EXHIBIT 99.4

2004 Management Discussion and Analysis

The following is an amended managements discussion and analysis (MD&A) of Paramount Energy Trusts (PET) operating and financial results for the year ended December 31, 2004 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 amended audited consolidated financial statements for the years ended December 31, 2004 and 2003, together with accompanying notes. This MD&A is dated as of March 20, 2006.

The Trusts financial statements and MD&A as at and for year ended December 31, 2004 have been restated to reflect the use of the binomial lattice option pricing model to value unit incentives. PET believes the binomial lattice model provides a more accurate valuation of the unit incentives.  The Trust had previously used the intrinsic value method of accounting for unit incentives. The change and resulting impact on net earnings and balance sheet accounts is described more fully in the Financial Reporting and Regulatory Update section of this MD&A.

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 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.

Management uses cash flow (before changes in non-cash working capital) to analyze operating performance and leverage. Cash flow as presented does not have any standardized meaning prescribed by Canadian Generally Accepted Accounting Principles (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 Canadian GAAP. All references to cash flow throughout this amended MD&A are based on cash flow before changes in non-cash working capital.



Forward-looking Information

This amended 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.

In particular, this amended 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 ability to raise capital and to add to its reserves through acquisitions as well as through exploration and development;



the focus of capital expenditures on development activity rather than exploration;



the sale, farming in, farming out or development of certain exploration properties using third party resources;



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



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



drilling 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 of similar size;



PETs treatment under governmental regulatory regimes;



the goal to sustain or grow production and reserves through prudent 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



1

---





and elsewhere in this amended 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 and skilled personnel;



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.



Highlights

|                                                 |                 |         |       
|------------------------------------------------ | --------------- | ------- | ------
|(CDN$ millions, except per Unit and volume data) | 2004
(restated) | 2003    | 2002  
|Cash flow(1)                                     | $
143.6         | $
126.4 | $
59.7
|Cash flow per Unit                               | $
2.65          | $
2.97  | $
1.51
|Net earnings (loss)                              | $
(17.5)        | $
52.4  | $
7.4 
|Distributions                                    | $
121.3         | $
123.2 | $
n/a 
|Distributions per Unit                           | $
2.18          | $
2.884 | $
n/a 
|Payout ratio (%)                                 | 84.5%           | 97.5%   | n/a   
|Production (Mcfe/d)(2)                           |                 |         |       
|Daily average production                         | 102,472         | 85,574  | 94,842
|Gas over bitumen deemed production               | 16,724          | 3,198   | -     
|Total average daily (actual and deemed)          | 119,196         | 88,772  | 94,842



(1)

Before changes in non-cash working capital, includes gas over bitumen royalty adjustment

(2)

Production amounts are based on company interest before royalties

On February 5, 2004 PET closed the acquisition of producing natural gas properties in northeast Alberta for $30.3 million, effective January 1, 2004. This acquisition was financed from existing credit facilities.

On July 16, 2004 PET acquired Cavell Energy Corp. (Cavell) for consideration of 6,931,933 Trust Units with an ascribed value of $78.7 million plus acquisition costs, net of stock option proceeds of $8.0 million. Cavell was a public oil and gas exploration and production company active in Western Canada.

On August 17, 2004 the Trust closed an acquisition of producing petroleum and natural gas properties and assets in northeast Alberta (the



2

---



Athabasca Assets Acquisition) for an aggregate purchase price of $208.3 million ($197 million net of adjustments to the adjustment date of July 1, 2004). The acquisition was financed through the issuance of 7,795,547 Trust Units for gross proceeds of $96,275,005, in addition to the issuance of $48,000,000 in 
8.0% convertible extendible unsecured subordinated debentures (Convertible Debentures), and through existing credit facilities. Convertible Debentures in the amount of $9.6 million were subsequently converted into 674,711 Trust Units between August and December 2004.

On August 24, 2004 PET concluded the sale of the oil producing properties in Southeast Saskatchewan acquired as part of the Cavell acquisition for $32.75 million.

On September 30, 2004 PET closed the acquisition of producing petroleum and natural gas properties in the Saleski area of northeast Alberta for an aggregate purchase price of $20.0 million. The acquisition was financed through existing credit facilities and had an effective date of April 1, 2004.

Strong commodity prices, excellent drilling results and increased production volumes as a result of the above noted acquisitions resulted in record cash flow of $143.6 million ($2.65 per Trust Unit) in 2004 compared with $126.4 million ($2.97 per Trust Unit) for 2003. The year-over-year increase in cash flow of $17.2 million was due primarily to the above noted acquisitions. Despite the royalty reductions credited as per the gas over bitumen financial solution with the Crown, the Trusts cash flow was reduced by $9 million as a result of the gas over bitumen shut-ins.

PET declared distributions of $121.3 million in 2004 ($2.18 per Unit) and $123.2 million in 2003 ($2.884 per Unit), representing 
84 percent of 2004 cash flow and 97 percent in 2003.

The Trust successfully completed two major equity offerings in May 2004 and August 2004 netting $47.9 million and $91.5 million, respectively.

The Board of Directors of the Administrator of PET has approved a capital expenditure program of up to $45 million in 2005.

Evaluation of disclosure controls and procedures

The Chief Executive Officer, Clayton Riddell, and Chief Financial Officer, Cameron Sebastian, evaluated the effectiveness of PETs disclosure controls and procedures as of December 31, 2004 (the Evaluation Date) for the purpose of concluding whether or not PETs disclosure controls and procedures were effective to ensure that information PET is required to disclose in its filings with the Securities and Exchange Commission under the Securities Exchange Act of 1934 (the Exchange Act) is recorded, processed, summarized and reported, within the time periods specified in the Commissions rules and forms, and to ensure that information required to be disclosed by PET in the reports that it files under the Exchange Act is accumulated and communicated to PETs management, including its principal executive officer and principal financial officer, as appropriate to allow timely decisions regarding required disclosure. Based on that evaluation, the Chief Executive Officer and Chief Financial Officer concluded that the design and operation of these disclosure controls and procedures were not effective as the Registrant did not file its Form 40-F in a timely fashion for the year ended December 31, 2004.Changes to internal controls and procedures for financial reporting

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

Mechanics of creation of the Trust

PET was formed through a series of transactions as described below:

On February 3, 2003:

(1)

Paramount Operating Trust (POT) acquired the Legend property from Paramount Resources Ltd. (PRL) for an $81 million promissory note;

(2)

PET issued approximately 9.9 million Trust Units to PRL; and

(3)

PRL declared a dividend to be paid to its shareholders on February 12, 2003 of these Trust Units, at 1 Unit per 6.071646 shares, valued at $5.15 per Trust Unit, or approximately $0.85 per PRL Common Share.

On February 17, 2003:

(4)

PET issued 3 rights per Trust Unit to acquire additional Trust Units at $5.05 per Unit.

On March 11, 2003:

(5)

With proceeds of the rights offering of approximately 
$150 million, which was successfully closed with full subscription on March 10, 2003, plus bank debt, PET purchased from PRL the majority of PRLs remaining northeast Alberta natural gas assets for $220 million. The effective date of the property transactions was July 1, 2002 which, after adjustment for net cash flow and interest, resulted in the Trust assuming $70 million in bank debt.



