FINANCIAL AND OPERATING HIGHLIGHTSThree months ended
December 31Year ended
December 31($CDN thousands, except volume and per Trust Unit amounts)20052004%
Change20052004%
ChangeFINANCIALRevenue before royalties129,23379,66562424,741239,95777Cash flow (2)78,20056,52138260,218143,59281Per Trust Unit (1) (2)0.960.87103.472.6531Net earnings (loss)17,928(29,696)16061,870(17,544)453Per Trust Unit (1)0.22(0.46)1480.82(0.32)356Cash distributions58,99039,13551205,032121,31469Per Trust Unit (3)0.720.60202.722.1825Total assets820,408556,71147820,408556,71147Net bank and other debt outstanding (7)166,975176,082(5)166,975176,082(5)Convertible debentures64,88838,4196964,88838,41969Total net debt231,863214,5018231,863214,5018Unitholders equity394,643264,45149394,643264,45149Capital expendituresExploration and development11,4022,24740759,89628,891107Acquisitions, net8814,141(99)279,671385,029(27)Other71811,118(94)1,26711,169(89)Net capital expenditures12,20827,506(55)340,834425,089(20)TRUST UNITS OUTSTANDING (thousands)End of period82,48265,3272682,48265,32726Weighted average81,62565,0822574,99854,18838Diluted82,80465,0822775,73854,18840February 28, 200683,29183,291




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FINANCIAL AND OPERATING HIGHLIGHTS CONTINUEDThree Months Ended
December 31Year Ended
December 3120052004%
Change20052004%
ChangeOPERATINGProductionTotal natural gas (Bcf)14.111.81953.337.542Daily average natural gas (MMcf/d)153.7128.020146.0102.542Gas over bitumen deemed production (MMcf/d)21.622.8(5)22.416.734Average daily (actual and deemed  MMcf/d)175.3150.816168.4119.241Per Trust Unit (cubic feet/d/Unit) (1)2.152.32(7)2.252.202Exit rate (actual and deemed  - MMcf/d)(8)173.6146.518173.6146.518Per Trust Unit (cubic feet/d/Unit) (4)2.102.24(6)2.102.24(6)Average pricesNatural gas ($/Mcf), before hedging10.186.74518.306.5127Natural gas ($/Mcf), including hedging9.146.78357.976.4025RESERVES (Bcf)Proved (5) (6)195.8181.48195.8181.48Proved plus probable (5) (6)282.7233.521282.7233.521Per Trust Unit (Mcf/Unit) (4)3.433.58(4)3.433.58(4)Estimated present value before tax ($ millions) (6)Proved849.6518.064849.6518.064Proved plus probable1,041.9606.2721,041.9606.272LAND (thousands of net acres)Total land holdings2,4201,917262,4201,91726Undeveloped land holdings1,022775321,02277532DRILLINGWells Drilled (gross/net)Gas15/7.722/5.8(32)/33102/54.645/28.5127/92Dry-1/0.4-/-4/4.01/0.4300/900Total15/7.723/6.2(34)/24106/58.646/28.9130/103Success Rate100/10096/944/696/9398/99(2)/(6)




(1)

Based on weighted average Trust Units outstanding for the period.

(2)

This is a non-GAAP measure; please refer to Significant Accounting Policies and Non-GAAP Measures included in Managements Discussion and Analysis.

(3)

Based on Trust Units outstanding at each cash distribution date.

(4)

Based on Trust Units outstanding at period end.

(5)

As evaluated by McDaniel & Associates Consultants Ltd. in accordance with National Instrument 51-101. See Reserves included in Managements Discussion and Analysis.

(6)

Discounted at 10% using consultants forecast pricing. Includes gas over bitumen royalty adjustments (2005 - $100.9 million, 2004 - $82.7 million) and gas over bitumen shut-in reserves (proved: 2005  nil, 2004  12.0 Bcf and $8.7 million; proved plus probable: 2005  25.1 Bcf and $25.8 million, 2004  24.0 Bcf and $17.1 million).

(7)

Net debt includes net working capital.

(8)

Exit production is average production from last month in period.







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MANAGEMENTS DISCUSSION AND ANALYSIS



The following is managements discussion and analysis (MD&A) of Paramount Energy Trusts (PET or the Trust) operating and financial results for the year ended December 31, 2005 as well as information and estimates concerning the Trusts future outlook based on currently available information.  This discussion should be read in conjunction with the Trusts audited consolidated financial statements for the years ended December 31, 2005 and 2004, together with accompanying notes.  Readers are referred to the legal advisories regarding forward-looking information contained in the Forward Looking Information section of this MD&A.  The date of this MD&A is March 20, 2006.



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



EVALUATION OF DISCLOSURE CONTROLS AND PROCEDURES



The Chief Executive Officer, Susan Riddell Rose, and Chief Financial Officer, Cameron Sebastian, evaluated the effectiveness of PETs disclosure controls and procedures as of December 31, 2005 (the Evaluation Date), and concluded that 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.



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.



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 Management Information Circular dated March 21, 2006 and on PETs website.



FOURTH QUARTER HIGHLIGHTS



·

Production averaged 153.7 MMcf/d, a 20 percent increase from 128.0 MMcf/d for the fourth quarter of 2004. Cash flow reached a record $78.2 million for the quarter or $0.96 per Trust Unit, up 38 percent (10 percent on a per unit basis) from $56.5 million or $0.87 per Trust Unit in the fourth quarter of 2004.



