the higher undeveloped acreage total.  PET has one of the most extensive inventories in the energy trust sector of undeveloped land relative to production base.



The Trusts undeveloped acreage in the East Side Core Area includes approximately 227,000 net acres inside the gas over bitumen area of concern. While development of this acreage is restricted in certain formations, there are numerous other prospective zones in the region. The mineral rights for leases with shut-in production are continued indefinitely under Section 8-1-h of the Mines and Minerals Act(Alberta) until resolution of the gas over bitumen issue.



PET estimates the fair value of its undeveloped acreage to be $86 million at December 31, 2006 (December 31, 2005 - $83 million), using a combination of average land sale values by area and recent land sale acquisitions by the Trust.





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Gas over bitumen royalty adjustments



In 2004 and 2005 the Government of Alberta enacted amendments to the royalty regulation with respect to natural gas (Royalty Regulation), which provide a mechanism whereby the Government may prescribe additional royalty components to effect a reduction in the royalty calculated through the Crown royalty system for operators of gas wells which have been denied the right to produce by the AEUB as a result of certain bitumen conservation decisions. The formula for calculation of the royalty reduction provided in the Royalty Regulation is:



0.5 x [(deemed production volume x 0.80) x (Alberta Gas Reference Price - $0.3791/GJ)]



Through this formula, operating costs are effectively deemed to be $0.40 Per Mcf, royalties are deemed to be 20 percent, the deemed production is assigned the Alberta Gas Reference Price, which includes a transportation component and the entire formula is assigned a 50 percent reduction factor. The components of netbacks for the gas over bitumen shut-in reserves are outlined below:



|                                                          |           |          |         
|--------------------------------------------------------- | --------- | -------- | --------
|                                                          |           |          |         
|Gas over bitumen royalty adjustment netback   ($ per Mcf) | 2006      | 2005     | 2004    
|Average deemed volume (MMcf/d)                            | 20.8      | 22.4     | 16.7    
|Gas price                                                 | $    6.74 | $   8.30 | $   6.28
|Royalties                                                 | (1.35)    | (1.66)   | (1.26)  
|Operating costs                                           | (0.40)    | (0.40)   | (0.40)  
|50% reduction factor                                      | (2.49)    | (3.12)   | (2.31)  
|Gas over bitumen royalty adjustment netback               | $    2.50 | $   3.12 | $   2.31



The Trusts net deemed production volume for purposes of the royalty adjustment was 20.8 MMcf/d in 2006. Deemed production represents all PET natural gas production that has been shut-in or denied production pursuant to a Decision Report, corresponding AEUB Order or General Bulletin, or through correspondence in relation to an AEUB ID 99-1 application.  In accordance with IL 2004-36, the deemed production volume related to wells shut-in is reduced by 10 percent at the end of every year of shut-in.  PETs current deemed production is approximately 19.8 MMcf/d.



The majority of royalty adjustments received have been recorded on PETs balance sheet rather than reported as income as the Trust cannot determine if, when or to what extent the royalty adjustments may be repayable through incremental royalties if and when gas production recommences.  Royalty adjustments may be repayable to the Crown in the form of an overriding royalty on gas production from wells which resume production within the gas over bitumen area. However, all royalty adjustments are recorded as a component of cash flow and as such are considered distributable income.



In the second quarter of 2006, PET disposed of certain shut-in gas wells in the gas over bitumen area. As part of the disposition agreement, the Trust continues to receive the gas over bitumen royalty adjustments related to the sold wells, although the ownership of the natural gas reserves is transferred to the buyer. As such, any overriding royalty payable to the Crown when gas production recommences from the affected wells is no longer PETs responsibility. As a result of this disposition, the gas over bitumen royalty adjustments received by the Trust for the affected wells are now considered revenue since they will not be repaid to the Crown. The Trust reclassifed $13.7 million from the gas over bitumen liability on the balance sheet into revenues representing all royalty adjustments received to the disposition date in respect of the disposed wells.



During 2006, the Trust received $18.5 million in gas over bitumen royalty adjustments as compared to $30.6 million received in 2004.  The decrease is primarily due to lower gas prices as the royalty adjustment is calculated using the actual Alberta Gas Reference Price each month. The deemed production volume has also been reduced in 2006 as compared to 2005 in accordance with the Royalty Regulation.  This brings cumulative royalty adjustments received to December 31, 2006 to $60.3 million ($41.8 million to December 31, 2005), of which $14.9 million has been recorded as revenue and $45.4 million has been recorded on the Trusts balance sheet.



PET continues to focus on converting its shut-in natural gas reserves back into producing assets.  While the Trust is receiving partial relief for its lost cash flow in the form of monthly royalty reductions, PET still owns the shut-in reserves and they are more valuable if returned to production.  PET continues to monitor new information as there is potential that future field evidence from actual SAGD projects will provide support to PETs technical position.  The Trust also continues its active involvement in technical solution initiatives.





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MARKETING



Natural gas prices



|                                                                                      |         |         |        
|------------------------------------------------------------------------------------- | ------- | ------- | -------
|Natural gas price ($/Mcf, except percentages)                                         | 2006    | 2005    | 2004   
|Reference prices                                                                      |         |         |        
|AECO Monthly Index                                                                    | $  6.99 | $  8.50 | $  6.54
|AECO Daily Index                                                                      | $  6.53 | $  8.74 | $  6.55
|Alberta Gas Reference Price (1)                                                       | $  6.74 | $  8.30 | $  6.28
|Average PET prices                                                                    |         |         |        
|Before financial hedging and physical forward sales (2)                               | $  6.61 | $  8.71 | $  6.51
|Percent of Alberta Gas Reference Price                                                | 98      | 105     | 104    
|                                                                                      |         |         |        
|Before financial hedging (3)                                                          | $  7.17 | $  8.30 | $  6.51
|Percent of Alberta Gas Reference Price                                                | 106     | 100     | 104    
|                                                                                      |         |         |        
|Including financial hedging and physical forward sales (Realized natural gas price) | $  7.52 | $  7.97 | $  6.40
|Percent of Alberta Gas Reference Price                                                | 112     | 96      | 102    



(1) Alberta Gas Reference Price is the price used to calculate Alberta Crown royalties.

(2) PETs commodity hedging strategy employs both financial forward contracts and physical natural gas delivery contracts at fixed prices or price collars. In calculating the Trusts natural gas price before financial and physical hedging, PET assumes all natural gas sales based on physical delivery fixed-price or price collar contracts during the period were instead sold at AECO daily index.

(3)Natural gas price before financial hedging includes physical forward sales contracts for which delivery was made during the reporting period but excludes realized gains and losses on financial instruments.



U.S. natural gas prices are typically referenced to NYMEX at the Henry Hub, Louisiana while western Canada natural gas prices are referenced to the AECO Hub in Alberta.  AECO Monthly Index prices decreased 18 percent to average $6.99 per Mcf in 2006 as compared to $8.50 per Mcf for 2005.  The decline was largely driven by record high natural gas storage levels due in part to mild winter weather which has lowered gas demand in key consuming regions.



The Alberta Gas Reference Price is the monthly weighted average of intra-Alberta consumers' prices and ex-Alberta border prices, reduced by allowances for transporting and marketing gas.  The Alberta Gas Reference Price is used to calculate Alberta Gas Crown Royalties.  The Alberta Gas Reference Price decreased 19 percent from $8.30 per Mcf in 2005 to $6.74 per Mcf in 2006.



PETs natural gas price before financial hedging and physical forward sales decreased 24 percent to $6.61 per Mcf in 2006 from $8.71 in 2005, in line with the decrease in AECO prices for the year.  PETs average realized gas price after hedging transactions was $7.52 per Mcf and $7.97 per Mcf in 2006 and 2005 respectively. The $0.91 per Mcf increase in the Trusts realized natural gas price as compared to PETs gas price before financial hedging and physical forward sales can be attributed to fixed-price forward natural gas contracts entered into by the Trust in order to provide distribution stability for PETs Unitholders, lock in gas prices on the AcquireCo acquisition and take advantage of a strong forward price curve for natural gas in the first half of 2006. As a result of this strategy, PET realized $51 million of additional revenue and cash flow in 2006.



Hedging and risk management



PETs commodity price risk management activities are conducted in consultation with the Board of Directors of the Administrator of the Trust with the objective of using a proactive and opportunistic approach to hedging in order to maximize cash flow while managing price risk rather than a routine portfolio approach.  A number of market analysis tools are used in an attempt to identify perceived anomalies or trends in natural gas markets.  Hedging is also used to ensure or enhance the economics related to significant acquisitions.  The Trust mitigates exposure to credit risk associated with these risk management contracts by only entering into financial hedging transactions with financially sound, credit-worthy counterparties in accordance with Risk Management Policies approved by the Board of Directors of the Administrator.



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At December 31, 2006 the Trust had entered into financial hedge and forward physical gas sales arrangements at AECO as follows:



|                     |                 |                        |              |       |        |                           
|-------------------- | --------------- | ---------------------- | ------------ | ----- | ------ | --------------------------
|Type of contract     | PET transaction | Volumes at AECO (GJ/d) | Price ($/GJ) | Term 
|Fixed                | Floor           | Ceiling               
|Financial            | sold            | 36,000                 | $8.27        | -     | -      | January  March 2007      
|Financial            | bought          | (7,500)                | $7.66        | -     | -      | January  March 2007      
|Financial            | sold            | 5,000                  | -            | $9.50 | $11.00 | January  March 2007      
|Financial            | sold            | 5,000                  | -            | $9.00 | $10.00 | January  March 2007      
|Physical             | sold            | 22,500                 | $8.99        | -     | -      | January  March 2007      
|Physical             | sold            | 5,000                  | -            | $9.00 | $11.00 | January  March 2007      
|Physical             | sold            | 5,000                  | -            | $9.00 | $10.00 | January  March 2007      
|Physical             | sold            | 5,000                  | -            | $8.50 | $11.00 | January  March 2007      
|Period total, net(1) | sold            | 76,000                 |              | $8.72 |        | January  March 2007      
|Financial            | sold            | 40,000                 | $7.91        | -     | -      | April  October 2007      
|Financial            | bought          | (7,500)                | $7.09        | -     | -      | April  October 2007      
|Physical             | sold            | 35,000                 | $8.04        | -     | -      | April  October 2007      
|Period total, net(1) | sold            | 67,500                 |              | $7.98 |        | April  October 2007      
|Financial            | sold            | 37,500                 | $9.27        | -     | -      | November 2007  March 2008
|Physical             | sold            | 37,500                 | $9.69        | -     | -      | November 2007  March 2008
|Period total, net    | sold            | 75,000                 |              | $9.48 |        | November 2007  March 2008



(1)Weighted average prices are calculated using floor prices for collars, and netting the volumes of the financial sold/bought contracts together and measuring the net volume at the weighted average sold price for the financial contracts.