Business plan and strategy

PET is a natural gas focused Canadian energy royalty trust actively managed to generate monthly cash distributions for Unitholders. The Trusts operations are based entirely in Canada with the majority of its core assets presently concentrated in northeast Alberta. PET is currently Canadas only 100 percent natural gas royalty trust.

PET seeks to be highly profitable, generating premium after-tax returns at an acceptable risk for all stakeholders. Maximizing total return to Unitholders in the form of cash distributions and change in Unit price is a paramount objective. Strategies for achieving this objective include attentive management of all costs and capital expenditures, prudent use of financial leverage, optimization of our existing asset base, infrastructure management, land stewardship and the pursuit of accretive acquisitions. At the same time, management also attempts to mitigate commodity price volatility through an active hedging and price management program.



3

---





PET has a strategy to focus its vision of accretive growth on existing core areas and pursue field optimization and cost control within those core areas to maximize asset value. The Trust strives to maximize control over its operations through operatorship whenever possible, and to maintain high working interests. PET operates over 90 percent of its production. PET believes this high level of operatorship can translate to control over costs, timing of capital outlays and projects as well as providing competitive advantages for future opportunities.

Corporate governance

PET is committed to maintaining high standards of corporate governance. Each regulatory body has a different set of rules pertaining to corporate governance 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. 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. Full disclosure of this compliance is provided in PETs information circular and on PETs website.

Gas over bitumen issue

Decision 2004-045, resulting from the Alberta Energy and Utilities Board (AEUB) Interim Hearing related to the ongoing gas over bitumen issue, was released June 8, 2004 and called for the shut-in of an additional 12.5 MMcf/d of PETs net gas production effective July 1, 2004. This decision, combined with gas shut-in since September 1, 2003 as a result of General Bulletin 2003-28, brought PETs total shut-in volumes to 17.2 MMcf/d. An additional 0.2 MMcf/d of production in the Chard and Leismer areas was shut-in September 1, 2004 as required by Shut-In Order 04-003. The total shut-in volume of 17.4 MMcf/d is significantly less than the approximate 44 MMcf/d of production initially targeted by the AEUB in 2003.

On October 4, 2004 the Government of Alberta enacted amendments to the Natural Gas Royalty Regulation (the Regulation) with respect to natural gas 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 recent bitumen conservation decisions. The Minister of Energy signed a Ministerial Order in late December prescribing the additional royalty calculation components retroactive to the dates of shut-in.

The Department of Energy issued an Information Letter 2004-36 (IL 2004-36) which, in conjunction with the Regulation, sets
out the details of the gas over bitumen financial solution. The formula for calculation of the royalty reduction provided in the Regulation is:

0.5 x [(deemed production volume x 0.80) x (Alberta Gas Reference Price - $0.4293/GJ)]

The deemed production volume includes all gas 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. The Trusts current net deemed production volume for purposes of the royalty adjustment is 
22.8 MMcf/d. According to IL 2004-36, the deemed production volume will be reduced by 10 percent at the end of every year 
of shut-in.

If gas production recommences from zones previously ordered to be shut-in, gas producers may pay an incremental royalty to the Crown on production from the reinstated pools along with Alberta Gas Crown Royalties otherwise payable. The incremental royalty will apply only to the pool or pools reinstated for production and will be established at 1 percent after the first year of shut-in increasing at 1 percent per annum based on the period of time such zones remained shut-in to a maximum of 10 percent. The incremental royalties payable to the Crown would be limited to amounts recovered by a gas well operator through the 
reduced royalty.

At December 31, 2004 the Trust had recorded $11.2 million on its balance sheet for cumulative gas over bitumen royalty adjustments to that date, 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. The royalty adjustments are being excluded from earnings pending such future determination. Royalty adjustments, although not included in earnings, are recorded as a component of funds from operations and as such are considered distributable income.

Lease rental remission will also be granted for a mineral licence or lease issued by the Crown that has a well or wells shut-in, according to IL 2004-36.

Parties wishing to contest the production status of an interval or intervals were required to file evidence with the AEUB by February 14, 2005 for a final hearing pursuant to Phase 3 of General Bulletin 2003-28. PET filed detailed evidence supporting the resumption of production for six pools representing approximately 8.5 MMcf/d of shut-in production or half of the production the Trust currently has shut-in pursuant to AEUB Orders. PET also reiterated to the AEUB its continued objection to all zones that have been shut-in as a result of the interim hearing, based on the new evidence that the Trust has submitted.

In addition, PET has reviewed the evidence submissions of all other parties and found that five additional producing wells, representing a total of less than 0.2 MMcf/d net to the Trust, have been further requested shut-in by other parties. As a result, PET concludes that it will have very little incremental gas beyond that already shut-in subject to review at the final hearing. Any changes in productive status resulting from the final hearing should result in increased gas production for PET. The AEUB intends to make final decisions and issue final orders, when appropriate, confirming the production status of every interval within the scope of the Phase 3 proceedings, including those intervals whose production status is not contested in the final hearing. PET anticipates final decisions will be issued in late 2005 or early 2006 after the conclusion of the final hearing which is currently scheduled to begin June 14, 2005.

Production volumes

Production volumes during 2004 averaged 102.5 MMcfe/d compared with 85.6 MMcfe/d in 2003, a 20 percent increase. The increase in production was attributed to the Marten Hills acquisition that was effective January 1, 2004 in addition to the acquisition of Cavell, the Athabasca acquisition, the Saleski property purchase and the results of the 2004 capital expenditure program. These acquisitions resulted in an increase in average 2004 production of approximately 63 MMcfe/d while the Trusts 2004 winter capital program added approximately 7 MMcf/d of production above the base case forecast in PETs independent reserve report.



4

---



In 2004, five properties located within the Trusts four core areas accounted for 41 percent of the Trusts production with one property accounting for 16 percent of the total production. This diversification of production minimizes the risk that operating problems at a specific property will materially impact the Trust.

Production

|                          |         |        |       
|------------------------- | ------- | ------ | ------
|                          | 2004    | 2003   | 2002  
|Natural gas (Mcf/d)       | 102,323 | 85,574 | 94,842
|Oil (Bbls/d)              | 25      | -      | -     
|Total Production (Mcfe/d) | 102,472 | 85,574 | 94,842



PET expects 2005 production to average approximately 122 MMcfe/d after incorporating production declines on existing properties and the positive impact of ongoing exploration and development activities on the assets. PET does not budget for acquisitions due to uncertainty regarding their completion and the timing thereof.

Commodity prices

Prices and marketing

|                                              |        |        |       
|--------------------------------------------- | ------ | ------ | ------
|                                              | 2004   | 2003   | 2002  
|Reference prices                              |        |        |       
|AECO gas ($/Mcf)                              | $
6.54 | $
6.70 | $
4.07
|Alberta Gas Reference Price ($/Mcf)           | $
6.28 | $
6.13 | $
3.88
|                                              |        |        |       
|Average PET prices                            |        |        |       
|Natural gas, before hedging ($/Mcfe)          | $
6.51 | $
6.39 | $
3.83
|% AECO, before hedging                        | 100%   | 95%    | 94%   
|% Alberta Gas Reference Price, before hedging | 104%   | 104%   | 99%   
|Natural gas, after hedging ($/Mcfe)           | $
6.40 | $
6.72 | $
3.83
|% AECO, after hedging                         | 98%    | 100%   | 94%   
|% Alberta Gas Reference Price, after hedging  | 102%   | 110%   | 99%   



U.S. natural gas prices are typically referenced off NYMEX at the Henry Hub, Louisiana while western Canada natural gas prices are referenced to the AECO Hub in Alberta. AECO Hub prices were $6.54 per Mcf and $6.70 per Mcf for 2004 and 2003 respectively; a decrease of two percent.