·

PET planned and began the execution of an $80 million winter capital program, the largest in the Trusts history, targeting 25-35 MMcf/d of natural gas production additions through drilling, completion, tie-in and seismic acquisition activities spread throughout the Trusts three core areas in Northeast Alberta.



·

Distributions for the fourth quarter of 2005 totaled $0.72 per Trust Unit, paid on November 15, 2005, December 15, 2005 and January 16, 2006. PETs payout ratio for the quarter was 75.4% of its cash flow.



·

In November 2005, the Alberta Energy and Utilities Board (AEUB) issued its final bitumen conservation decision. Decision 2005-122 had minimal impact on the Trust, targeting one additional well, producing less than 50 Mcf/d net to PET, for shut-in effective January 1, 2006.  Also shut-in PET wells with a productive capacity of less than 200 Mcf/d net to PET were approved for production, for a net potential gain to the Trust's production of approximately 150 Mcf/d as a result of the decision.





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·

On December 23, 2005 PET announced its intent to acquire a private company (AcquireCo) engaged in natural gas exploration and development in east-central Alberta, for an estimated cost including assumption of net debt of $92 million. This transaction closed as scheduled on February 16, 2006. Production from the AcquireCo assets is over 90% operated and measured approximately 9.5 MMcf/d as at the closing date. The AcquireCo properties are located southeast of PETs Athabasca core area, and offer over 50 shallow gas drilling and development prospects on 54,600 net acres of undeveloped year-round access lands.



ANNUAL HIGHLIGHTS



(CDN$ millions, except per Unit and volume data)200520042003Cash flow (1)$   260.2$   143.6$   126.4Cash flow per Unit$     3.47$     2.65$     2.97Net earnings (loss)$     61.9$   (17.5)$     52.4Distributions$   205.0$    121.3$   123.2Distributions per Unit$     2.72$      2.18$   2.884Payout ratio (%) (1)78.8%84.5%97.5%Production (Mcf/d) (2)Daily average production146,031102,47285,574Gas over bitumen deemed production22,41316,7243,198Total average daily (actual and deemed)168,444119,19688,772




(1)

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

(2)

Production amounts are based on company interest before royalties.

·

During the first quarter of 2005 PET completed the execution of a $40 million winter capital program in Northeast Alberta which included the drilling of 39 gas wells and over 150 recompletions distributed throughout the Trusts three core areas in the region. Approximately 18 MMcf/d of new production was brought onstream from the winter program by the end of the first quarter. PET followed up its successful winter program with a $15 million capital program targeting production and reserve additions from the year-round access assets in the Southern core area. Over the final three quarters of 2005 PET drilled 67 wells (27.8 net) with a 96% success rate, including participation in 43 wells (6.4) net in a non-operated coal bed methane project in the Craigmyle area of Southern Alberta.

·

On May 17, 2005 PET closed the acquisition of 100% shallow natural gas producing properties in Northeast Alberta (the Northeast Alberta Assets) for $273.5 million. The Northeast Alberta Assets are in close proximity to the Trusts Northeast Alberta Core Areas but well outside the defined boundaries of the AEUB gas over bitumen area of concern.  The Northeast Alberta Assets added 87 Bcf of proved plus probable reserves and produced an average of 40.5 MMcf/d for the period from the date of acquisition.



·

Concurrent with the acquisition of the Northeast Alberta Assets (the Northeast Alberta Acquisition), PET also entered into an agreement to sell on a bought deal basis, 9,500,000 subscription receipts at a price of $16.85 each for gross proceeds of approximately $160 million, and $100 million of five-year 6.25% convertible debentures (the 6.25% Debentures) to a syndicate of underwriters.  The 6.25% Debentures are convertible into units of PET (Trust Units) at a price of $19.35 per Trust Unit.  The offering closed as scheduled on April 26, 2005.  The Subscription Receipts were converted into Trust Units on the closing of the Northeast Alberta Acquisition.



·

PET recorded average production of 146.0 MMcf/d, a 42 percent increase and a 3 percent increase per weighted average Trust Unit outstanding from 2004.  Exceptional results from PETs winter capital program and rapid integration of the Northeast Alberta Assets into the Trusts existing operations were instrumental in achieving the production increase.



·

Higher production and continued strength in natural gas prices led to record cash flows for PET in 2005.  The Trust recorded cash flow of $260.2 million or $3.47 per Trust Unit for the year as compared to $143.6 million or $2.65 per Trust Unit for 2004.



·

As a result of the gas over bitumen financial solution put in place by the Government of Alberta in January 2005, the accretive Northeast Alberta Acquisition, the success of PETs capital programs and continued strength in natural gas prices, PET raised monthly distributions by a total of 20 percent to $0.24 per Trust Unit during 2005. Distributions for 2005 of $2.72 per Trust Unit, combined with an increase in the closing market price of PETs Trust Units from $15.94 per Unit on December 31, 2004 to $22.17 per Unit on December 30, 2005, provided a total annual pre-tax return of 56% for Unitholders.





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·

In conjunction with PETs capital spending programs and significant acquisition activity, the Trust continued to maintain a strong balance sheet throughout 2005. PETs ratio of net debt, including convertible debentures, at December 31, 2005 to annualized fourth quarter cash flow measured 0.7 times.