PET had also entered into financial and physical forward gas sales arrangements based on the NYMEX index, as follows:



|                 |                 |                            |                   |                           
|---------------- | --------------- | -------------------------- | ----------------- | --------------------------
|Type of contract | PET transaction | Volumes at NYMEX (MMBTU/d) | Price (US$/MMBTU) | Term                      
|Financial        | sold            | 2,500                      | $7.82             | January  March 2007      
|Financial        | sold            | 2,500                      | $9.23             | March 2007                
|Financial        | bought          | (2,500)                    | $8.85             | March 2007                
|Financial        | sold            | 2,500                      | $10.30            | November 2007  March 2008
|Financial        | bought          | (2,500)                    | $10.24            | November 2007  March 2008
|Physical         | sold            | 2,500                      | $10.29            | November 2007  March 2008
|Physical         | sold            | 5,000                      | $6.68             | April  October 2008      



In addition, PET has entered into financial contracts to sell forward Canadian dollars for US dollars at a fixed exchange rate in order to mitigate the effect of exchange rate fluctuations on the Trusts realized natural gas price. Foreign exchange contracts outstanding as at December 31, 2006 are as follows:



|                 |                     |                          |                     
|---------------- | ------------------- | ------------------------ | --------------------
|Type of Contract | CDN$ sold (monthly) | Fixed FX rate (CDN$/US$) | Term                
|Financial        | $1,000,000          | 1.1100                   | April  October 2008



During 2006 PET terminated certain financial natural gas forward sales contracts and foreign exchange contracts in exchange for cash settlements from the Trusts counterparties totaling $5.3 million. This amount has been included in realized gains on financial instruments, net earnings and cash flow for the period.



During the year ended December 31, 2006, the Trust entered into certain physical contracts to purchase natural gas from third parties at fixed prices or prices collars that were equivalent to or below the prices on existing physical contracts to sell natural gas to the same third parties in order to effectively close out certain of its physical forward sales contracts at a premium.  As a result of entering into these purchase contracts the Trust will collect a total of $2.1 million over the terms of the contracts, with approximately $1.9 million to be collected in the first quarter of 2007 and $0.2 million to be collected during the final three quarters of 2007.



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The Trusts financial hedging and physical sales portfolio has changed significantly since December 31, 2006. Total financial hedge arrangements and physical sales contracts outstanding as of March 5, 2007 are as follows:



|                     |                 |                        |                    |                           
|-------------------- | --------------- | ---------------------- | ------------------ | --------------------------
|Type of contract     | PET transaction | Volumes at AECO (GJ/d) | Fixed Price ($/GJ) | Term                      
|Financial            | sold            | 62,500                 | $7.65              | April  October 2007      
|Financial            | bought          | (7,500)                | $7.09              | April  October 2007      
|Physical             | sold            | 35,000                 | $8.00              | April  October 2007      
|Period total, net(1) | sold            | 90,000                 | $7.79              | April  October 2007      
|Financial            | sold            | 45,000                 | $9.09              | November 2007  March 2008
|Physical             | sold            | 37,500                 | $9.69              | November 2007  March 2008
|Period total, net    | sold            | 82,500                 | $9.36              | November 2007  March 2008
|Financial            | sold            | 25,000                 | $7.54              | April  October 2008      



(1)Weighted average prices are calculated using floor prices for collars, and netting the volumes of the financial sell/buy contracts together and measuring the net volume at the weighted average sell price for the financial contracts.



PETs NYMEX-based financial and physical forward gas sales arrangements as of February 23, 2007 are as follows:



|                 |                 |                            |                   |                           
|---------------- | --------------- | -------------------------- | ----------------- | --------------------------
|Type of contract | PET transaction | Volumes at NYMEX (MMBTU/d) | Price (US$/MMBTU) | Term                      
|Financial        | sold            | 2,500                      | $10.30            | November 2007  March 2008
|Financial        | bought          | (2,500)                    | $10.24            | November 2007  March 2008
|Physical         | sold            | 2,500                      | $10.29            | November 2007  March 2008
|Physical         | sold            | 5,000                      | $6.68             | April  October 2008      
|Financial        | sold            | 10,000                     | $7.70             | April  October 2008      



FINANCIAL RESULTS



Revenue



|                                                   |         |          |        
|-------------------------------------------------- | ------- | -------- | -------
|Revenue ($ thousands)                              | 2006    | 2005     | 2004   
|Oil and natural gas revenue, before hedging        | 401,635 | 442,505  | 244,303
|Realized gains/losses on financial instruments (1) | 19,211  | (17,764) | (4,346)
|Natural gas revenues, after financial hedging      | 420,846 | 424,741  | 239,957



(1)Realized gains/losses on financial instruments include settlement of financial forward contracts and options for natural gas and foreign exchange.



Oil and natural gas revenue in 2006 was $420.8 million, representing a one percent decrease from $424.7 million in 2005.  The slight reduction in revenue was caused by the 24 percent decrease in gas prices offset by $51 million in positive contributions from financial hedging and physical forward sales contracts and the five percent increase in natural gas production in 2006 as compared to the prior year.



The Trust recorded unrealized gains on financial instruments of $24.9 million in 2006, reflecting the change in the fair value of unsettled financial forward natural gas and foreign exchange contracts during the year (see Change in Accounting Policy in this MD&A).



Operating netbacks



The components of operating netbacks are shown below:



|                     |         |         |        
|-------------------- | ------- | ------- | -------
|Netback ($ per Mcf)  | 2006    | 2005    | 2004   
|Realized gas price   | $  7.52 | $  7.97 | $  6.40
|Royalties            | (1.18)  | (1.66)  | (1.11) 
|Operating costs      | (1.50)  | (1.20)  | (1.03) 
|Transportation costs | (0.21)  | (0.26)  | (0.26) 
|Netback              | $  4.63 | $  4.85 | $  4.00



PET pays Crown, freehold and overriding royalties that are dependent upon production volumes, commodity prices, location and age of producing wells and type of production.  Gas Crown royalties are reduced by Gas Cost Allowance



Page 15



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(GCA) deductions.  The GCA deductions are based on processing fees and allowable capital costs incurred at a property and are in accordance with Crown royalty regulations.  Royalty income received is included in revenue.  The effective royalty rate applicable to the Trust in 2006 was 15.7 percent (2005  20.9 percent) or $1.18 per Mcf (2005 - $1.66 per Mcf).  The decrease in royalty rate was primarily due to the Trusts realized natural gas price being significantly higher than the Alberta Gas Reference Price for the year as a result of gains from PETs hedging program.



Operating costs include all costs associated with the production of oil and natural gas from the wellhead to the point at which the product enters a sales pipeline for transport to market.  Field gathering and processing costs are also included in operating costs.  Revenue received from the processing of third party production at PETs facilities is netted against operating costs.



Operating costs totaled $84.0 million in 2006 as compared to $64.0 million in 2005. On a unit-of-production basis, operating costs increased by 25 percent to $1.50 per Mcf in 2006 from $1.20 per Mcf in 2005.  Operating costs increased as a result of an overall industry trend towards higher operating costs resulting from competitive conditions and a shortage of oilfield services and manpower, as well as higher property tax rates on the Trusts expanding productive acreage base. Much of the total operating costs in northeast Alberta relate to the ongoing operation and maintenance of facilities and other infrastructure and are fixed in nature. As PET continues to expand its facilities in these areas in order to tie in new wells and increase compression the related fixed costs of operations tend to increase.



Costs to transport gas from the plant gate to the commercial market sales point are not reflected as an operating cost but rather are recorded as transportation costs for the product.  Total transportation costs decreased by 13 percent to $11.9 million ($0.21 per Mcf) in 2006 from $13.7 million ($0.26 per Mcf) in 2005 as a result of the negotiation of natural gas sales contracts directly to end users proximal to the Trusts operations in northeast Alberta beginning in April 2006. These contracts benefit from reduced gas transportation costs.



General and administrative expenses



|                                 |        |       |        |       |        |      
|-------------------------------- | ------ | ----- | ------ | ----- | ------ | -----
|                                 | 2006   | 2005  | 2004  
|                                 | $000s | $/Mcf | $000s | $/Mcf | $000s | $/Mcf
|Cash general & administrative    | 16,635 | 0.30  | 11,807 | 0.22  | 8,279  | 0.22 
|Trust Unit-based compensation(1) | 3,337  | 0.06  | 1,993  | 0.04  | 2,374  | 0.06 
|Total general & administrative   | 19,972 | 0.36  | 13,800 | 0.26  | 10,653 | 0.28 

(1)  Non-cash item



General and administrative expenses (G&A) include costs incurred by PET which are not directly associated with the production of oil and natural gas.  The most significant components of G&A expenses are office staff compensation costs and information technology costs.  Field employee compensation costs are charged to operating expenses.  Overhead recoveries resulting from the allocation of administrative costs to partners are recorded as a reduction of G&A expenses.