The Alberta Gas Reference Price is the monthly weighted average of an intra-Alberta consumers price and an ex-Alberta border price, 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 increased two percent from $6.13 per Mcf in 2003 to $6.28 per Mcf in 2004.

PETs average well head gas price, prior to hedging transactions, increased by two percent to $6.51 per Mcfe in 2004 from $6.39 per Mcfe in 2003. PETs average gas price after hedging transactions was $6.40 per Mcfe and $6.72 per Mcfe in 2004 and 2003 respectively.

Hedging and risk management

PETs hedging 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 distributable income 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. In addition hedging may be used to ensure or enhance the economics related to significant acquisitions. The Trust limits its hedging activity for any given period to 50 percent of forecast production for that period.



5

---





In 2004, the Trusts hedging activities resulted in a net payment of $4.3 million or $0.11 per Mcfe (2003 - $10.3 million net receipt: $0.33 per Mcfe). Activity in 2002 did not include any hedging as the 2002 results represent an allocation of the northeast Alberta operations of PRL.

Revenue

Oil and natural gas revenue in 2004 was $240.0 million, representing a 14 percent increase from $209.8 million in 2003. Revenue growth was achieved via higher natural gas volumes.

Revenue

|                                            |         |         |        
|------------------------------------------- | ------- | ------- | -------
|($ thousands)                               | 2004    | 2003    | 2002   
|Oil and natural gas revenue, before hedging | 244,303 | 199,488 | 132,631
|Hedging receipts (payments)                 | (4,346) | 10,318  | -      
|Total revenue                               | 239,957 | 209,806 | 132,631



Operating netbacks

A 2004 operating netback of $4.00 per Mcfe compared with $4.33 per Mcfe in 2003 reflected the five percent decline in realized natural gas prices and a 16 percent increase in unit 
operating costs.

Operating costs include all costs associated with the production of oil and natural gas from the time the well commences commercial production to the point at which the product enters a pipeline for transport. 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 increased by 40 percent (16 percent per Mcfe) to $38.8 million ($1.03 per Mcfe) in 2004 from $27.7 million ($0.89 per Mcfe) in 2003. Operating costs increased by $11.1 million in 2004 due to the increased production volumes related to the Marten Hills, Athabasca, and Cavell acquisitions. Unit costs increased as a result of ongoing fixed costs for facilities with lost production from the gas over bitumen shut-ins and an overall industry trend towards increasing operating costs resulting from competitive conditions and a shortage of oilfield services.

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 (GCA) deductions. The GCA deductions are based on processing fees and allowable capital cost 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 2004 was 17.3 percent (2003  18.2 percent) or $1.11 per Mcfe (2003  $1.22 per Mcfe).

Costs to transport the product from the wellsite to the commercial market are not reflected as an operating cost but rather are recorded as transportation costs for the product. Total transportation costs increased by 14 percent to $9.8 million ($0.26 per Mcfe) in 2004 from $8.6 million ($0.28 per Mcfe) in 2003. The increased transportation costs are a factor of the 20 percent increase in production from 2003 to 2004. In 2004, PET retroactively adopted the new accounting standard requiring that revenue be reported before transportation costs with separate disclosure of transportation costs in net earnings.

The components of operating netbacks are shown below:

Netback

|                     |        |        |       
|-------------------- | ------ | ------ | ------
|($ per Mcfe)         | 2004   | 2003   | 2002  
|Gas price            | 6.40   | 6.72   | 3.83  
|Royalties            | (1.11) | (1.22) | (0.63)
|Operating costs      | (1.03) | (0.89) | (0.87)
|Transportation costs | (0.26) | (0.28) | (0.26)
|Netback              | 4.00   | 4.33   | 2.07  



Shut-in gas over bitumen netbacks

A 2004 netback of $2.29 per Mcfe compared to $1.86 per Mcfe in 2003 reflected the gas over bitumen financial solution implemented at year end as a result of the amendments to the Natural Gas Royalty Regulation. The formula contained in the amended Regulation allows for a royalty adjustment of:

0.5 x [(deemed production volume x 0.80) x (Alberta Gas Reference Price -
$0.4293/GJ)]



6

---





Through this formula, operating costs are effectively deemed to be $0.45 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 an arbitrary 50 percent reduction factor. The components of netbacks for the gas over bitumen shut-in reserves can be derived 
as below:



Netback

|                                  |         |            |     
|--------------------------------- | ------- | ---------- | ----
|($ per Mcfe)                      | 2004(3) | 2003(1)(3) | 2002
|Average deemed volume (MMcf/d)(2) | 16.7    | 9.6        | -   
|Gas price                         | 6.28    | 5.20       | -   
|Royalties                         | (1.26)  | (1.04)     | -   
|Operating costs                   | (0.45)  | (0.45)     | -   
|Arbitrary multiplier              | (2.28)  | (1.85)     | -   
|Netback                           | 2.29    | 1.86       | -   



(1)

From September 1, 2003 to December 31, 2003

(2)

Represents an average of 14.6 MMcf/d of shut-in production (2003  7.5 MMcf/d) and 2.1 MMcf/d of wells denied production under AEUB ID 99-1 
(2003  2.1 MMcf/d)

(3)

All actual gas over bitumen royalty adjustments received in 2004, including retroactive payments for shut-in during the period September 1 through December 31, 2003, have been recorded as an adjusting item for cash flow from operations in 2004. Gas over bitumen royalty adjustments have not been restated for 2003

The deemed production volume includes all gas 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. The Trusts current net deemed production volume for purposes of the royalty adjustment is 
22.8 MMcf/d. According to Alberta Department of Energy Information Letter 2004-36, the deemed production volume will be reduced by 10 percent at the end of every year of shut-in.

General and administrative expense

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 employee compensation costs, office rent and gas over bitumen costs. Field employee compensation costs for field employees are charged to operating expenses. Overhead recoveries resulting from the allocation of administrative costs to joint venture partners are recorded as a reduction of 
G&A expenses.