OPERATIONS



Properties



The scale of PETs operations increased significantly during 2005, primarily due to the acquisition of the Northeast Alberta Assets in May of 2005.  At the same time, the key attributes of PETs asset base remained unchanged.  PETs assets are extremely focused technically, through the concentration on the production of shallow natural gas, and geographically, with over 90 percent of PETs production coming from northeast Alberta.  Virtually all of PETs properties feature well established, high working interest production and most are operated by PET.  Production profiles are predictable due to the extensive production histories and the diversification of PETs production base.  Relatively low operating costs and access to stable markets combine to deliver high field netbacks.  PET has an extensive inventory of low cost opportunities for value creation which extends throughout the asset base and the undeveloped lands, requiring modest capital expenditures to offset most of the annual natural production declines.  Strategic infrastructure ownership throughout PETs asset base provides additional opportunities to add value through synergies and economies of scale.



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



·

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

·

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

·

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

·

Southern  includes assets in southern Alberta and western Saskatchewan.



Production



Natural gas production by core area (MMcf/d)200520042003West Side45.338.039.1East Side (1)28.834.546.2Athabasca65.424.9-Southern6.55.10.3Total146.0102.585.6




(1)As a result of the gas over bitumen regulatory issue described in this MD&A, PET had an average of 22.4 MMcf/d of deemed production during 2005 (2004  16.7 MMcf/d; 2003  3.2 MMcf/d) attributable to properties in the East Side Core Area.



Production volumes increased 42 percent to 146.0 MMcf/d in 2005 compared to 102.5 MMcf/d in 2004. The increase in production was attributed to the Northeast Alberta acquisition which closed in May 2005, a full year of production from the 2004 acquisitions of Cavell Energy Corporation (Cavell acquisition) and assets in the Athabasca area of northeast Alberta (Athabasca Acquisition), as well as the results of the 2005 capital expenditure program. The Northeast Alberta Acquisition increased average 2005 gas production by 25.4 MMcf/d.



In 2005, five properties located within the Trusts four core areas accounted for 44 percent of the Trusts production with the largest single property, Wabasca in the Athabasca Core Area, accounting for 14 percent of the total production.  This diversification of production minimizes the risk that operating problems at a specific property will materially impact the Trust.





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Capital Expenditures



($ thousands except where noted)200520042003Exploration and development expenditures52,21427,7678,213Undeveloped land purchases7,6821,124114Acquisitions285,956417,77932,252Dispositions(9,285)(32,750)-Oil and gas properties acquired from Paramount Resources Ltd.--269,162Other1,26711,169757Total capital expenditures337,834425,089310,498




Total capital expenditures including net property and corporate acquisitions aggregated to $337.8 million in 2005 ($425.1 million in 2004).  Of the total, $52.2 million was incurred on drilling and completions, geological, geophysical and facilities expenditures, $7.7 million was in respect of undeveloped land acquisitions, with the remaining $277.9 million attributable to net property and corporate acquisitions including $20.7 million of the purchase price for the Northeast Alberta Acquisition allocated to undeveloped acreage.  Exploration and development expenditures for 2005 include approximately $16.8 million in exploration costs which have been expensed directly on the Trusts statement of earnings. Exploration costs include seismic expenditures, dry hole costs and expired leases and are considered by PET to be more closely related to investing activities than operating activities; as a result they are included with capital expenditures.



PETs exploration and development expenditures were concentrated in its three winter-only access core areas in northeast Alberta, with a $40 million capital program conducted in the first quarter of 2005.  The program targeted both significant low cost production additions through shallow drilling, completion and tie-in activities, facilities optimization and consolidation projects to improve efficiencies in the Trusts operating cost structure and seismic acquisition for future prospect definition.



Following up on the success of PETs winter capital program, the Trust initiated a $15 million summer capital expenditure program focused on exploiting drilling opportunities in its year-round access areas.



Total acquisitions of $286.0 million in 2005 reflect primarily the Northeast Alberta Acquisition, as well as consolidating acquisitions in the Birch/Tar and Wabasca areas of northeast Alberta which totaled 1.3 MMcf/d of natural gas production and 0.9 MMcf/d of gas over bitumen shut-in production.



PETs exploration and development expenditures for 2005 were funded entirely by cash flow in excess of distributions of $55.2 million.  Undeveloped land acquisition and net property and corporate acquisitions were funded indirectly through excess cash flow, the Trusts credit facility and through the issuance of 9.5 million Trust Units and $100.0 million in convertible debentures in May 2005.



The Board of Directors of Paramount Energy Operating Corp., PETs Administrator, has approved a budget for exploration and development capital expenditures of up to $100 million for 2006, of which approximately $3 million in preliminary costs were incurred in 2005.



Drilling



200520042003GrossNetGrossNetGrossNetGas10254.64528.51611.4Service----10.5Dry44.010.4--Total10658.64628.91711.9Success rate (%)96939899100100




PET drilled 106 gross wells in 2005, as compared to 46 in 2004. Drilling activity was spread throughout the Trusts three core areas in northeast Alberta in the first quarter of 2005, with 39 (30.8 net) wells drilled with a 90 percent success rate. Through the last nine months of 2005 the Trust drilled 21 (19.9 net) operated wells and 3 (1.5) non-operated wells in the Southern core area, achieving a 95percent net success rate. PET also participated in 43 wells (6.4 net) as part of its non-operated coalbed methane project in the Craigmyle area of southern Alberta.