G&A expenses, net of overhead recoveries on operated properties, increased to $20.0 million from $13.8 million in 2005 and increased on a unit-of-production basis from $0.26 per Mcf in 2005 to $0.36 per Mcf in 2006. The increase in 2006 is the result of a full year of general and administrative costs related to continued operation and development of the Northeast Alberta Assets, additional staffing with the Southern core area to enable effective development of the AcquireCo assets and fees and expenses related to Sarbanes Oxley initiatives. General and administrative expense related to PETs Sarbanes Oxley compliance project, including an allocation for internal resources, totaled $1.6 million in 2006. Trust Unit-based compensation also increased by $1.3 million in 2006 due to a higher number of incentive rights outstanding as compared to the prior year. PET uses the binomial lattice option pricing model to value unit incentive rights.



Interest expense



Interest and other expense increased to $11.7 million in 2006 from $8.3 million in 2005 as a result of a higher monthly average debt balance following the AcquireCo acquisition, in addition to higher interest rates as a result of the increase in the Bank of Canada lending rate during 2006.  On a unit-of-production basis, interest expenses were $0.21 per Mcf in 2006 as compared to $0.15 per Mcf in 2005.



In 2006, $10.4 million of interest on the Convertible Debentures was expensed as compared to $6.3 million in 2005.  The increase was due to the issuance of $100 million of the 6.25% Debentures in April 2006, and a full year of interest expense on the 6.25% Convertible Debentures (the 2005 6.25% Debentures) issued in April 2005.



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Depletion, depreciation and accretion



PETs 2006 depletion, depreciation and accretion (DD&A) rate increased to $3.56 per Mcf from $2.80 per Mcf in 2005 primarily due to the cost of the AcquireCo assets.  The Trust calculates its depletion factor using proved reserves for acquired properties, proved developed reserves for other properties and production volumes. Gas over bitumen deemed production is not included in the DD&A calculation.  The DD&A rate includes accretion expense on the asset retirement obligation of $7.2 million in 2006 as compared to $3.6 million in 2005.  The increase in accretion is a function of both higher production volumes and a significant increase in the asset retirement obligation at year-end 2005, which factored into accretion expense for 2006.  PETs asset retirement obligation increased from $94.3 million at December 31, 2005 to $109.4 million at December 31, 2006 due to the Trusts larger well base as a result of the AcquireCo acquisition and drilling activity during the year.



|                                         |         |         |        
|---------------------------------------- | ------- | ------- | -------
|Depletion, depreciation and accretion    |         |         |        
|($ thousands except per Mcf amounts)     | 2006    | 2005    | 2004   
|Depletion expense                        | 192,052 | 145,469 | 106,777
|Accretion of asset retirement obligation | 7,187   | 3,617   | 2,090  
|Total                                    | 199,239 | 149,086 | 108,867
|Per Unit-of-production ($/Mcf)           | 3.56    | 2.80    | 2.90   



At year-end 2006, property, plant and equipment costs included undeveloped land of $80.9 million (2005 - $83.9 million) currently not subject to depletion and $19.5 million (2005 - $32.5 million) of costs related to shut-in gas over bitumen reserves which are not being depleted due to the non-producing status of the wells in the affected properties.



Income taxes



The Trust and its principal operating entities are taxable entities under the Income Tax Act(Canada) and are taxable only on income that is not distributed or distributable to the Unitholders. As the Trust distributes all of its taxable income to the Unitholders pursuant to its Trust Indenture and meets the requirements of the Income Tax Act(Canada) applicable to the Trust, no provision for income taxes has been made relative to the Trust. The Administrator has no tax balances.



The Trusts corporate subsidiaries follow the tax liability method of accounting for income taxes. Under this method, income tax liabilities and assets are recognized for the estimated tax consequences attributable to differences between the amounts reported in the financial statements and their respective tax bases, using enacted income tax rates. The effect of a change in income tax rates on future income tax liabilities and assets is recognized in income in the period that the change occurs.



At December 31, 2006, the Trusts consolidated income tax pools are estimated as follows. Actual tax pool amounts will vary as tax returns are finalized and filed.



|                                      |           
|------------------------------------- | ----------
|Tax pool information                  | $ millions
|Canadian Oil and Gas Property Expense | 264       
|Canadian Development Expense          | 39        
|Canadian Exploration Expense          | 53        
|Undepreciated Capital Cost            | 156       
|Trust Unit Issue Costs                | 16        
|Non-capital Losses                    | 45        
|Total                                 | 573       



On October 31, 2006, the federal government announced its intentions to change the tax treatment for income trusts, introducing a tax on publicly traded income trusts and altering the personal tax treatment of trust distributions (the October 31 Proposals).  The October 31 Proposals were tabled through a Ways and Means Motion passed in the House of Commons on November 7, 2006 as the first step in the Parliamentary review process.



Under the October 31 Proposals effectively all distributions other than those comprising a return of capital to Unitholders would be subject to a 31.5 percent tax at the trust level as all distributions would no longer be deductible in computing trust taxable income. The personal tax on distributions would be reduced to a level similar to the tax paid on a dividend received from a taxable Canadian corporation.  The October 31 Proposals would effectively reduce income being distributed to PETs Unitholders, with the end result being a two-tiered tax structure similar to that of corporations.  At present, Canadian Pension Funds, Registered Retirement Savings Plans and Registered Retirement Income Funds ("Canadian Tax Deferral Entities") are not subject to tax on distributions.  Under the October 31 Proposals Canadian Tax Deferral Entities would be subject to tax as a result of the tax imposed at the trust level.  The October 31 Proposals would also significantly increase the tax for non-resident Unitholders due to the tax imposed at the trust level. If enacted, the October 31 Proposals would apply to PET effective January 1, 2011.



Page 17



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If the October 31 Proposals become enacted into law PET would record a significant future income tax liability, as the carrying values of the Trusts assets are well in excess of the related tax values.  As the October 31 Proposals are not yet enacted or considered substantively enacted, no future income tax liability has been recorded. For the entities within PETs structure that are not subject to tax, the carrying amount of assets within those entities is $171.7 million higher than the related tax basis.



Impairment test



PET performs impairment tests annually or as economic events dictate. An impairment loss is recognized when the carrying amount of a property is greater than the sum of the expected future cash flows (undiscounted and without interest charges) from that property. The amount of the impairment loss is calculated as the difference between the carrying amount and the present value of estimated future cash flows discounted at a rate that reflects the inherent risks in owning and developing oil and natural gas assets.



Although the sum of the expected future cash flows for the total of all of PETs assets greatly exceeds the carrying amount, cost recovery tests carried out at a property level as required by successful efforts accounting did identify an impairment at December 31, 2006. Application of this test at December 31, 2006 resulted in a reduction of the carrying value of PETs property, plant and equipment of $58.7 million. Such adjustments relate to prescribed determinations under the successful efforts method of accounting and should not be taken to represent indications of the fair market value of PETs assets or the possible impairment of such value.



This impairment charge arose in connection with the year end reserve evaluation in the Trusts east central Alberta and Saskatchewan cost centres. Based on the McDaniel Report PETs reserves in east central Alberta from the AcquireCo assets differ significantly from the Trusts internal evaluation. In addition, significant value included in the AcquireCo purchase price was attributed to the extensive prospect inventory generated by AcquireCo management and the pace of development has been tempered somewhat by weak gas prices. The purchase was negotiated in late 2005 at a time of rapidly rising natural gas prices and intense industry competition for such assets. PETs technical teams continue to aggressively develop the properties and are confident that their ultimate value will substantially exceed that assigned by the independent evaluators. Certain of the Trusts Saskatchewan properties have continued to perform below expectations and consequently the assigned reserves were reduced for 2006.



Net earnings (loss) and cash flow



Cash flow totaled $236.7 million ($2.82 per Trust Unit) for the year ended December 31, 2006 as compared to $260.2 million ($3.47 per Trust Unit) for the year ended December 31, 2005, an 19 percent decrease on a per Trust Unit basis.  The nine percent decrease in cash flow in 2006 is primarily the result of the six percent decrease in realized gas prices combined with the 25 percent increase in unit operating costs, higher general and administrative costs and higher  interest expense as compared to 2005, partially offset by a 26 percent decrease in royalties and a 13 percent decrease in transportation costs. The Trust also received $18.5 million of gas over bitumen royalty adjustments as compared to $30.6 million in 2005 due to the seven percent decrease in deemed production volumes and the 19 percent decrease in the Alberta Gas Reference Price.



|                                         |            |         |            |        
|---------------------------------------- | ---------- | ------- | ---------- | -------
|                                         | 2006       | 2005   
|Cash flow reconciliation                 | $ millions | ($/Mcf) | $ millions | ($/Mcf)
|Production volume (Bcf)                  |            | 56.0    |            | 53.3   
|Revenue                                  | 420.8      | 7.52    | 424.7      | 7.97   
|Royalties                                | (66.0)     | (1.18)  | (88.7)     | (1.66) 
|Operating costs                          | (84.0)     | (1.50)  | (64.0)     | (1.20) 
|Transportation costs                     | (11.9)     | (0.21)  | (13.7)     | (0.26) 
|Operating netback from production        | 258.9      | 4.63    | 258.3      | 4.85   
|Gas over bitumen royalty adjustments (1) | 3.6        | 0.06    | 30.6       | 0.57   
|Gas over bitumen revenue (3)             | 14.9       | 0.27    | -          | -      
|Lease rentals                            | (2.5)      | (0.05)  | (3.0)      | (0.06) 
|General and administrative (2)           | (16.6)     | (0.30)  | (11.8)     | (0.22) 
|Interest and other                       | (11.7)     | (0.21)  | (8.3)      | (0.16) 
|Interest on convertible debentures(2)    | (8.6)      | (0.15)  | (5.6)      | (0.10) 
|Current taxes                            | (1.3)      | (0.02)  | -          | -      
|Cash flow (2) (4)                        | 236.7      | 4.23    | 260.2      | 4.88   

(1) Net of gas over bitumen revenue

(2) Excludes non-cash items

(3)Gas over bitumen revenues relate to certain shut-in natural gas assets that were sold during the year, but for which PET continues to receive the monthly gas over bitumen royalty adjustments. See Gas over bitumen royalty adjustments in this MD&A.