G&A expenses, net of overhead recoveries on operated properties, increased to $10.7 million ($0.28 per Mcfe) in 2004 from 
$4.7 million ($0.15 per Mcfe) in 2003. The 2004 total included 
$1.2 million in legal and consulting expenditures directly related to the AEUB gas over bitumen issue (2003  $0.7 million). The Trusts financial statements as at and for year ended December 31, 2004 have been restated to reflect the use of the binomial lattice option pricing model to value unit incentives. PET believes the binomial lattice model provides a more accurate valuation of the unit incentives.  The Trust had previously used the intrinsic value method of accounting for unit incentives. This change and the resulting impacts on net earnings and balance sheet accounts are described more fully in the Financial Reporting and Regulatory Update section of this MD&A. The Trust Unit-based compensation costs were not restated for 2003. The Trust expects 2005 G&A costs excluding non-cash G&A to increase slightly as a result of a full year of increased G&A costs following the Cavell and Athabasca acquisitions and the increased capital expenditure program in 2005, offset by reduced costs associated with office rent as the 
Trust purchased the building occupied by its head office in November 2004.



|General and administrative expense
|----------------------------------
|                                  
|                                  
|Cash general & administrative     
|Gas over bitumen costs            
|Trust Unit compensation           
|Total general & administrative    





7

---





Interest expense

Interest expense increased to $4.8 million in 2004 from 
$2.4 million in 2003 as a result of a higher monthly average debt balance following the Cavell and Athabasca acquisitions. This was offset by a slightly lower interest rate as a result of the reduction of the Trusts Bankers Acceptance stamping fee rate from 
1.50 percent to 1.25 percent in August of 2004. Interest expense was minimized over the course of the year by financing debt through the issuance of lower cost Bankers Acceptances as opposed to borrowing at the prevailing bank prime interest rates.

On August 10th, the Trust issued $48 million of convertible debentures to finance the Athabasca acquisition. Throughout the remainder of the year, $9.6 million debentures were converted into 674,711 Trust Units. In 2004, $1.4 million of interest on the convertible debentures was expensed.

Depletion, depreciation and accretion

PETs 2004 depletion, depreciation and accretion (DD&A) rate increased to $2.90 per Mcfe from $2.01 per Mcfe in 2003, primarily due to the downward revisions in the Trusts proved reserves at December 31, 2004 and the reduction of proved reserves for the Trusts Saskatchewan assets acquired through the Cavell plan of arrangement during 2004. The Trust calculates its depletion factor using proved reserves and production and as such neither the shut-in gas over bitumen reserves nor the gas over bitumen royalty adjustment are included in the DD&A calculation. The DD&A rate includes accretion expense on the asset retirement obligation of $2.1 million in 2004 ($1.2 million in 2003).

Depletion, depreciation and accretion

|                                         |         |        |       
|---------------------------------------- | ------- | ------ | ------
|($ thousands except where noted)         | 2004    | 2003   | 2002  
|Depletion expense                        | 106,777 | 61,436 | 50,383
|Accretion of asset retirement obligation | 2,090   | 1,239  | 1,163 
|Total                                    | 108,867 | 62,675 | 51,546
|$/Mcfe                                   | 2.90    | 2.01   | 1.49  



Property, plant and equipment costs included undeveloped land of $72.5 million (2003 - $46.8 million) and $35.4 of costs related to shut-in gas over bitumen reserves which are currently not subject to depletion.



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.

Capital expenditures

Total capital expenditures, including net property and corporate acquisitions, aggregated to $425.1 million in 2004 ($310.5 million in 2003). Of the total, $28.9 million was incurred on drilling and completions, geological, geophysical and facilities expenditures, with the remaining $396.2 million attributable to net property and corporate acquisitions.

In late 2004 PET acquired the five storey office building in downtown Calgary, which has housed its offices since the formation of the Trust, from PRL for $10.5 million. The building which has an appraised value of $12.6 million provides effective facilities for the Trust, shields PET from escalating rental rates and provides potential for increasing real estate values.



8

---





A breakdown of capital expenditures by category is shown below:

Capital expenditures

|                                                |          |         |       
|----------------------------------------------- | -------- | ------- | ------
|($ thousands except where noted)                | 2004     | 2003    | 2002  
|Exploration and development expenditures        | 28,891   | 8,327   | 11,468
|Acquisitions                                    | 417,779  | 32,252  | -     
|Dispositions                                    | (32,750) | -       | -     
|Oil and gas properties acquired from PRL        | -        | 269,162 | -     
|Other                                           | 11,169   | 757     | 2,828 
|Total capital expenditures and net acquisitions | 425,089  | 310,498 | 14,296



The Board of Directors of the Administrator of PET has approved a capital budget for exploration and development expenditures of up to $45 million for 2005.

Cost recovery test

PET performs cost recovery 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.



The sum of the expected future cash flows for the total of all of PETs properties greatly exceeds the carrying amount of its property, plant and equipment. The successful efforts accounting methodology followed by PET prescribes that each constituent property be tested individually for impairment. Testing of the Saskatchewan property resulted in an impairment amount of $65.4 million as at December 31, 2004 and as a result the entire property, plant and equipment account of PET has been reduced by that amount through an additional charge to depletion and depreciation. 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 primarily in connection with the year-end reserve evaluation in the Trusts Saskatchewan property. The properties acquired in the Cavell acquisition in the West Central Saskatchewan and Abbey areas have been affected by technical and well performance difficulties. Consequently, assignment of reserves at December 31, 2004 was less than anticipated when evaluated by the Trusts independent reserve consultants. PETs technical teams continue to evaluate the properties in an ongoing effort to solve the technical challenges of this area.

At December 31, 2003, PET recorded a writedown of property, plant and equipment of $9.8 million related to the gas over bitumen issue. The estimated value of the reduced royalties associated with the gas over bitumen financial solution significantly exceeds the net book value of the shut-in reserves; therefore no further writedown for the shut-in reserves has been recorded in 2004.

Capitalization and financial resources

Capitalization and financial resources

|                                                        |           |        
|------------------------------------------------------- | --------- | -------
|($ thousands except per Trust Unit and percent amounts) | 2004      | 2003   
|Bank and other debt                                     | 171,698   | 55,564 
|Convertible debentures                                  | 38,419    | -      
|Working capital deficiency (surplus)                    | 2,611     | (2,196)
|Net debt                                                | 212,728   | 53,368 
|Trust Units outstanding (000s)                         | 65,327    | 44,638 
|Market price at end of period                           | 15.88     | 11.68  
|Market value of Trust Units                             | 1,037,392 | 521,371
|Total capitalization(1)                                 | 1,250,120 | 574,744
|Net debt as a percent of total capitalization           | 17.0%     | 9.3%   
|Cash flow                                               | 143,592   | 126,360
|Net debt to cash flow ratio                             | 1.5       | 0.4    

(1) 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.



9

---







PET commenced bank borrowing in March 2003. At December 31, 2004, PET had bank debt outstanding of $171.7 million compared with $55.6 million at December 31, 2003, $38.4 million in Convertible Debentures versus nil at December 31, 2003, and a working capital deficit of $2.6 million versus a working capital surplus of $2.2 million at the end of 2003. The 2004 year-end working capital deficit is a result of normal operating conditions in periods when the Trust incurs significant capital expenditures. PET participated in significant capital projects near the end of the year resulting in accrued capital expenditures of $7.6 million at December 31, 2004 compared with $1.2 million at December 31, 2003.

PET has a revolving credit facility with a syndicate of five Canadian Chartered Banks. As at the date of this report the revolving credit facility had a borrowing base of $220 million. The facility consists of a demand loan of $210 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 $2.85 million. 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.

Advances under the facility are made in the form of Bankers 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, 2004 was 3.78 percent.

December 31, 2004 net debt to total capitalization was 17.0 percent (9.3 percent in 2003) and net debt to 2004 cash flow was 
1.5 years (0.4 times in 2003) based upon cash flow from operations of $143.6 million and net debt of $212.7 million.