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Reserves



PETs complete NI 51-101 reserves disclosure as at December 31, 2005, including underlying assumptions regarding commodity prices, expenses and other factors and reconciliation of reserves on a Net Interest Basis (working interest less royalties payable), is available in the Trusts Annual Information Form for the year ended December 31, 2005 dated March 15, 2006 filed on www.sedar.com.



The reserves data set out below (the Reserves Data) is based upon an evaluation by McDaniel and Associates Consultants Ltd. (McDaniel) with an effective date of December 31, 2005 contained in a report of McDaniel dated March 8, 2006 (the McDaniel Report). The Reserves Data summarizes the natural gas reserves of the Trust and the net present values of future net revenue for these reserves using McDaniel forecast prices and costs. The oil and natural gas liquids reserves of PET are immaterial.



Natural gas reserves as at December 31 (MMcf)200520042003ProvedDeveloped producing179,976162,597115,218Developed non-producing6,8603,6472,826Shut-in gas over bitumen reserves(1)-11,9884,567Undeveloped9,0063,181656Total Proved195,842181,413123,267ProbableDeveloped producing, developed non-producing and
undeveloped61,77740,16216,318Shut-in gas over bitumen reserves (1)25,06511,9699,202Total probable86,84252,13125,520Total proved & probable282,684233,544148,787Trust Units outstanding (millions)82.565.344.6Total proved & probable per Trust Unit (Mcf/Unit)3.433.583.33




(1)

The McDaniel Report assumes that the shut-in gas over bitumen reserves are probable, that the reserves return to production after 10 years of shut-in and that such production is subject to an incremental 10 percent gross overriding royalty pursuant to the amended Natural Gas Royalty Regulation (Royalty Regulation). In 2004, 50 percent of the shut-in gas over bitumen reserves were classified as proved.



The net present values of future net revenues for PETs reserves, using McDaniel forecast prices and costs at a 10% discount rate are presented in the table below. For income tax purposes PET is able to and intends to claim a deduction for all amounts paid or payable to the Unitholders and then allocate remaining taxable income, if any, to the Unitholders.  Accordingly, no income tax amounts have been reported in this reserves data.



Net present values of reserves as at December 31 ($thousands)200520042003(Forecast prices and costs discounted at 10%)ProvedDeveloped producing727,775426,559228,989Developed non-producing6,989(4,227)9,663Gas over bitumen royalty adjustments100,86382,706-Shut-in Gas over Bitumen Reserves(1)(1,308)8,710-Undeveloped15,3634,265416Total proved849,682518,013239,068ProbableDeveloped producing, developed non-producing and
undeveloped166,44179,82634,847Shut-in gas over bitumen reserves (1)25,7858,383-Total probable192,22688,20934,847Total proved & probable1,041,908606,223273,915Trust Units (millions)82.565.344.6Total proved & probable per Trust Unit ($/Unit)12.639.286.14




(1)

The McDaniel Report assumes that the shut-in gas over bitumen reserves are probable but the future abandonment and reclamation liability associated with the wells is proved, that the reserves return to production after 10 years of shut-in and that such production is subject to an incremental 10 percent gross overriding royalty pursuant to the amended Natural Gas Royalty Regulation. In 2004, 50 percent of the shut-in gas over bitumen reserves were classified as proved.



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The following table sets forth a reconciliation of the changes in reserves for the year ended December 31, 2005 from the opening balance on December 31, 2004 derived from the McDaniel Reports at those dates, using McDaniel forecast prices.



Reserves reconciliation (Bcf)ProvedProbableProved & ProbableDecember 31, 2004181.452.1233.5Discoveries and extensions18.44.823.2Technical revisions(5.5)(4.8)(10.3)Reclassification of shut-in gas over bitumen reserves from
proved to probable (1)(11.7)11.7-Acquisitions, net of dispositions66.523.089.5Production(53.3)-(53.3)December 31, 2005195.886.8282.6




(1) In 2005 the gas over bitumen shut-in reserves were recategorized as probable from 50 percent proved and 50 percent probable in 2004, as the Phase 3 Final Hearing under the AEUB GB 2003-28 process was concluded and the final decision rendered in November 2005.



According to the McDaniel Report, over 91% of the Trusts proved reserves are developed producing reserves.  The McDaniel report identifies minimal future capital expenditures to realize the estimated production potential of the reserves identified: $31 million for the proved reserves and $7 million for the probable reserves, $14 million of which are specified for 2006.   Internally, the Trust has a significant inventory of opportunities which exceeds the forecast future capital expenditures recognized in the reserve report, including the opportunities currently being pursued in the Trusts 2006 exploration and development capital program.