(4)This is a non-GAAP measure, see Significant Accounting Policies and Non-GAAP Measures in this MD&A.



Page 18



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The Trust incurred a net loss of $18.9 million or $0.22 per Trust Unit in 2006 as compared to net earnings of $61.9 million or $0.82 per Trust Unit in 2005, as a result of the write-down of natural gas assets, lower cash flows and a higher DD&A rate partially offset by unrealized gains on financial instruments.



Fourth quarter information summary



|                                                                               |                                |          |         
|------------------------------------------------------------------------------ | ------------------------------ | -------- | --------
|Fourth quarter information                                                     | Three months ended December 31
|($ thousands except per Trust Unit, per Mcf and percent amounts)               | 2006                           | 2005     | % change
|Daily production volumes (MMcf/d)                                              | 144.6                          | 153.7    | (6)     
|                                                                               |                                |          |         
|Natural gas revenues                                                           | 94,564                         | 144,645  | (35)    
|Realized gains (losses) on financial instruments                               | 9,602                          | (15,412) | 162     
|Natural gas revenues, after financial hedging                                  | 104,166                        | 129,233  | (19)    
|Natural gas price, before financial hedging and physical forward sales ($/Mcf) | $  6.59                        | $ 11.41  |         
|Realized natural gas price ($/Mcf)                                             | $  7.83                        | $   9.14 | (14)    
|                                                                               |                                |          |         
|Royalties                                                                      | 13,164                         | 33,918   | (61)    
|Royalties as a percentage of revenues (%)                                      | 12.6                           | 26.2     | (52)    
|                                                                               |                                |          |         
|Operating expenses                                                             | 21,942                         | 16,837   | 30      
|Per Mcf                                                                        | $  1.65                        | $  1.19  | 39      
|                                                                               |                                |          |         
|General and administrative expenses                                            | 6,769                          | 3,349    | 102     
|Per Mcf                                                                        | $  0.51                        | $  0.24  | 113     
|                                                                               |                                |          |         
|Cash flow                                                                      | 58,166                         | 78,200   | (26)    
|Per Trust Unit                                                                 | $  0.69                        | $  0.96  | (28)    
|                                                                               |                                |          |         
|Net earnings (loss)                                                            | (68,254)                       | 17,899   | (481)   
|Per Trust Unit                                                                 | $  (0.80)                      | $  0.22  | (464)   
|                                                                               |                                |          |         
|Capital expenditures  exploration and development                             | 24,104                         | 11,402   | 111     



In comparing the fourth quarter of 2006 with the same period in 2005:



·

Production decreased six percent to 144.6 MMcf/d, primarily due to the extremely cold weather in early November that caused unexpected downtime at several facilities for an extended period.

·

Realized natural gas prices were 14 percent lower in the fourth quarter of 2006 as a result of lower AECO daily spot and monthly index prices compared to the three months ended December 31, 2005, offset somewhat by significant gains from the Trusts active hedging program.

·

The Trusts royalty rate decreased to 12.6 percent of revenues as realized natural gas prices were well above the Alberta Gas Reference Price.

·

General and administrative expenses increased from the fourth quarter of 2005 due primarily to $1.8 million in non-cash unit-based compensation expense recorded in the current quarter, as well as fees and expenses related to Sarbanes Oxley initiatives.

·

Operating costs increased 30 percent to $21.9 million as a result of generally higher costs for field services and supplies. On a unit-of-production basis operating costs increased 39 percent due to lower production volumes as compared to the prior period related to the extremely cold conditions in November which caused unexpected downtime at certain facilities, and $1.8 million in cost adjustments relating to prior periods received from a third party in the fourth quarter of 2006.

·

These factors combined to result in a 26 percent decrease in cash flow to $58.2 million from $78.2 million for the fourth quarter of 2005.

·

A net loss of $68.3 million was recorded for the three months ended December 31, 2006 as compared to net earnings of $17.9 million for the comparative period in 2005. The difference is due to $58.7 million in natural gas asset write-downs, lower cash flows and a higher depletion rate.



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LIQUIDITY, CAPITALIZATION AND FINANCIAL RESOURCES



|                                                        |                        |          
|------------------------------------------------------- | ---------------------- | ---------
|Capitalization and financial resources                  | Year ended December 31
|($ thousands except per Trust Unit and percent amounts) | 2006                   | 2005     
|Bank and other debt                                     | 228,657                | 168,106  
|Convertible debentures                                  | 157,391                | 64,888   
|Working capital deficiency (surplus) (2)                | 16,827                 | (1,131)  
|Net debt                                                | 402,875                | 231,863  
|Trust Units outstanding (thousands)                     | 85,186                 | 82,482   
|Market price at end of period                           | 12.40                  | 22.17    
|Market value of Trust Units                             | 1,056,306              | 1,828,626
|Total market capitalization (1)                         | 1,459,181              | 2,060,489
|Net debt as a percentage of total capitalization        | 27.6%                  | 11.3%    
|Cash flow (1)                                           | 236,653                | 260,218  
|Net debt to cash flow ratio                             | 1.7                    | 0.9      



(1)  These are Non-GAAP measures; see Significant accounting policies and non-GAAP measures in this MD&A.

(2) Working capital deficiency (surplus) excludes short-term financial instrument assets and liabilities.



At December 31, 2006, PET had bank debt outstanding of $228.7 million compared to $168.1 million at December 31, 2005 and $157.4 million in convertible debentures outstanding versus $64.9 million at December 31, 2005.  The increase in convertible debentures from 2005 levels is a result of the $100 million offering of 6.25% convertible debentures closed in April 2006 as funding for the AcquireCo acquisition.



PET has a revolving credit facility with a syndicate of six Canadian Chartered Banks.  As at the date of this MD&A the revolving credit facility had a borrowing base of $310 million.  The facility consists of a demand loan of $300 million and a working capital facility of $10 million. In addition to amounts outstanding under the facility, PET has outstanding letters of credit in the amount of $4.87 million as at the date of this MD&A. Collateral for the credit facility is provided by a floating-charge debenture covering all existing and after acquired property of the Trust as well as unconditional full liability guarantees from all subsidiaries in respect of amounts borrowed under the facility. The revolving feature of the Trust's credit facility expires on May 30, 2007, if not extended.   Pursuant to the terms of the credit agreement, the Trust will request that the facility be extended for 364 days and anticipates that this request will be granted.



Advances under the facility are made in the form of bankers acceptances (BA), prime rate loans or letters of credit.  In the case of BA advances, interest is a function of the BA rate plus a stamping fee based on the Trusts current ratio of debt to cash flow. In the case of prime rate loans, interest is charged at the lenders prime rate.  The average interest rate at December 31, 2006 was 5.2 percent.



Year end 2006 net debt to total capitalization was 27.6 percent (11.3 percent in 2005) and net debt to 2006 cash flow was 1.7 times (0.9 times in 2005). The increase in net debt in 2006 is largely due to the acquisition and development of the AcquireCo assets and distributions greater than the excess cash flow from operations after taking into consideration capital expenditures for the year.



The Trust expects that its distributions and capital expenditure program for 2007 will be funded by cash flow and proceeds from PETs DRIP plan however changes in natural gas prices, cash netbacks and production levels can affect future capital spending plans and distributions.



PETs future contractual obligations are summarized in the following table:



|                                    |                        |                  |           |           |              
|----------------------------------- | ---------------------- | ---------------- | --------- | --------- | -------------
|                                    | Payments due by period
|Contractual obligations ($millions) | Total                  | Less than 1 year | 2-3 years | 4-5 years | After 5 years
|Bank and other debt (1)             | 228.7                  | 223.3            | 0.8       | 0.9       | 3.7          
|Convertible debentures              | 161.2                  | -                | 5.9       | 155.3     | -            
|Pipeline commitments (2)            | 11.1                   | 4.9              | 2.2       | 0.5       | 3.5          
|Total contractual obligations       | 401.0                  | 228.2            | 8.9       | 156.7     | 7.2          



(1)The revolving feature of the Trust's credit facility expires on May 30, 2007, if not extended.   Pursuant to the terms of the credit agreement, the Trust will request that the facility be extended for 364 days and anticipates that this request will be granted.

(2) The Trust has long-term commitments to pay for gas transportation on certain major pipeline systems in western Canada.



Page 20



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Convertible debentures



As at December 31, 2006, the Trust had 6.25% convertible debentures issued in April 2006 (2006 6.25% Debentures), 6.25% convertible debentures issued in April 2005 (2005 6.25% Debentures) and 8% convertible debentures issued in July 2004 (8% Debentures) outstanding as follows:



|                                    |                |               |                   
|----------------------------------- | -------------- | ------------- | ------------------
|Convertible debentures series       | 2006  6.25%   | 2005  6.25%  | 8%                
|Principal outstanding ($ millions)  | 100.0          | 55.3          | 5.9               
|Maturity date                       | April 30, 2011 | June 30, 2010 | September 30, 2009
|Conversion price ($ per Trust Unit) | 23.80          | 19.35         | 14.20             
|Fair market value ($ millions)      | 99.0           | 54.7          | 5.9               



All series of debentures are redeemable by the Trust at a premium to face value, pay interest semi-annually and are subordinated to substantially all other liabilities of PET including the credit facility. Fair values of debentures are calculated by multiplying the number of debentures outstanding at December 31, 2006 by the quoted market price per debenture at that date.