The Trusts current plans are to finance the approved 2005 capital budget of $45 million from cash flow.

A summary of contractual obligations is as follows:



TABULAR DISCLOSURE OF CONTRACTUAL OBLIGATIONS



|                        |                                        |           |           |                   |    
|----------------------- | -------------------------------------- | --------- | --------- | ----------------- | ---
|Contractual Obligations | Payments Due by Period
(CDN$ Millions)
|Total                   | Less than 1 Year                       | 1-3
Years | 3-5
Years | More than 5 Years
|Bank Debt               | $171.7                                 | $171.7    | ---       | ---               | ---
|Convertible Debentures  | $38.4                                  | ---       | ---       | $38.4             | ---
|Total                   | $210.1                                 | $171.7    | ---       | $38.4             | ---



Convertible debentures

On August 10, 2004, PET issued $48 million of Convertible Debentures for net proceeds of $46.1 million. The Convertible Debentures have a maturity date of September 30, 2009.

The Convertible Debentures bear interest at 8.0 percent per annum, paid semi-annually on March 31 and September 30 of each year and are subordinated to substantially all other liabilities of PET, including its credit facility. The Convertible Debentures are convertible at the option of the holder into PET Trust Units at any time prior to September 30, 2009 at a conversion price of $14.20 per Unit. The Convertible Debentures are not redeemable by PET on or before September 30, 2007 but may be redeemed in whole or in part at the option of PET at a price of $1,050 per Convertible Debenture after September 30, 2007 and prior to September 30, 2008 at a price of $1,025 per Convertible Debenture thereafter until their maturity. Redemption and conversions entitle the holder to accrued and unpaid interest to and including the effective date.

At the option of PET, the repayment of the principal amount of the Convertible Debentures may be settled in Trust Units. The number of Trust Units to be issued upon redemption by PET will be calculated by dividing the principal by 95 percent of the weighted average trading price. The interest payable may also be settled with the issuance and sale of sufficient Trust Units to satisfy the interest obligation. At December 31, 2004, $9.6 million in Convertible Debentures had been converted into 674,711 Trust Units and the fair market value of the outstanding Convertible Debentures was $43.9 million.

In 2004 PET early-adopted the new accounting rules in effect for fiscal years ending on or after November 1, 2004, which will require the Convertible Debentures to be disclosed as financial liabilities rather than equity on the balance sheet.

Unitholders equity

PETs total capitalization was $1,250.1 million at December 31, 2004 with the market value of the Trust Units representing 
83 percent of total capitalization. During 2004, the market price of the Trust Units ranged from $9.92 to $16.87 with an average daily trading volume of 268,000 Units.

PET implemented an industry-leading distribution reinvestment and optional Trust Unit purchase plan (DRIP Plan) for eligible Unitholders of the Trust in February 2004. The DRIP Plan provides Unitholders with the opportunity to reinvest monthly cash distributions to acquire additional Trust



10

---





Units at 94 percent of the Treasury Purchase Price, which is defined as the daily volume weighted average trading prices of the Trust Units for the 
10 trading days immediately proceeding a distribution payment date. As well, subject to thresholds and restrictions described in the DRIP Plan, it contains a provision for the purchase of additional Trust Units with optional cash payments of up to $100,000 per participant per fiscal year of PET to acquire additional Trust Units at the same six percent discount to the Treasury Purchase Price. No additional commissions, service or brokerage fees will be charged to the Unitholder for these transactions. The DRIP Plan resulted in an additional 632,829 Trust Units being issued in 2004 at an average price of $12.93 raising a total of $8.2 million.

On December 31, 2004 there were 65.3 million Trust Units outstanding. Trust Units were issued during 2004 as follows:



On May 18, 2004 PET closed an equity financing issuing 
4.5 million Trust Units at $11.20 per Unit for net proceeds of $47.9 million.



On July 16, 2004 PET issued 6.9 million Trust Units as a 
part of the Cavell acquisition at $11.35 for net proceeds of $78.7 million.



On August 10, 2004 PET closed an equity financing 
issuing 7.8 million Trust Units at $12.65 for net proceeds 
of $91.5 million.



During 2004, 0.2 million Trust Units were issued by way of exercised Incentive Rights for net proceeds of $1.5 million.



During 2004, 0.6 million Trust Units were issued through the DRIP Plan for net proceeds of $8.2 million.



In 2004, 0.7 million Trust Units were issued through the conversion of Convertible Debentures to Trust Units.

Cash distributions

PET declared cash distributions of $121.3 million ($2.18 per Unit) in 2004 representing 84 percent of 2004 cash flow, bringing total cumulative distributions since inception to $244.5 million, ($5.064 per Trust Unit). In 2003, declared cash distributions were 
$123.2 million ($2.884 per Trust Unit), representing 97 percent of cash flow.

Historical distributions by calendar year

|              |               |         |                  
|------------- | ------------- | ------- | -----------------
|Calendar Year | Distributions | Taxable | Return of Capital
|2004          | $
2.180       | 1.713   | 0.467            
|2003          | 2.884         | 1.500   | 1.384            
|Cumulative    | $
5.064       | 3.213   | 1.851            



Taxation of 2004 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 2004 taxation year, the split between the two is 78.58 percent taxable and 21.42 percent tax deferred.

PET, in consultation with its tax advisors, is of the view that the 2004 distributions paid to non-corporate Unitholders who are U.S. residents are Qualified Dividends for U.S. tax purposes. With respect to distributions paid in 2004, 82.39 percent would be reported as qualified dividends and 17.61 percent would 
be reported as non-taxable return of capital for U.S. Persons. PET performed an Earnings and Profits calculation for U.S. tax purposes in order to make this determination.



11

---





2004 Distributions by month ($ per Trust Unit)

|                   |                         |                                                  |                   
|------------------ | ----------------------- | ------------------------------------------------ | ------------------
|Payment Date       | Canadian Taxable Amount | Canadian Tax Deferred Amount (Return of Capital) | Total Distribution
|February 16, 2004  | $
0.157                 | $
0.043                                          | $
0.200           
|March 15, 2004     | 0.126                   | 0.034                                            | 0.160             
|April 15, 2004     | 0.126                   | 0.034                                            | 0.160             
|May 17, 2004       | 0.126                   | 0.034                                            | 0.160             
|June 15, 2004      | 0.126                   | 0.034                                            | 0.160             
|July 15, 2004      | 0.126                   | 0.034                                            | 0.160             
|August 16, 2004    | 0.141                   | 0.039                                            | 0.180             
|September 15, 2004 | 0.157                   | 0.043                                            | 0.200             
|October 15, 2004   | 0.157                   | 0.043                                            | 0.200             
|November 15, 2004  | 0.157                   | 0.043                                            | 0.200             
|December 15, 2004  | 0.157                   | 0.043                                            | 0.200             
|January 17, 2005   | 0.157                   | 0.043                                            | 0.200             
|Total              | $
1.713                 | $
0.467                                          | $
2.180(1)        
|Percent            | 78.58%                  | 21.42%                                           | 100.0%            



(1) Total is based upon cash distributions paid and payable during 2004

2005 Cash distributions

PET has declared three consecutive payments of $0.22 per Trust Unit in 2005 following implementation of the gas over bitumen financial solution announced by the Trust in January.