Finding, Development and Acquisition Costs



2005 Capital expenditures ($millions)ProvedProved & ProbableExploration and development52.252.2Undeveloped land7.77.7Acquisitions286.0286.0Dispositions(9.3)(9.3)Total net oil and gas capital expenditures336.6336.6Less increase in net book value of undeveloped land(11.4)(11.4)Add increase in future development capital21.527.02005 FD&A net capital expenditures (1)346.7352.2Reserve additions (Bcf)Increase in year end reserves before reclassification(2)26.149.1Reclassification of gas over bitumen reserves(11.7)-Increase in year end reserves14.449.1Annual production53.353.32005 reserve additions79.4102.4Finding, development and acquisition costs ($/Mcf) (3)$4.37$3.44




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

(2)Increase in year end reserves is before change in classification of shut-in gas over bitumen reserves to probable from 50% proved and 50% probable in the previous year.

(3) F&D costs for proved reserves are calculated on increase in year-end reserves before reclassification of gas over bitumen shut-in reserves to probable from 50 percent proved and 50 percent probable in 2004.



The Trusts finding, development and acquisition costs on a proved and probable basis were $3.44 per Mcf for 2005, as compared to $3.09 per Mcf for 2004. The higher FD&A costs in 2005 are primarily the result of a general increase in the cost of field services from the previous year as well as the cost of the acquisition of the Northeast Alberta Assets.





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Land



Land inventory20052004Net acresAverage working interestNet acresAverage working interestDeveloped1,398,19474.0%1,141,46881.5%Undeveloped1,021,97674.8%775,14085.8%Total2,420,17074.4%1,916,60883.2%




PETs undeveloped acreage position increased by 32 percent in 2005.  At 7 net undeveloped acres per producing Mcf, PET has one of the most extensive inventories of undeveloped land relative to its production base in the energy trust sector.  The Northeast Alberta Acquisition added 339,733 net acres of undeveloped land.



The Trusts undeveloped acreage in the East Side Core Area includes approximately 225,000 net acres inside the gas over bitumen area of concern. While development of this acreage is restricted in certain formations, there are numerous other prospective zones in the region. The mineral rights for leases with shut-in production are continued indefinitely under Section 8-1-h of the Mines and Minerals Act(Alberta) until resolution of the gas over bitumen issue.



PET estimates the fair value of its undeveloped acreage to be $83 million at December 31, 2005 (December 31, 2004 - $55 million).



Asset Retirement Obligation and Salvage Value of Tangible Equipment



PET engaged Prevent Technologies Ltd. (Prevent), an independent evaluator, to estimate its total future asset retirement obligation based on PETs net ownership interest in all wells and facilities, including wells with no attributed reserves, , estimated costs to abandon the wells and facilities and reclaim the sites and the estimated timing of the costs to be incurred in future periods.  PET has estimated the net present value of its total asset retirement obligations to be $94.3 million as at December 31, 2005 based on an undiscounted total future liability of $190.2 million. As at December 31, 2005, the estimated undiscounted net salvage value of the Trusts gas plants, compressors and facilities was estimated at $130.3 million ($62.0 million discounted at 10%). The McDaniel Report includes an undiscounted amount of $75.3 million ($33.9 million discounted at 10%) with respect to expected future well abandonment costs related specifically to PETs proved and probable reserves.  Incorporating the estimates from Prevent Technologies, PET has assets in excess of the liabilities not considered by McDaniels in the Reserve Report of $15.4 million on an undiscounted basis ($1.6 million discounted at 10%).



Asset retirement obligation and net salvage value
(at December 31  - $ millions)2005
Undiscounted2005
Discounted at 10%LiabilitiesAsset retirement obligation
(Future abandonment and reclamation liabilities for all assets
as evaluated by Prevent)190.294.3Future abandonment and reclamation liabilities for portion of
assets as evaluated by McDaniel(75.3)(33.9)Incremental liabilities not accounted for in McDaniel Report114.960.4AssetsNet salvage value of plants, compressors and facilities130.362.0Incremental value of assets in excess of liabilities not accounted for in McDaniel Report15.41.6








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Gas Over Bitumen Issue



The AEUB issued General Bulletin 2003-28 (GB 2003-28) and Interim Shut-In Order 03-001 on July 22, 2003, establishing a process to identify gas production in the Wabiskaw-McMurray formations which may be posing an unacceptable risk to potential bitumen resources.  The AEUB considers that gas production in pressure communication with associated potentially recoverable bitumen places future bitumen recovery utilizing Steam Assisted Gravity Drainage (SAGD) at an unacceptable risk.



Following the completion of a Regional Geological Study by the AEUB and an interim hearing held in March 2004 the AEUB ordered the shut-in, effective July 1, 2004, of Wabiskaw-McMurray natural gas production in northeast Alberta totaling approximately 123 MMcf/d. As of July 1, 2004, PET had shut-in wells producing approximately 17.2 MMcf/d of sales gas pursuant to Decision 2004-045 and Interim Shut-In Orders 04-001 and 04-002 including 4.5 MMcf/d from the zones shut-in on September 1, 2003 pursuant to GB 2003-28 and Interim Shut-In Order 03-001. An additional 0.2 MMcf/d was shut-in on September 1, 2004 pursuant to Decision 2004-064 and Interim Shut-In Order 04-003 related to wells in the Chard and Leismer areas.