During the year ended December 31, 2006, $2.6 million of 2005 6.25% Debentures and $1.5 million of 8% Convertible Debentures were converted resulting in the issuance of a total of 241,000 Trust Units.



Unitholders equity



PETs total capitalization was $1.46 billion at December 31, 2006 with the market value of the Trust Units representing 72.5 percent of total capitalization. During 2006, the market price of the Trust Units ranged from $11.58 to $22.59 with an average daily trading volume of 299,000 Units.



In February 2004, PET implemented a DRIP Plan for eligible Unitholders of the Trust.  The DRIP Plan provides Unitholders with the opportunity to reinvest monthly cash distributions to acquire additional Trust Units at 94 percent of the Treasury Purchase Price, which is defined as the daily volume weighted average trading price of the Trust Units for the 10 trading days immediately proceeding a distribution payment date (Treasury Purchase Price).  As well, subject to thresholds and restrictions described in the DRIP Plan, it contains a provision for the purchase by Canadian unitholders of additional Trust Units with optional cash payments of up to $100,000 per participant per fiscal year of PET at the same six percent discount to the Treasury Purchase Price.  No additional commissions, service or brokerage fees are charged to the Unitholder for these transactions.  In 2006 the DRIP Plan resulted in an additional 2,139,000 Trust Units (2005  2,854,000 Trust Units) being issued at an average price of $16.96 (2005 - $17.34) raising a total of $36.3 million (2005 - $49.5 million).



Weighted average Trust Units outstanding for 2006 totaled 83.9 million (2005  75.0 million). On December 31, 2006 there were 85.2 million Trust Units outstanding. In addition to issuances under the DRIP plan and through debenture conversions, 325,000 Trust Units were issued during 2006 by way of exercised incentive rights and bonus rights for net proceeds of $0.5 million.



CASH DISTRIBUTIONS



PET declared cash distributions of $221.8 million ($2.64 per Unit) in 2006 representing 94 percent of 2006 cash flow, bringing total cumulative distributions since inception to year-end 2006 to $671.3 million ($10.424 per Trust Unit).  In 2005, declared cash distributions were $205.0 million ($2.72 per Trust Unit), representing 79 percent of cash flow. The higher payout ratio in 2006 compared to 2005 is due to lower cash flows resulting from lower realized natural gas prices and higher operating costs.



Taxation of 2006 cash distributions



Cash distributions are comprised of a return of capital portion (tax deferred) and a return on capital portion (taxable).  For cash distributions received or receivable by a Canadian resident, outside of a registered pension or retirement plan in the 2006 taxation year, the split between the two is 95 percent taxable and 5 percent tax deferred.





Page 21



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|                                               |          |                     |              |    
|---------------------------------------------- | -------- | ------------------- | ------------ | ---
|2006 Distributions by month
($ per Trust Unit) | Canadian | Canadian Tax        |              |    
|                                               | Taxable  | Deferred Amount     | Total        |    
|Payment Date                                   | Amount   | (Return of capital) | Distribution |    
|February 15, 2006                              | 0.228    | 0.012               | 0.24         |    
|March 15, 2006                                 | 0.228    | 0.012               | 0.24         |    
|April 17, 2006                                 | 0.228    | 0.012               | 0.24         |    
|May 15, 2006                                   | 0.228    | 0.012               | 0.24         |    
|June 15, 2006                                  | 0.228    | 0.012               | 0.24         |    
|July 17, 2006                                  | 0.228    | 0.012               | 0.24         |    
|August 15, 2006                                | 0.190    | 0.010               | 0.20         |    
|September 15, 2006                             | 0.190    | 0.010               | 0.20         |    
|October 16, 2006                               | 0.190    | 0.010               | 0.20         |    
|November 15, 2006                              | 0.190    | 0.010               | 0.20         |    
|December 18, 2006                              | 0.190    | 0.010               | 0.20         |    
|January 15, 2007                               | 0.190    | 0.010               | 0.20         |    
|Total                                          | $  2.508 | $  0.132            | $  2.64      | (1)
|Percent                                        | 95       | 5                   | 100          |    



(1)  Total is based upon cash distributions declared during 2006.



2007 Cash distributions



PET adjusted its monthly distribution to $0.14 per Trust Unit per month in February 2007 and estimates that this level of monthly distributions will be sustained for the foreseeable future, based upon the Trusts forecasted cash flow based on current hedges, the forward market for natural gas prices and the Trusts future capital spending plans however distributions are subject to change as dictated by actual conditions.  The Trust estimates a payout ratio for 2007 of approximately 55 percent of cash flow, given current forward natural gas prices and the Trusts estimates for 2007 production and cash flow.



SUMMARY OF QUARTERLY RESULTS



|                                            |                    |               |               |             
|------------------------------------------- | ------------------ | ------------- | ------------- | ------------
|                                            | Three months ended
|(thousands of dollars, except where noted)) | Dec 31, 2006       | Sept 30, 2006 | June 30, 2006 | Mar 31, 2006
|                                            |                    |               |               |             
|Natural gas revenues before royalties       | $    94,564        | $    96,576   | $   97,856    | $ 112,639   
|Natural gas production (MMcf/d)             | 144.6              | 154.6         | 162.9         | 151.5       
|Cash flow                                   | $    58,166        | $    60,770   | $   56,605    | $   61,112  
|Per Trust Unit - basic                      | $        0.69      | $        0.72 | $       0.68  | $       0.74
|Net earnings (loss)                         | $ (68,254)         | $    19,619   | $   21,816    | $     7,969 
|Per Trust Unit - basic                      | $     (0.80)       | $        0.23 | $       0.26  | $       0.10
|- diluted                                   | $     (0.80)       | $        0.23 | $       0.26  | $       0.10
|Realized natural gas price ($/Mcf)          | $        7.83      | $        7.36 | $       6.85  | $       8.09
|Average AECO daily index price ($/GJ)       | $        6.54      | $        5.36 | $       5.71  | $       7.13



|                                           |                    |               |               |             
|------------------------------------------ | ------------------ | ------------- | ------------- | ------------
|                                           | Three months ended
|(thousands of dollars, except where noted) | Dec 31, 2005       | Sept 30, 2005 | June 30, 2005 | Mar 31, 2005
|                                           |                    |               |               |             
|Natural gas revenues before royalties      | $  144,645         | $  121,585    | $ 100,328     | $   75,947  
|Natural gas production (MMcf/d)            | 153.7              | 159.4         | 148.5         | 122.0       
|Cash flow                                  | $    78,200        | $    74,726   | $   66,491    | $   40,801  
|Per Trust Unit - basic                     | $        0.96      | $        0.95 | $       0.90  | $       0.62
|Net earnings                               | $    17,899        | $    30,339   | $   11,433    | $     2,199 
|Per Trust Unit - basic                     | $        0.22      | $        0.39 | $       0.16  | $       0.03
|- diluted                                  | $        0.22      | $        0.38 | $       0.15  | $       0.03
|Realized natural gas price ($/Mcf)         | $        9.14      | $        8.11 | $       7.42  | $       6.95
|Average AECO daily index price ($/GJ)      | $      10.72       | $        8.89 | $       6.99  | $       6.53





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Natural gas revenues have trended closely with the trend in natural gas prices over the eight quarters shown above; revenues are highest in the last two quarters of 2005 and lower in the final three quarters of 2006 as the AECO daily index dropped to an average of $5.87/GJ over that period.



The increased net earnings in the third and fourth quarters of 2005 as compared to prior quarters in 2005 and the first quarter of 2006 are due to higher production levels and natural gas prices, offset somewhat by higher royalties.  Gas over bitumen revenues of $13.7 million related to the sale of certain shut-in natural gas properties and unrealized gains on financial instruments of $14.0 million contributed to higher net earnings in the second and third quarters of 2006, respectively. The net loss in the fourth quarter of 2006 was a result of impairment charges at east central Alberta and Saskatchewan, higher DD&A expenses and higher operating costs as compared to previous quarters.



2007 OUTLOOK AND SENSITIVITIES



The following table shows PETs estimate of key measures for 2007 based on PETs hedging portfolio, production levels and the Trusts estimated exploration and development capital expenditures and targeted results for the year under several different AECO gas price assumptions.



|                                              |                                                 |       |       |      
|--------------------------------------------- | ----------------------------------------------- | ----- | ----- | -----
|                                              | Average AECO monthly index gas price ($/GJ) (4)
|Cash  flow outlook                            | $6.00                                           | $7.00 | $8.00 | $9.00
|Natural gas production (MMcf/d) (1)           | 153                                             | 153   | 153   | 153  
|Realized gas price ($/Mcf)                    | 7.48                                            | 8.03  | 8.59  | 9.15 
|Cash flow (2)($million)                       | 231                                             | 254   | 276   | 299  
|Per Trust Unit (2)($/Unit/month)              | 0.22                                            | 0.25  | 0.27  | 0.29 
|Payout ratio (2)(%)                           | 65                                              | 59    | 54    | 50   
|Ending net debt to cash flow ratio (3)(times) | 1.8                                             | 1.6   | 1.4   | 1.2  



(1)Annual production is based on the Trusts most recent estimates in February 2007.

(2)These are non-GAAP terms; please refer to Significant accounting policies and non-GAAP measures in this MD&A.

(3)Calculated as ending net debt (including convertible debentures) divided by annualized cash flow.

(4)Average forward AECO price for March-December 2007 as at March 6, 2007 was $7.79/GJ.