PET estimates that this level of monthly distributions of $0.22 per Unit per month will be sustainable for the foreseeable future, based upon the Trusts current hedges and the forward market for natural gas prices, however distributions are subject to change as dictated by actual conditions.



2005 Guidance and sensitivities

Based on current commodity prices, PETs hedging portfolio, production levels and exploration and development capital expenditure budget, following are PETs current estimates of its 2005 results:

|                                   |              |         |            
|---------------------------------- | ------------ | ------- | -----------
|                                   |              | 2004    | 2005E(1)(2)
|Natural Gas Production             | MMcf/d       | 103     | 120        
|Gas prices                         |              |         |            
|AECO Monthly Index                 | $/GJ         | $
6.46  | $
7.10     
|PET Realized                       | $/Mcf        | $
6.40  | $
7.50     
|Monthly cash flow                  | $/Unit/Month | $
0.205 | $
0.260    
|Monthly average distributions      | $/Unit/Month | $
0.182 | $
0.220    
|Payout ratio                       | %            | 84%     | 85%        
|Ending debt to 
cash flow ratio(3) | Times        | 1.5     | 1.0        



(1)

Cash flow incorporates royalty adjustments for gas over bitumen shut-in gas

(2)

Includes forward gas prices as of March 15, 2005, PET hedging activity and physical forward sales and PET contracts but no future acquisitions

(3)

Calculated as ending net debt, including Convertible Debentures as debt, divided by annualized cash flow



12

---





Below is a table that shows sensitivities of PETs 2005 cash flow to operational changes and changes in the business environment:

|                             |            |                                    |        
|---------------------------- | ---------- | ---------------------------------- | -------
|                             |            | Impact on Cash
Flow per Trust Unit
|                             | Change     | Annual                             | Monthly
|Business environment         |            |                                    |        
|Price per Mcf of natural gas |            |                                    |        
|(PET Avg.)                   | $
0.25/Mcf | 0.14                               | 0.012  
|Interest rate on debt        | 2%         | 0.05                               | 0.004  
|Operational                  |            |                                    |        
|Gas production volume        | 5 MMcf/d   | 0.13                               | 0.011  
|Operating costs              | $
0.10/Mcf | 0.07                               | 0.006  
|Cash G&A expenses            | $
0.10/Mcf | 0.07                               | $
0.006



These sensitivities assume operating costs of $1.10 per Mcf, cash general and administrative expenses of $0.15 per Mcf, and an interest rate on long term bank debt of 5.25 percent.

Financial reporting and regulatory update

There have been several changes in the financial reporting and securities regulatory environment in 2004 that have impacted PET and all public entities. Canadian securities regulators and the Canadian Institute of Chartered Accountants (CICA) are undertaking these measures to increase investor confidence through increased transparency, consistency and comparability of financial statements and financial information. As well, the changes have been brought about by a goal of aligning Canadian standards more closely with those in the United States.

The following new and amended standards were implemented by the Trust in 2004 and their impact is reflected in the 2004 financial statements:

Stock Based Compensation and Other Stock Based Payments   The Trusts financial statements as at and for year ended December 31, 2004 have been restated to reflect the
use of the binomial lattice option pricing model to value unit incentives. PET believes the binomial lattice model provides a more accurate valuation of the unit incentives.  The Trust had previously
used the intrinsic value method of accounting for unit incentives.



Under the fair value method using the binomial lattice model, compensation expense associated with Incentive Rights is recognized in earnings over the vesting period.  Consideration received upon the exercise of the Rights together with the amount previously recognized in contributed surplus is recorded as an increase in Unitholders capital.  The Trust has not incorporated an estimated forfeiture rate for Rights that will not vest, and accounts for actual forfeitures as they occur.



The effects of the change on balance sheet accounts as at December 31, 2004 are shown in the following table:



|                                      |                                 |                  |                     
|------------------------------------- | ------------------------------- | ---------------- | --------------------
|As at December 31, 2004
($ thousands) | Balance, as previously reported | Effect of change | Balance, as restated
|Contributed Surplus                   | 6,929                           | (2,393)          | 4,536               
|Unitholders Capital                  | 496,192                         | (330)            | 495,862             
|Accumulated earnings                  | 22,120                          | 2,621            | 24,741              





13

---





The effects of the change on G&A expenses and net earnings (loss) for each of the fiscal quarters in 2004 and for the year ended December 31, 2004 are as follows:



|                                                                              |          |         |        |        |         
|----------------------------------------------------------------------------- | -------- | ------- | ------ | ------ | --------
|                                                                              | 2004    
|($ thousands, except per Trust Unit amounts)                                  | Q4       | Q3      | Q2     | Q1     | Total   
|G&A expenses, including trust-unit based compensation, as previously reported | 2,817    | 5,424   | 2,361  | 2,010  | 12,612  
|Effect of change in stock-based compensation                                  | (789)    | (1,923) | (117)  | (290)  | (3,119) 
|G&A expenses, including trust-unit based compensation, as restated            | 2,028    | 3,501   | 2,244  | 1,720  | 9,493   
|Net earnings (loss), as previously reported                                   | (30,484) | 2,890   | 5,029  | 1,902  | (20,663)
|Effect of change in stock-based compensation                                  | 789      | 1,923   | 117    | 290    | 3,119   
|Net earnings (loss) as restated                                               | (29,695) | 4,813   | 5,146  | 2,192  | (17,544)
|Net earnings (loss) per Trust Unit, basic and diluted, as previously reported | $ (0.47) | $ 0.05  | $ 0.11 | $ 0.04 | $ (0.38)
|Net earnings (loss) per Trust Unit, basic and diluted, as restated            | $ (0.46) | $ 0.08  | $ 0.11 | $ 0.05 | $ (0.32)



Transportation Costs New accounting standards effective for fiscal years beginning on or after October 1, 2003 focus on what constitutes Canadian GAAP and its sources, including the primary sources of generally accepted accounting principles. In prior years, it had been industry practice to record revenue net of related transportation costs. In accordance with the new accounting standard, revenue is now reported before transportation costs with separate disclosure in the consolidated statement of earnings and accumulated earnings of transportation costs. This change in classification has no impact on net earnings, earnings per Trust Unit or working capital and the comparative figures have been restated to conform to the presentation adopted for the current year.

Hedging Relationships  In December 2001, the CICA issued Accounting Guideline 13 Hedging Relationships that deals with the identification, designation, documentation and measurement of effectiveness of hedging relationships for the purposes of applying hedge accounting. Accounting Guideline 13 is intended to harmonize Canadian GAAP with SFAS No.133 Accounting for Derivatives Instruments and Hedging Activities. The guideline is effective for fiscal years beginning on or after July 1, 2003.

Continuous Disclosure Obligations  Effective March 31, 2004, the Trust and all reporting issuers in Canada will be subject to new disclosure requirements as per National Instrument 51-102 Continuous Disclosure Obligations. This new instrument is effective for fiscal years beginning on or after January 1, 2004. The instrument proposes shorter reporting periods for filing of annual and interim financial statements, MD&A and the Annual Information Form (AIF). The instrument also proposes enhanced disclosure in the annual and interim financial statements, MD&A and AIF. Under this new instrument, it will no longer be mandatory for the Trust to mail annual and interim financial statements and MD&A to Unitholders, but rather these documents will be provided on an as requested basis. It is PETs intention to make these documents available on the Trusts website on a continuous basis.