On October 4, 2004 the Government of Alberta enacted amendments to the Royalty 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 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.  In July 2005, further amendments were enacted to the Royalty Regulation with respect to natural gas, implementing a positive correction to the royalty calculation formula to provide a $0.05 per Mcf

reduction in the effective operating costs adjustment.  This effectively increases the net royalty adjustment by $0.025 per Mcf of deemed production and is retroactive to the date of shut-in.  The revised formula for calculation of the royalty reduction provided in the Royalty Regulation is:



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



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



Gas over bitumen royalty adjustment netback($ per Mcf)200520042003 (1)Average deemed volume (MMcf/d) (2)22.416.79.6Gas price$   8.30$   6.28$   5.20Royalties(1.66)(1.26)(1.04)Operating costs(0.40)(0.40)(0.40)50% reduction factor(3.12)(2.31)(1.88)Gas over bitumen royalty adjustment netback$   3.12$   2.31$   1.88




(1)

From September 1, 2003 to December 31, 2003

(2)

Represents 20.5 MMcf/d of shut-in production in 2005 (2004  14.6 MMcf/d, 2003  7.5 MMcf/d) and 1.9 MMcf/d of wells denied production under AEUB ID 99-1 (2004 and 2003  2.1 MMcf/d)



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, were recorded as an adjusting item for cash flow from operations in 2004.



The Trusts net deemed production volume for purposes of the royalty adjustment was 22.4 MMcf/d in 2005. Deemed production represents all PET natural gas production shut-in or denied production pursuant to a Decision Report, corresponding AEUB Order or General Bulletin, or through correspondence in relation to an AEUB ID 99-1 application.  In accordance with IL 2004-36, the deemed production volume related to wells shut-in is reduced by 10 percent at the end of every year of shut-in.  PETs current deemed production is approximately 21.5 MMcf/d.



During 2005, the Trust received $30.6 million in gas over bitumen royalty adjustments, a substantial increase from the $11.2 million received in 2004.  With the interim shut-in orders effective July 1 and September 1, 2004, the increase in the 2005 gas over bitumen royalty adjustment was related to the full year effect of shut-in as well as increased gas prices as the royalty adjustment is calculated using the actual Alberta Gas Reference Price each month. These amounts have been recorded on PETs balance sheet rather than reported as income as the Trust cannot determine if, when or to what extent the royalty adjustments may be repayable through incremental royalties if and when gas production recommences.  This brings cumulative royalty adjustments received to December 31, 2005 to $41.8 million. Royalty



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adjustments, although not included in earnings, are recorded as a component of funds from operations and as such are considered distributable income.



The Phase 3 Final Hearing with respect to the AEUBs bitumen conservation requirements commenced on June 14, 2005 and ended on August 12, 2005.  PET, an active participant in the hearing, filed detailed evidence supporting the resumption of production from six gas pools representing approximately 8.5 MMcf/d of production the Trust had shut-in pursuant to AEUB Orders.  PET also reiterated to the AEUB its continued objection to all zones that had been shut-in as a result of the interim hearing based on the new evidence that the Trust has submitted.



On November 11, 2005 PET advised that the AEUB issued Decision 2005-122 (the Final Decision) regarding the Phase 3 Final Hearing.  The Final Decision had minimal impact on the Trust, targeting one additional well, producing less than 50 Mcf/d net to PET, for shut-in effective January 1, 2006.  Shut-in PET wells with a productive capacity of less than 200 Mcf/d net to PET were approved for production, for a net potential gain to the Trusts production of approximately 150 Mcf/d as a result of the Final Decision.



With the AEUB GB 2003-28 process now complete, PET will continue to focus on converting its shut-in natural gas reserves back into producing assets.  While the Trust is receiving partial relief for its lost cash flow in the form of monthly royalty reductions, PET still owns the shut-in reserves and they are more valuable if returned to production.  PET will continue to monitor new information as there is potential that future field evidence from actual SAGD projects will provide support to PETs technical position.  The Trust will also continue its active involvement in technical solution initiatives.



Future AEUB reviews will be project specific in nature and will be focused on either bitumen production project approval or gas production approval.  Technical solutions such as flue gas injection, gas cap repressurization with air, low pressure pump technology or new recovery processes, THAI and VAPEX technology as well as other research initiatives that may not yet have been identified are now the focus of PET and others in industry to reduce the perceived risk gas production may pose to potentially recoverable bitumen resources.  PET is also diligent in the monitoring of all future proposed SAGD projects in our operating areas as associated gas production and contamination from SAGD operations is a serious concern for all owners of shut-in gas reserves.



MARKETING



Natural Gas Prices



Natural gas price (/Mcf)200520042003Reference pricesAECO Monthly Index ($/Mcf)$  8.50$  6.54$  6.70Alberta Gas Reference Price ($/Mcf)$  8.30$  6.28$  6.13Average PET prices, before hedgingNatural gas ($/Mcf)$  8.30$  6.51$  6.39% AECO98%100%95%% Alberta Gas Reference Price100%104%104%Natural gas, after hedging(1) ($/Mcf)$  7.97$  6.40$  6.72% AECO, after hedging94%98%100%% Alberta Gas Reference Price, after hedging96%102%110%




(1) Includes settled financial fixed price foward contracts and options..



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 Monthly Index prices increased sharply to average $8.50 per Mcf in 2005 as compared to $6.54 per Mcf for 2004, a 30 percent change.  This was largely driven by a significant increase in natural gas prices in September and the fourth quarter of 2005 following disruption of Gulf of Mexico natural gas production as a result of Hurricanes Katrina and Rita.  AECO Monthly Index prices in the fourth quarter of 2005 averaged $11.69 per Mcf as compared to $7.09 per Mcf in 2004, an increase of 65 percent.