Below is a table that shows sensitivities of PETs 2007 estimated cash flow to operational changes and changes in the business environment:



|                                                  |             |                                    |        
|------------------------------------------------- | ----------- | ---------------------------------- | -------
|                                                  |             | Impact on cash flow per Trust Unit
|Cash flow sensitivity analysis ($ per Trust Unit) | Change      | Annual                             | Monthly
|Business Environment                              |             |                                    |        
|Price per Mcf of natural gas                      | $  0.25     | 0.07                               | 0.006  
|Interest rate on debt                             | 1%          | 0.03                               | 0.003  
|Operational                                       |             |                                    |        
|Gas production volume                             | 5 MMcf/d    | 0.09                               | 0.007  
|Operating costs                                   | $  0.10/Mcf | 0.07                               | 0.006  
|Cash G&A expenses                                 | $  0.10/Mcf | 0.07                               | 0.006  



The Trusts outlook and sensitivities assume operating costs of $1.40 per Mcf, cash G&A expenses of $0.34 per Mcf and an interest rate on bank debt of 5.25 percent. Cash G&A expenses are equal to G&A expenses before Trust Unit-based compensation.



SIGNIFICANT ACCOUNTING POLICIES AND NON-GAAP MEASURES



Successful efforts accounting



The Trust follows the successful efforts method of accounting for its petroleum and natural gas operations.  This method differs from the full cost accounting method in that exploration expenditures, including exploratory dry hole costs, geological and geophysical costs, lease rentals on undeveloped properties as well as the cost of surrendered leases and abandoned wells, are expensed rather than capitalized in the year incurred.  However, to make reported cash flow results comparable to industry practice, the Trust reclassifies geological and geophysical costs as well as surrendered leases and abandonment costs from operating to investing activities.





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Cash flow



Management uses cash flow provided by operating activities before changes in non-cash working capital, settlement of asset retirement obligations and certain exploration costs (cash flow) and cash flow per Trust Unit to analyze operating performance and leverage. Cash flow as presented does not have any standardized meaning prescribed by GAAP and therefore it may not be comparable to the calculation of similar measures for other entities.  Cash flow as presented is not intended to represent operating cash flow or operating profits for the period nor should it be viewed as an alternative to cash flow from operating activities, net earnings or other measures of financial performance calculated in accordance with GAAP.  Cash flow is reconciled to its closest GAAP measure, cash provided by operating activities, as follows:



|                                                      |                                |           
|----------------------------------------------------- | ------------------------------ | ----------
|                                                      | For the year ended December 31
|(thousands of dollars, except per Trust Unit amounts) | 2006                           | 2005      
|Cash provided by operating activities                 | $  227,254                     | $  237,349
|Exploration costs (1)                                 | 13,758                         | 16,850    
|Settlement of asset retirement obligations            | 3,095                          | 660       
|Changes in non-cash operating working capital         | (7,454)                        | 5,359     
|Cash flow                                             | $  236,653                     | $  260,218
|Cash flow per Trust Unit (2)                          | $  2.82                        | $  3.47   



(1)Certain exploration costs are added back to cash flow in order to be more comparable to other energy trusts that use the full-cost method of accounting for oil and gas activities. Exploration costs that are added back to cash flow include seismic expenditures, dry hole costs and expired leases and are considered by PET to be more closely related to investing activities than operating activities.

(2)Based on weighted average Trust Units outstanding for the period (2006  83.9 million, 2005  75.0 million).



Payout ratio



Payout ratio refers to distributions on Trust Units measured as a percentage of cash flow for the period and is used by management to analyze cash flow available for development and acquisition opportunities as well as overall sustainability of distributions.  Cash flow does not have any standardized meaning prescribed by GAAP and therefore payout ratio may not be comparable to the calculation of similar measures for other entities.



Operating and cash flow netbacks



Operating and cash flow netbacks are used by management to analyze margin and cash flow on each Mcf of natural gas production.  Operating and cash flow netbacks do not have any standardized meaning as prescribed by GAAP and therefore may not be comparable to the calculation of similar measures for other entities.  Operating and cash flow netbacks should not be viewed as an alternative to cash from operating activities, net earnings per Trust Unit or other measures of financial performance calculated in accordance with GAAP.



Revenue, including realized gains (losses) on financial instruments



Revenue, including realized gains (losses) on financial instruments is used by management to calculate the Trusts net realized natural gas price taking into account monthly settlements on financial forward natural gas sales and foreign exchange contracts. These contracts are put in place to protect PETs cash flows from potential volatility in natural gas prices, and as such any related realized gains or losses are considered part of the Trusts natural gas price. Revenue, including realized gains (losses) on financial instruments does not have any standardized meaning as prescribed by GAAP and should not be reviewed as an alternative to Revenue or other measures calculated in accordance with GAAP.



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Total capitalization



Total capitalization is equal to net debt including convertible debentures plus market value of issued equity and is used by management to analyze leverage.  Total capitalization as presented does not have any standardized meaning prescribed by Canadian GAAP and therefore it may not be comparable with the calculation of similar measures for other entities. Total capitalization is not intended to represent the total funds from equity and debt received by the Trust.



CRITICAL ACCOUNTING ESTIMATES



The MD&A is based on the Trusts consolidated financial statements which have been prepared in Canadian dollars in accordance with GAAP. The application of GAAP requires management to make estimates, judgments and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities, if any, at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. PET bases its estimates on historical experience and various other assumptions that are believed to be reasonable under the circumstances. Actual results could differ from these estimates under different assumptions or conditions.



Following is a discussion of the critical accounting estimates that are inherent in the preparation of the Trusts consolidated financial statements and notes thereto.



Accounting for petroleum and natural gas operations



Under the successful efforts method of accounting, the Trust capitalizes only those costs that result directly in the discovery of petroleum and natural gas reserves including acquisitions, successful exploratory wells, development costs and the costs of support equipment and facilities.  Exploration expenditures including geological and geophysical costs, lease rentals and exploratory dry holes are charged to earnings in the period incurred.  The application of the successful efforts method of accounting requires managements judgment to determine the proper designation of wells as either developmental or exploratory which will ultimately determine the proper accounting treatment of the costs incurred. The results of a drilling operation can take considerable time to analyze and the determination that proved reserves have been discovered requires both judgment and application of industry experience.  The evaluation of petroleum and natural gas leasehold acquisition costs requires managements judgment to evaluate the fair value of land in a given area.



Reserve estimates



Estimates of the Trusts reserves included in its consolidated financial statements are prepared in accordance with guidelines established by the Alberta Securities Commission. Reserve engineering is a subjective process of estimating underground accumulations of petroleum and natural gas that cannot be measured in an exact manner. The process relies on interpretations of available geological, geophysical, engineering and production data. The accuracy of a reserve estimate is a function of the quality and quantity of available data, the interpretation of that data, the accuracy of various mandated economic assumptions and the judgment of the persons preparing the estimate.



PETs reserve information is based on estimates prepared by its independent petroleum consultants. Estimates prepared by others may be different than these estimates.  Because these estimates depend on many assumptions, all of which may differ from actual results, reserve estimates may be different from the quantities of petroleum and natural gas that are ultimately recovered.  In addition, the results of drilling, testing and production after the date of an estimate may justify revisions to the estimate. The present value of future net revenues should not be assumed to be the current market value of the Trusts estimated reserves.  Actual future prices, costs and reserves may be materially higher or lower than the prices, costs and reserves used for the future net revenue calculations.  The estimates of reserves impact depletion, dry hole expenses and asset retirement obligations.  If reserve estimates decline, the rate at which the Trust records depletion increases thereby reducing net earnings. In addition, changes in reserve estimates may impact the outcome of PETs assessment of its petroleum and natural gas properties for impairment.



Purchase price allocation



Corporate acquisitions are accounted for by the purchase method of accounting whereby the purchase price is allocated to the assets and liabilities acquired based on their fair values, as estimated by management at the time of acquisition. The excess of the purchase price over the fair values represents goodwill. In order to estimate fair values, management has to make various assumptions, including commodity prices, reserves acquired and discount rates. Differences from these estimates may impact the future financial statements of the Trust.



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Impairment of petroleum and natural gas properties



The Trust reviews its proved properties for impairment on an operational field basis.  For each property, an impairment provision is recorded whenever events or circumstances indicate that the carrying value of that property may not be recoverable. The impairment provision is based on the excess of carrying value over fair value. Fair value is defined as the present value of the future net revenues from the property as estimated by the Trust on the balance sheet date.  Reserve estimates and estimates for natural gas prices and production costs may change and there can be no assurance that impairment provisions will not be required in the future.



Managements assessment of, among other things, the results of exploration activities, commodity price outlooks and planned future development and sales impacts the amount and timing of impairment provisions.



Asset retirement obligations



The asset retirement obligations recorded in the consolidated financial statements are based on an estimate of the fair value of the total costs for future site restoration and abandonment of the Trusts petroleum and natural gas properties. This estimate is based on managements analysis of production structure, reservoir characteristics and depth, market demand for equipment, currently available procedures, the timing of asset retirement expenditures and discussions with construction and engineering consultants.  Estimating these future costs requires management to make estimates and judgments that are subject to future revisions based on numerous factors including changing technology and political and regulatory environments.  PET engages an independent environmental consulting firm to analyze and prepare an annual estimate of the Trusts asset retirement obligations in accordance with National Instrument 51-101.  The asset retirement obligation does not include any adjustment for the net salvage value of tangible equipment and facilities.



CHANGE IN ACCOUNTING POLICY



Effective January 1, 2006 PET prospectively applied fair value accounting for all financial forward natural gas and foreign exchange contracts.  The Trust previously accounted for financial forward natural gas contracts using hedge accounting.  Accordingly, the fair values of these financial instruments as at January 1, 2006 were recorded on the Trusts balance sheet and amortized into earnings over the contractual life of the associated instrument.  Changes in fair value of these financial instruments from January 1, 2006 to December 31, 2006 as well as fair values of other financial forward natural gas and foreign exchange contracts as at December 31, 2006 are recorded to earnings.