Variable Interest Entities  In June 2003, the CICA issued Accounting Guideline 15 Consolidation of Variable Interest Entities which deals with the consolidation of entities that are subject to control on a basis other than ownership of voting interests. This guideline is effective for annual and interim periods beginning on or after November 1, 2004. The Trust has assessed that this new guideline is not applicable based on the current structure of the Trust and therefore will have no impact of financial statements of the Trust. However, this new guideline will be assessed in future periods to determine the applicability and resulting financial statement implications at that time.

Impact on net earnings of change in accounting policies

The implementation of a new accounting policy relating to asset retirement obligations has resulted in restatement of previously reported annual and quarterly net earnings. The restatement was required per the transitional provisions of the 
accounting standard.

The following table illustrates the impact of the new accounting policy on annual net income for the years and quarters which have been presented for comparative purposes:



|                                                              |                 |        |        |        |         
|------------------------------------------------------------- | --------------- | ------ | ------ | ------ | --------
|                                                              | 2004 (restated)
|($ thousands)                                                 | Q4              | Q3     | Q2     | Q1     | Total   
|Net earnings (loss) before changes in
accounting policies (1) | (29,695)        | 4,813  | 5,146  | 2,192  | (17,544)
|Increase (decrease) in net earnings                           |                 |        |        |        |         
|Asset retirement obligation (2)                               | -               | -      | -      | -      | -       
|Net earnings (loss) after change in accounting policies       | (29,695)        | 4,813  | 5,146  | 2,192  | (17,544)
|                                                              | 2003           
|($ thousands)                                                 | Q4              | Q3     | Q2     | Q1     | Total   
|Net earnings (loss) before changes in
accounting policies (1) | (2,574)         | 11,993 | 17,502 | 26,416 | 53,337  
|Increase (decrease) in net earnings                           |                 |        |        |        |         
|Asset retirement obligation (2)                               | (238)           | 323    | (518)  | (470)  | (903)   
|Net earnings (loss) after change in accounting policies       | (2,812)         | 12,316 | 16,984 | 25,946 | 52,434  



(1)

This represents net earnings as reported before retroactive restatement for changes in accounting policies.

(2)

The new accounting policy for asset retirement obligations was implemented in the fourth quarter of 2003. This new standard requires retroactive application with restatement of all periods presented for comparative purposes.



14

---





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.

Reserve estimates

The reserve and recovery information contained in PETs independent reserve evaluation is only an estimate. The actual production and ultimate reserves from the properties may be greater or less than the estimates prepared by the independent reserve evaluator. A significant portion of the principal properties acquired during 2004 have relatively short production histories which may make estimates on those properties more subject to revisions. The reserve report was prepared using certain commodity price assumptions that are described in the notes to the reserve tables. If lower prices for crude oil and natural gas are realized by the Trust and substituted for the price assumptions utilized in those reserve reports, the present value of estimated future net cash flows for the Trusts reserves would be reduced and the reduction could 
be significant.

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 operation of oil and gas wells involves a number of operating and natural hazards that may result in blowouts, environmental damage and other unexpected or dangerous conditions resulting in damages to operating subsidiaries of the Trust and possible liability to third parties. PET will maintain liability insurance, where available, in amounts consistent with industry standards. Business interruption insurance may also be purchased for selected facilities, to the extent that such insurance is available. PET may become liable for damages arising from such events against which it cannot insure or against which it may elect not to insure because of high premium costs or other reasons. Costs incurred to repair such damage or pay such liabilities will reduce distributable cash.

Continuing production from a property, and to some extent marketing of production therefrom, 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 of the distributions could result in such circumstances.

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 PETs 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 the future operational and financial condition of the Trust being adversely affected.

Acquisitions

The price paid for reserve acquisitions is based on engineering and economic estimates of the reserves made by independent engineers modified to reflect the technical views of management. 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



15

---







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 reserve 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.

Additional financing

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, the level of distributable income will be reduced.

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 (Canada), the Trust intends to comply with the requirements of the Income Tax Act (Canada) 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 50 percent or more of the Trust Units then outstanding are or may be non-residents of Canada or that such situation is imminent, the Trust shall take such actions as may be necessary to carry out the foregoing intention.

Accounting write-downs as a result of GAAP

Canadian 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, by 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

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.

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 amended 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 products. These prices are influenced in varying degrees by factors outside the Trusts control. Some of these factors include:



economic conditions that 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



16

---









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.

Management and financial reporting systems

The Trust continuously assesses and documents its management and internal reporting systems to provide assurance that accurate, timely internal and external information is gathered and disseminated.

The Trusts financial and operating results incorporate certain estimates including:

a)

estimated revenues, royalties and operating costs on production as at a specific reporting date but for which actual revenues and costs have not yet been received;

b)

estimated capital expenditures on projects that are in progress; and

c)

estimated depletion, depreciation and accretion costs that are based on estimates of oil and natural gas reserves which the Trust expects to recover in the future.

d)

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

e)

The net amount at which petroleum and natural gas costs on a property or project are carried is subject to a cost-recovery test annually or as economic events dictate. An impairment loss is recognized when the carrying amount of the asset is greater than the sum of the expected future cash flows (undiscounted and without interest charges). The amount of the impairment loss is calculated as the difference between the carrying amount and the discounted present value of estimated future cash flows. The carrying values of capital assets including the costs of acquiring proven and probable reserves are subject to uncertainty associated with the quantity of oil and gas reserves, future production rates, commodity prices and other factors.

The Trust has hired individuals and consultants who have the skill set to make such estimates and ensures individuals or departments with the most knowledge of the activity are responsible for the estimate. Further, past estimates are reviewed and compared to actual results in order to make more informed decisions on future estimates.

The PET management teams mandate includes ongoing development of procedures, standards and systems to allow PET staff to make the best decisions possible and ensuring those decisions are in compliance with the Trusts environmental, health and safety policies.



Historical Review

Financial and Operating Highlights(1)

| |                       
| | ----------------------
| | Year Ended December 31



|                                                           |                 |         |        
|---------------------------------------------------------- | --------------- | ------- | -------
|($CDN thousands, except volume and per Trust Unit amounts) | 2004
(restated) | 2003    | 2002   
|Financial                                                  |                 |         |        
|Operating revenue before royalties                         | 239,957         | 209,806 | 132,631
|Per Trust Unit(2)                                          | 4.43            | 4.93    | 3.35   
|Cash flow(3)                                               | 143,592         | 126,360 | 59,699 
|Per Trust Unit(2)                                          | 2.65            | 2.97    | 1.51   
|Net earnings (loss)(4)                                     | (17,544)        | 52,434  | 7,406  