The Alberta Gas Reference Price is the monthly weighted average of intra-Alberta consumers' prices and ex-Alberta border prices, reduced by allowances for transporting and marketing gas.  The Alberta Gas Reference Price is used to calculate Alberta Gas Crown Royalties.  The Alberta Gas Reference Price increased 32 percent from $6.28 per Mcf in 2004 to $8.30 per Mcf in 2005.



PETs natural gas price, prior to hedging transactions, increased by 27 percent to $8.30 per Mcf in 2005 from $6.51 per Mcf in 2004.  PETs average realized gas price after hedging transactions was $7.97 per Mcf and $6.40 per Mcf in 2005 and 2004 respectively. The difference between the Trusts natural gas price before and after hedging can be



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attributed to fixed-price financial contracts entered into by PET in order to lock in attractive returns on the Northeast Alberta Acquisition and provide distribution stability for our Unitholders.



Hedging and Risk Management



PETs commodity price risk management activities are conducted in consultation with the Board of Directors of the Administrator of the Trust with the objective of using a proactive and opportunistic approach to hedging in order to maximize 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.  Hedging is also used to ensure or enhance the economics related to significant acquisitions.  The Trust mitigates exposure to credit risk associated with these risk management contracts by only entering into financial hedging transactions with financially sound, credit-worthy counterparties.



At December 31, 2005 the Trust had entered into financial hedge arrangements as follows:



Volumes  at AECO(Gigajoules/day)(GJ/d)Price ($/GJ)Term65,000 GJ/d$ 8.40January 2006  March 200620,000 GJ/d$ 8.01April 2006  October 2006




Had these contracts been settled on December 31, 2005, using forward prices in effect at that time the mark-to-market settlement payment by PET would have totaled $20.5 million.  As the Trust follows hedge accounting for these instruments this amount has not been recorded in the financial statements.  The January, February and March hedges have now settled for a net realized loss of $2.1 million and the mark-to-market settlement on the remaining financial contracts using prices in effect on March 13, 2006 would have been a receipt to PET of $7.1 million.  This equates to a net realized and projected mark-to-market gain on the hedges in place on December 31, 2005 of $5.0 million as at March 13, 2006.



At December 31, 2005 PET had entered into forward physical gas sales arrangements as follows:



|                                             |              |       |         |                     
|-------------------------------------------- | ------------ | ----- | ------- | --------------------
|                                             | Price ($/GJ) |      
|Volumes at AECO
    (Gigajoules/day)(GJ/d) | Fixed        | Floor | Ceiling | Term                
|65,000 GJ/d                                  | $8.50        | -     | -       | January  March 2006
|25,000 GJ/d                                  | $8.03        | -     | -       | April October 2006 
|5,000 GJ/d                                   | -            | $9.00 | $12.50  | April October 2006 



The January, February and March physical sales contracts have now settled for a net realized loss of $2.1 million and the mark-to-market settlement on the remaining forward physical sales contracts using prices in effect on March 13, 2006 would have been a receipt to PET of $11.7 million. This equates to a net realized and projected mark-to-market gain on the physical forward sales in place on December 31, 2005 of $9.2 million as at March 13, 2006.



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The Trusts financial hedging and physical sales portfolio has changed significantly since December 31, 2005. Total financial hedge arrangements and physical sales contracts outstanding as of March 13, 2006 are as follows:



|                 |                      |              |          |        |                            |  | 
|---------------- | -------------------- | ------------ | -------- | ------ | -------------------------- |  | 
|                 |                      |              |          |        |                           
|Type of Contract | Volumes at AECO
GJ/d | Price ($/GJ) | Term    
|Fixed            | Floor                | Ceiling     
|Financial        | 27,500               | $7.54        | -        | -      | April   October 2006     
|Physical         | 42,500               | $7.64        | -        | -      | April  October 2006      
|Physical         | 5,000                | -            | $9.00    | $12.50 | April October 2006       
|Period Total     | 75,000               |              | $7.70(1) |        | April October 2006       
|Financial        | 30,000               | $9.025       | -        | -      | November 2006  March 2007
|Financial        | 5,000                | -            | $9.50    | $11.00 | November 2006  March 2007
|Financial        | 5,000                | -            | $9.00    | $10.00 | November 2006  March 2007
|Physical         | 30,000               | $9.035       | -        | -      | November 2006  March 2007
|Physical         | 5,000                | -            | $9.00    | $11.00 | November 2006  March 2007
|Physical         | 5,000                | -            | $9.00    | $10.00 | November 2006  March 2007
|Physical         | 5,000                | -            | $8.50    | $11.00 | November 2006  March 2007
|Period Total     | 85,000               |              | $9.02(1) |        | November 2006  March 2007
|Financial        | 27,500               | $7.94        | -        | -      | April October 2007       
|Physical         | 27,500               | $7.91        | -        | -      | April October 2007       
|Period Total     | 55,000               |              | $7.93    |        | April 2007  October 2007 
|Financial        | 12,500               | $9.272       | -        | -      | November 2007  March 2008
|Physical         | 12,500               | $9.031       | -        | -      | November 2007  March 2008
|Period Total     | 25,000               |              | 9.15     |        | November 2007  March 2008



(1) Average price calculated using fixed price and floor price for collars.