The combination of the change in fair value during the year ended December 31, 2006 and amortization of the fair values recorded at January 1, 2006 was an unrealized gain on financial instruments of $24.9 million. Reconciliations of unrealized gains on financial instruments recorded in the statement of earnings and related balance sheet amounts are included in Note 12 to the consolidated financial statements as at and for the year ended December 31, 2006.



As the change in accounting policy was applied prospectively there is no related impact on earnings for periods related to 2005 and earlier.



NEW ACCOUNTING PRONOUNCEMENTS



In 2005 the CICA issued Handbook sections 1530 - Comprehensive Income, 3855 - Financial Instruments: Recognition and Measurement, 3861 - Financial Instruments: Disclosure and Presentation and 3865  Hedges which are effective for fiscal years beginning on or after October 1, 2006. These sections will apply to the Trust commencing January 1, 2007. Under these new standards all financial assets are measured at fair value with the exception of loans, receivables and investments that are intended to be held to maturity. Similarly, all financial liabilities should be measured at fair value when they are either derivatives or held for trading. Gains and losses on financial instruments measured at fair value will be recognized in earnings in the periods in which they arise, with the exception of gains and losses related to financial assets held for sale and financial instruments for which hedge accounting is applied.



Sections 1530, 3855 and 3865 introduce the term other comprehensive income, which comprises revenues, expenses, gains and losses that are excluded from net earnings. Unrealized gains and losses on qualifying hedging instruments and financial assets held for sale are recorded to other comprehensive income and reclassified to earnings when realized. Other comprehensive income and its components will be required disclosures under the new sections. Section 3855 also discusses the recognition and measurement of non-financial derivatives, and section 3861 addresses the related disclosure and presentation for these derivatives.



The Trust believes that under the new standards its portfolio of forward fixed-price natural gas physical delivery contracts will be recognized as non-financial derivatives. As such, these contracts will be fair valued at each balance sheet date, with the difference in fair values being recorded to net earnings... The fair value amount determined will be recorded as a financial asset or liability on the balance sheet on January 1, 2007 with a corresponding deferred gain or loss which will be amortized into earnings over the lives of the associated contracts.  The Trust is currently assessing other potential impacts of implementing these new sections.



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PROPOSED TRANSACTIONS



On February 28, 2007 the Trust entered into an agreement to acquire certain oil and gas properties in northeast Alberta for $46.5 million. The transaction is expected to close in March and will be financed from available credit facilities.



QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK



PETs operations are affected by a number of underlying risks, both internal and external to the Trust.  These risks are similar to those affecting others in both the conventional oil and gas royalty trust sector and the conventional oil and gas producers sector.  The Trusts financial position, results of operations, and cash available for distribution to Unitholders are directly impacted by these factors.



Income Taxes



The October 31 Proposals propose to apply a tax at the trust level on certain income from publicly traded mutual fund trusts at rates of tax comparable to the combined federal and provincial corporate tax and to treat distributions as dividends to the Unitholders. Existing trusts will have a four-year transition period and, subject to the qualification below, the new tax proposals will apply in January 2011.  Assuming the October 31 Proposals are ultimately enacted in the form currently proposed, the implementation of such proposals would be expected to result in adverse tax consequences to the Trust and certain Unitholders (including most particularly Unitholders that are tax exempt or non-residents of Canada) and may impact cash distributions from the Trust.



In light of the foregoing, the October 31 Proposals has reduced the value of the Trusts Units, which would be expected to increase the cost to PET of raising capital in the public capital markets for acquisition opportunities. In addition, the October 31 Proposals are expected to place PET and other Canadian energy trusts at a competitive disadvantage relative to industry competitors, including U.S. master limited partnerships, which will continue to not be subject to entity level taxation. There can be no assurance that PET will be able to reorganize its legal and tax structure to substantially mitigate the expected impact of the October 31 Proposals.



Further, the proposal plan provides that, while there is no intention to prevent normal growth during the transitional period, any undue expansion could result in the transition period being revisited, presumably with the loss of the benefit to the Trust of that transitional period. As a result, the adverse tax consequences resulting from the proposals could be realized sooner than 2011. On December 15, 2006, the Department of Finance issued guidelines with respect to what is meant by normal growth in this context. Specifically, the Department of Finance stated that normal growth would include equity growth within certain safe harbour limits, measured by reference to a Specified Investment Flow Throughs (SIFT) market capitalization as of the end of trading on October 31, 2006. The safe harbour calculation would include only the market value of the SIFTs issued and outstanding publicly-traded trust units, and not any convertible debt, options or other interests convertible into or exchangeable for trust units. Those safe harbour limits are 40% for the period from November 1, 2006 to December 31, 2007, and 20% each for calendar 2008, 2009 and 2010. These limits are cumulative, so that any unused limit for a period carries over into the subsequent period. Additional details of the Department of Finances guidelines include the following:



(i) new equity for these purposes includes units and debt that is convertible into units, and may include other substitutes for equity;



(ii) replacing debt that was outstanding as of October 31, 2006 with new equity, whether by a conversion into trust units of convertible debentures or otherwise, will not be considered growth for these purposes and will therefore not affect the safe harbour; and



(iii) the exchange, for trust units, of exchangeable partnership units or exchangeable shares that were outstanding on October 31, 2006 will not be considered growth for these purposes and will therefore not affect the safe harbour where the issuance of the trust units is made in satisfaction of the exercise of the exchange right by a person other than the SIFT.



The Trusts market capitalization as of the close of trading on October 31, 2006, having regard only to its issued and outstanding publicly-traded Trust Units, was approximately $1.4 billion, which means the Trusts safe harbour equity growth amount for the period ending December 31, 2007 is approximately $560 million, and for each of calendar 2008, 2009 and 2010 is an additional approximately $280 million, not including equity issued to replace debt that was outstanding on October 31, 2006, including convertible debentures.



These guidelines could adversely affect the Trusts access to capital, the cost of raising capital, and the Trusts ability to undertake more significant acquisitions. It is not known at this time when the October 31 Proposals will be enacted by Parliament or whether the October 31 Proposals will be enacted in the form currently proposed.





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Gas over bitumen issue



While we have no significant additional production recommended for shut-in by any party or the AEUB at this time and royalty adjustments are being received for production currently shut-in, we cannot ensure that additional production will not be shut-in in the future or that we 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.



Reserve estimates



Estimates of PETs 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 natural gas exists at a particular location and whether, and the extent to which, natural gas is recoverable from a reservoir.  The reliability of reserve estimates depends on:

·

whether the prevailing tax rules and other government regulations will remain the same as on the date estimates are made;

·

whether existing contracts remain the same as on the date estimates are made;

·

whether 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 natural gas can be sold;

·

the costs associated with recovering natural gas;

·

the prevailing environmental conditions associated with drilling and production sites;

·

the availability of enhanced recovery techniques; and

·

the ability to transport natural gas to markets.



Cyclical and seasonal impact on industry



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



Operational matters



The Trusts operations may be delayed or unsuccessful for many reasons including cost overruns, lower natural gas prices, equipment shortages, mechanical and technical difficulties and labour problems.  The Trusts 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 expected.  PET 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 natural gas could result in 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 costs of drilling, completing and operating wells are 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 and, consequently, delay operations.



Continuing production from a property, and to some extent marketing of production there from, are largely dependent upon the ability of the operator of the property.  Operating costs on most properties have increased significantly over recent years.  To the extent the operator fails to perform these functions properly, revenue may be reduced.  Payments from production generally flow through the operator and there is a risk of delay and additional expense in receiving such revenues if the operator becomes insolvent.  Although satisfactory title reviews are generally conducted in accordance with industry standards, such reviews do not guarantee or certify that a defect in the chain of title may not arise to defeat the claim of the Trust to certain properties.  A reduction in distributions on Trust Units could result in such circumstances.





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Expansion of operations



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



Acquisitions



The price paid for asset acquisitions is based on the Trusts internal assessment of the reserves and future production potential adjusted for risk. These assessments include a number of material assumptions regarding such factors as recoverability and marketability of oil and natural gas, future prices of oil and natural gas, and operating costs, future capital expenditures and royalties and other government levies which will be imposed over the producing life of the reserves.  Many of these factors are subject to change and are beyond the control of the operators of the working interests, management and the Trust.  In particular, changes in prices of and markets for petroleum and natural gas from those anticipated at the time of making such assessments will affect the amount of future distributions and as such the value of the Trust Units.  In addition, all such estimates involve a measure of geological and engineering uncertainty which could result in lower production and reserves than attributed to the working interests.  Actual reserves could vary materially from these estimates.  Consequently, the reserves acquired may be less than expected, which could adversely impact cash flows and distributions to Unitholders.



Debt service



Amounts paid in respect of interest and principal on debt will reduce distributions.  Variations in interest rates and scheduled principal repayments could result in significant changes in the amount required to be applied to debt service before payment of distributions.  Certain covenants of the agreements with PETs lenders may also limit distributions.  Although PET believes the credit facilities will be sufficient for the Trusts immediate requirements, there can be no assurance that the amount will be adequate for the future financial obligations of the Trust or that additional funds will be able to be obtained.



The lenders will be provided with security over substantially all of the assets of PET.  If PET becomes unable to pay its debt service charges or otherwise commits an event of default such as bankruptcy, the lender may foreclose on or sell the working interests.



Depletion of reserves



The Trust has certain unique attributes which differentiate it from other oil and gas industry participants.  Distributions, 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 and natural gas reserves.  PET will not be reinvesting cash flow in the same manner as other industry participants as one of the main objectives of the Trust is to maximize long-term distributions.  Accordingly, absent capital injections, PETs initial production levels and reserves will decline.



PETs future oil and natural gas reserves and production, and therefore its cash flows, will be highly dependent on PETs success in exploiting its reserve base and acquiring additional reserves.  Without reserves additions through acquisition or development activities, the Trusts reserves and production will decline over time as reserves are exploited.



To the extent that external sources of capital including the 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.  To the extent that PET is required to use cash flow to finance capital expenditures or property acquisitions, the level of distributions will be reduced.