17

---





|Per Trust Unit(2)  | (0.32)  | 1.23    | 0.19
|------------------ | ------- | ------- | ----
|Cash distributions | 121,314 | 123,202 | n/a 

|Per Trust Unit(5)                            | 2.18    | 2.884   | n/a    
|-------------------------------------------- | ------- | ------- | -------
|Total assets                                 | 556,711 | 260,984 | 277,348
|Net debt outstanding                         | 174,309 | 53,368  | n/a    
|Convertible debentures                       | 38,419  | -       | -      
|Unitholders equity                          | 264,451 | 166,065 | 235,880
|Capital expenditures                         |         |         |        
|Exploration, development and other           | 40,060  | 9,084   | 14,296 
|Acquisitions (net)                           | 385,029 | 32,252  | -      
|Trust Units outstanding (thousands)          |         |         |        
|End of period(7)                             | 65,327  | 44,638  | 39,638 
|Weighted average(7)                          | 54,188  | 42,597  | 39,638 
|Incentive rights                             | 1,613   | 1,146   | n/a    
|March 15, 2005                               | 66,113  | n/a     | n/a    
|Operating                                    |         |         |        
|Production                                   |         |         |        
|Oil and natural gas (Bcfe)                   | 37.5    | 31.2    | 34.6   
|Oil and natural gas (MMcfe/d)                | 102.5   | 85.6    | 94.8   
|Average prices                               |         |         |        
|Oil and natural gas ($/Mcfe), before hedging | 6.51    | 6.39    | 3.83   
|Oil and natural gas ($/Mcfe), after hedging  | 6.40    | 6.72    | 3.83   
|Reserves                                     |         |         |        
|Proved plus probable(6)                      |         |         |        
|Natural gas (Bcf)                            | 233.5   | 150.6   | 183.9  
|Land (thousands of net acres)                |         |         |        
|Undeveloped land holdings                    | 775     | 322     | 364    
|Drilling                                     |         |         |        
|Wells Drilled (gross)                        |         |         |        
|Gas                                          | 45      | 16      | 16     
|Service                                      | -       | 1       | 2      
|Dry                                          | 1       | -       | 2      
|Total                                        | 46      | 17      | 20     
|Success Rate                                 | 98      | 100     | 90     



19

---





Quarterly Review



Financial and Operating Highlights(1)

|                                                           |                  |            |          |            |         |         |         |        
|---------------------------------------------------------- | ---------------- | ---------- | -------- | ---------- | ------- | ------- | ------- | -------
|                                                           | 2004 (restated)  | 2003      
|($CDN thousands, except volume and per Trust Unit amounts) | Q4               | Q3         | Q2       | Q1         | Q4      | Q3      | Q2      | Q1     
|Financial                                                  |                  |            |          |            |         |         |         |        
|Operating revenue before royalties                         | 79,665           | 59,156     | 49,904   | 51,232     | 43,022  | 48,812  | 53,643  | 64,329 
|Per Trust Unit(2)                                          | 1.22             | 0.99       | 1.06     | 1.15       | 0.96    | 1.09    | 1.30    | 1.62   
|Cash flow(3)                                               | 56,521           | 31,301     | 29,913   | 25,857     | 25,138  | 29,844  | 33,567  | 37,811 
|Per Trust Unit(2)                                          | 0.87             | 0.52       | 0.62     | 0.58       | 0.52    | 0.67    | 0.81    | 0.95(1)
|Net earnings (loss)(4)                                     | (30,484)(29,695) | 2,8904,813 | 5,029146 | 1,9022,192 | (2,812) | 12,316  | 16,984  | 25,946 
|Per Trust Unit(2)                                          | (0.47)46)        | 0.0508     | 0.11     | 0.0405     | (0.06)  | 0.28    | 0.41    | 0.65   
|Cash distributions                                         | 39,135           | 35,925     | 22,973   | 23,281     | 26,783  | 29,015  | 34,504  | 32,900 
|Per Trust Unit(5)                                          | 0.60             | 0.58       | 0.48     | 0.52       | 0.60    | 0.65    | 0.804   | 0.83   
|Total assets                                               | 556,711          | 604,588    | 261,926  | 286,488    | 260,984 | 266,616 | 286,939 | 301,417
|Net debt outstanding                                       | 174,309          | 167,021    | 41,735   | 97,208     | 53,368  | 37,168  | 38,420  | 60,633 
|Convertible Debentures                                     | 38,419           | 45,251     | -        | -          | -       | -       | -       | -      
|Unitholders equity                                        | 264,451          | 322,559    | 177,593  | 146,032    | 166,065 | 229,437 | 219,570 | 175,989
|Capital expenditures                                       |                  |            |          |            |         |         |         |        
|Exploration, development and other                         | 23,415           | 1,260      | 234      | 14,701     | 1,043   | (733)   | 87      | 8,687  
|Acquisitions                                               | 3,641            | 348,434    | -        | 32,954     | 13,871  | (38)    | 12,419  | 6,000  
|Trust Units outstanding (thousands)                        |                  |            |          |            |         |         |         |        
|End of period(7)                                           | 65,327           | 64,567     | 49,409   | 44,799     | 44,638  | 44,638  | 44,638  | 39,638 
|Weighted average(7)                                        | 65,082           | 59,738     | 47,019   | 44,731     | 44,638  | 44,638  | 41,342  | 39,638 
|Operating                                                  |                  |            |          |            |         |         |         |        
|Production                                                 |                  |            |          |            |         |         |         |        
|Oil and natural gas (Bcfe)                                 | 11.8             | 9.6        | 8.0      | 8.1        | 7.5     | 8.1     | 8.0     | 7.6    
|Oil and natural gas (MMcfe/d)                              | 128.0            | 104.8      | 88.2     | 88.8       | 81.2    | 88.5    | 88.4    | 84.2   
|Average prices                                             |                  |            |          |            |         |         |         |        
|Oil and natural gas
($/Mcfe), before hedging               | 6.74             | 6.36       | 6.57     | 6.32       | 5.33    | 5.82    | 6.22    | 8.21   
|Oil and natural gas
($/Mcfe), after hedging                | 6.78             | 6.14       | 6.21     | 6.34       | 5.76    | 6.00    | 6.67    | 8.48   





(1)

All amounts in this report include the operations and results of the northeast Alberta properties of Paramount Resources Ltd. (PRL) which were acquired by PET during the three months ended March 31, 2003. The consolidated financial statements have been prepared on a continuity of interests basis which recognizes PET as the successor entity to PRLs northeast Alberta core area of operations as PET acquired substantially all of PRLs natural gas assets in that region.

(2)

Based on weighted average Trust Units outstanding for the period.

(3)

Management uses cash flow (before changes in non-cash working capital) to analyze operating performance and leverage. Cash flow 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. 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 Canadian GAAP. All references to cash flow throughout this report are based on cash flow before changes in non-cash working capital and include gas over bitumen royalty adjustments for shut-in production.

(4)

Net earnings for 2002 have been restated to reflect the retroactive application of a change in accounting policy relating to Asset Retirement Obligations.

(5)

Based on Trust Units outstanding at each cash distribution date.

(6)

As evaluated by McDaniel & Associates Consultants Ltd. in accordance with National Instrument NI 51-101. 2002 figures are proved plus 1⁄2 probable for comparability 
under NI 51-101.

(7)

The Trust Units indicated for periods prior to March 31, 2003 are pro forma. Actual Units were issued by PET in the first and second quarters of 2003. 9.9 million Units were issued to PRL on February 3, 2003 which in turn issued these Units to shareholders as a dividend in-kind. 29.7 million Units were issued March 10, 2003 pursuant to a Rights Offering.



20

---