There can be no assurance that PET will be successful in developing or acquiring additional reserves on terms that meet the Trusts investment objectives.



Net asset value



The net asset value of the assets of the Trust will vary from time to time dependent upon a number of factors beyond the control of management, including oil and natural gas prices.  The trading prices of the Trust Units from time to time are also determined by a number of factors that are beyond the control of management and such trading prices may be greater than the net asset value of the Trusts assets.





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Insurance risk



Exploration for natural gas and the production of natural gas are hazardous undertakings.  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 the Trusts revenues or increase costs and have a material adverse effect on the Trusts operations or financial condition.



PET may be unable to obtain insurance against these risks at premium levels that justify its purchase.  Further, insurance may be unavailable or 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 PETs financial position and reduce or eliminate distributions to Unitholders.



Additional financing



PETs primary source of bank financing is a demand credit facility with a syndicate of Canadian chartered banks in the amount of $310 million.  The credit facility is presently due May 30, 2007.  PET expects that the facility will be extended at that date.  If the facility is not extended the Trust will need to find alternative sources of financing.  If alternative sources of financing are not available, or are more expensive than the current credit facility, PET may be unable to effectively operate its business or pay distributions to Unitholders.



In the normal course of making capital investments to maintain and expand the oil and natural gas reserves of the Trust, additional Trust Units are issued from treasury which may result in a decline in production per Trust Unit and reserves per Trust Unit.  Additionally, from time to time the Trust issues Trust Units from treasury in order to reduce debt and maintain a more optimal capital structure.  Conversely, to the extent that external sources of capital, including the issuance of additional Trust Units, become limited or unavailable, the Trusts ability to make the necessary capital investments to maintain or expand its oil and natural gas reserves will be impaired.  To the extent that PET is required to use cash flow to finance capital expenditures or property acquisitions, to pay debt services charges or to reduce debt, distributions will be reduced.



Hedging



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

·

buying a price floor under which the Trust will receive a minimum price for natural gas production;

·

buying a collar under which the Trust will receive a price within a specified price range for natural gas production;

·

entering into fixed price contract for natural gas production; and

·

entering into contracts to fix the basis differential between natural gas markets.





If product prices increase above the levels specified in PETs various hedging agreements, the Trust would be precluded from receiving the full benefit of commodity price increases.



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

·

PET is unable to produce sufficient quantities of natural gas to fulfill its obligations;

·

PET is required to pay a margin call on a financial hedge contract; or

·

PET is required to pay royalties based on a market or reference price that is higher than its hedged fixed or ceiling price.



Non-resident ownership of Trust Units



In order for the Trust to maintain its status as a mutual fund trust under the Income Tax Act, the Trust intends to comply with the requirements of the Income Tax Act for mutual fund trusts at all relevant times.  In this regard, the Trust shall among other things, monitor the ownership of the Trust Units to carry out such intentions.  The Trust Indenture provides that if at any time the Trust becomes aware that the beneficial owners of 48 percent or more of the Trust Units then outstanding may be non-residents or that such a situation is imminent, the Trust shall take such actions as may be necessary to carry out the foregoing intention.



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Accounting write-downs as a result of GAAP



GAAP requires that management apply certain accounting policies and make certain estimates and assumptions that affect reported amounts in the consolidated financial statements of the Trust.  The accounting policies may result in non-cash charges to net income and write-downs of net assets in the financial statements.  Such non-cash charges and write-downs may be viewed unfavorably by the market and result in an inability to borrow funds and/or may result in a decline in the Trust Unit price.  The carrying value of property, plant and equipment, the carrying value of goodwill and the value of hedging instruments are some of the items which are subject to valuation and potential non-cash write-downs.



Renegotiation or termination of contracts



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



Competitive conditions



The Trust is a member of the petroleum industry which is highly competitive at all levels.  The Trust competes with other companies and other energy trusts for all of its business inputs including exploitation and development prospects, access to commodity markets, property and corporate acquisitions, and available capital.  The Trust endeavours to be competitive by maintaining a strong financial condition through attracting and retaining technically competent and accountable staff, by refining and enhancing business processes on an ongoing basis and by utilizing current technologies to enhance exploitation, development and operational activities.



Environmental considerations



Compliance with health, safety and environmental laws and regulations could materially increase the Trusts costs.  PET 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 third party sites where the Trusts products or wastes will be handled or disposed.



PET is 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 the Trusts licenses.  As a result, anyone who suffers losses or damages as a result of pollution caused by PETs operations can claim compensation without needing to demonstrate that the damage is due to any fault on the Trusts part.



New laws and regulations, tougher requirements in licensing, increasingly strict enforcement of, or new interpretations of, existing laws and regulations and 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.



For example, the Canadian government has adopted the 1997 Kyoto Protocol to the United Nations Framework Convention on Climate Change.  As a result, new requirements and regulations may be implemented which would require PET 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 the Trusts operations or financial condition.  Any abandonment costs PET incurs will reduce distributions to Unitholders.



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





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Government regulation risk



PET operates 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 distributions to Unitholders. Additional details with respect to the gas over bitumen regulatory issue are described elsewhere in this MD&A.



Commodity price, foreign exchange and interest rate risk



The two most important factors affecting the level of cash distributions available to Unitholders are the level of production achieved by PET, and the price received for its production.  These prices are influenced in varying degrees by factors outside the Trusts control.  Some of these factors include:

·

economic conditions which influence the demand for natural gas and the level of interest rates set by the governments of Canada and the U.S.;

·

weather conditions that influence the demand for natural gas;

·

transportation availability and costs; and

·

price differentials among markets based on transportation costs to major markets.



To mitigate these risks, PET has an active hedging program in place based on an established set of criteria that has been approved by the Board of Directors of the Administrator.  The results of the hedging program are reviewed against these criteria and the results actively monitored by the Board.



Beyond our hedging strategy, PET also mitigates risk by having a diversified gas marketing portfolio and by transacting with a number of counter-parties and limiting exposure to each counter-party.



The contracts that PET has with aggregators vary in length.  They represent a blend of domestic markets with fixed and floating prices designed to provide price diversification to our revenue stream.



Nature of Trust Units



The Trust Units do not represent a traditional investment in the oil and natural gas sector and should not be viewed by investors as shares in a corporation.  The Trust Units represent a fractional interest in the Trust.  As holders of Trust Units, Unitholders will not have the statutory rights normally associated with ownership of shares of a corporation.  The Trusts sole assets will be the royalty interests in the properties.  The price per Trust Unit is a function of anticipated distributable income, the properties acquired by PET and PETs ability to effect long-term growth in the value of the Trust.  The market price of the Trust Units will be sensitive to a variety of market conditions including, but not limited to, interest rates and the ability of the Trust to acquire stable oil and natural gas properties.  Changes in market conditions may adversely affect the trading prices of the Trust Units.



FORWARD-LOOKING INFORMATION



This MD&A contains forward-looking information with respect to PET.



The use of any of the words anticipate, continue, estimate, expect, may, will, project, should, believe, outlook and similar expressions are intended to identify forward-looking statements.  These statements involve known and unknown risks, uncertainties and other factors that may cause actual results or events to differ materially from those anticipated in our forward-looking statements.  We believe the expectations reflected in these forward-looking statements are reasonable.  However, we cannot assure the reader that these expectations will prove to be correct.  The reader should not unduly rely on forward-looking statements included in this report.  These statements speak only as of the date of the MD&A.



In particular, this MD&A contains forward-looking statements pertaining to the following:



·

the quantity and recoverability of PETs reserves;

·

the timing and amount of future production;

·

prices for natural gas produced;

·

operating and other costs;

·

business strategies and plans of management;

·

supply and demand for natural gas;

·

expectations regarding PETs access to  capital to fund its acquisition exploration and development activities;

·

the disposition swap, farm in, farm out or investment in certain exploration properties using third party resources;

·

the use of exploration and development activity and acquisitions to replace and add to reserves;



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·

the impact of changes in natural gas prices on cash flow after hedging;

·

drilling, completion, facilities and construction plans;

·

the existence, operations and strategy of the commodity price risk management program;

·

the approximate and maximum amount of forward sales and hedging to be employed;

·

the Trusts acquisition strategy, the criteria to be considered in connection therewith and the benefits to be derived there from;

·

the impact of Canadian federal and provincial governmental regulation on the Trust relative to other issuers;

·

PETs treatment under governmental regulatory regimes;

·

the goal to sustain or grow production and reserves through prudent asset management and acquisitions;

·

the emergence of accretive growth opportunities; and

·

PETs ability to benefit from the combination of growth opportunities and the ability to grow through the capital markets.



PETs actual results could differ materially from those anticipated in these forward-looking statements as a result of the risk factors set forth below and elsewhere in this MD&A which include but are not limited to:



·

volatility in market prices for natural gas;

·

risks inherent in PETs operations;

·

uncertainties associated with estimating reserves;

·

competition for, among other things; capital, acquisitions of reserves, undeveloped lands, skilled personnel, equipment for drilling, completions, facilities and pipeline construction and maintenance;

·

incorrect assessments of the value of acquisitions;

·

geological, technical, drilling and process problems;

·

general economic conditions in Canada, the United States and globally;

·

industry conditions including fluctuations in the price of natural gas;

·

royalties payable in respect of PETs production;

·

governmental regulation of the oil and gas industry, including environmental regulation;

·

fluctuation in foreign exchange or interest rates;

·

unanticipated operating events that can reduce production or cause production to be shut-in or delayed;

·

stock market volatility and market valuations; and

·

the need to obtain required approvals from regulatory authorities.



The above list of risk factors should not be construed as exhaustive.



Additional information on PET, including the most recent filed Annual Report and Annual Information Form, can be accessed at www.sedar.com or from the Trusts website at www.paramountenergy.com.







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