The mark-to-market settlement on the outstanding financial hedges and physical forward sales contracts using prices in effect at the close of market on March 13, 2006, assuming the floor price for the collars is a fixed price, is a receipt of $24.9 million. In addition to the January through March contracts which have settled as described above, PET has settled or collected premiums for other contracts for an additional $3.3 million since year end 2005.



FINANCIAL RESULTS



Revenue



|                                            |          |         |        
|------------------------------------------- | -------- | ------- | -------
|($ thousands)                               | 2005     | 2004    | 2003   
|Oil and natural gas revenue, before hedging | 442,505  | 244,303 | 199,488
|Hedging receipts (payments) (1)             | (17,764) | (4,346) | 10,318 
|Total revenue                               | 424,741  | 239,957 | 209,806



(1)Hedging receipts (payments) includes settlement of financial forward contracts and options.



Oil and natural gas revenue in 2005 was $424.7 million, representing a 77 percent increase from $240.0 million in 2004.  Revenue growth was achieved via the 43 percent increase in natural gas volumes and the 25 percent increase in realized prices after hedging adjustments in 2005 as compared to the prior year.



Operating Netbacks



The components of operating netbacks are shown below:



|                     |         |         |        
|-------------------- | ------- | ------- | -------
|Netback              |         |         |        
|($ per Mcf)          | 2005    | 2004    | 2003   
|Gas price            | $  7.97 | $  6.40 | $  6.72
|Royalties            | (1.66)  | (1.11)  | (1.22) 
|Operating costs      | (1.20)  | (1.03)  | (0.89) 
|Transportation costs | (0.26)  | (0.26)  | (0.28) 
|Netback              | $  4.85 | $  4.00 | $  4.33





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



Total aggregate operating costs increased by $25.2 million (65 percent) to $64.0 million in 2005 from $38.8 million in 2004, primarily as a result of the 43 percent increase in average production related to the Northeast Alberta Acquisition. On a unit of production basis, operating costs increased by 17 percent to $1.20 per Mcf in 2005 from $1.03 per Mcf in 2004.  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 and manpower.



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 costs incurred at a property and are in accordance with Crown royalty regulations.  Royalty income received is included in revenue.  The effective royalty rate applicable to the Trust in 2005 was 20.9 percent (2004  17.3 percent) or $1.66 per Mcf (2004 - $1.11 per Mcf).  The increase in royalty rate over 2004 was primarily a result of higher reference natural gas prices and PETs realized natural gas prices that were lower than the Alberta Gas Reference Price, upon which Alberta Crown Royalties are calculated, in September and the fourth quarter of 2005. Also a higher production rate per well in the Northeast Alberta Assets, as compared to the Trusts base assets, also contributed to higher royalties as a percentage of revenue.



Costs to transport gas from the plant gate to the commercial market sales point are not reflected as an operating cost but rather are recorded as transportation costs for the product.  Total transportation costs increased by 40 percent to $13.7 million ($0.26 per Mcf) in 2004 from $9.8 million ($0.26 per Mcf) in 2004 as a result of the increased production.



General and Administrative Expenses



|                                 |        |       |        |       |        |      
|-------------------------------- | ------ | ----- | ------ | ----- | ------ | -----
|                                 | 2005   | 2004  | 2003  
|                                 | $000s | $/Mcf | $000s | $/Mcf | $000s | $/Mcf
|Cash general & administrative    | 10,807 | 0.20  | 7,119  | 0.19  | 3,980  | 0.13 
|Gas over bitumen costs           | 1,000  | 0.02  | 1,160  | 0.03  | 696    | 0.02 
|Trust Unit-based compensation(1) | 1,993  | 0.04  | 2,374  | 0.08  | -      | -    
|Total general & administrative   | 13,800 | 0.26  | 9,493  | 0.30  | 4,676  | 0.15 



(1)Non-cash item



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



G&A expenses, net of overhead recoveries on operated properties, increased to $13.8 million from $9.5 million in 2004 but decreased on a unit-of-production basis from $0.30 per Mcf in 2004 to $0.26 per Mcf in 2005.  The 2005 total included $1.0 million in legal and consulting expenditures directly related to the AEUB gas over bitumen issue ($1.2 million  2004).  Included in total G&A expenses are $2.0 million in 2005 related to Trust Unit-based compensation costs charged to earnings under new accounting rules adopted in 2004.  The Trust Unit-based compensation costs for 2004 were $2.4 million. PET uses the binomial lattice option pricing model to value unit incentive rights.



The Trust expects 2006 G&A costs excluding non-cash G&A to remain relatively flat in 2006.



Interest Expense



Interest expense increased to $8.0 million in 2005 from $4.8 million in 2004 as a result of a higher monthly average debt balance following the Northeast Alberta Acquisition, in addition to a slightly higher interest rate as a result of the increase in the Bank of Canada lending rate during 2005.  On a unit-of-production basis, interest expenses were $0.055 per Mcf in 2005 as compared to $0.047 per Mcf in 2004.



In 2005, $6.3 million of interest on the convertible debentures was expensed as compared to $1.4 million in 2004.  The increase was due to the issuance of $100 million of the 6.25% Debentures in April 2005, and a full year of interest expense on the 8% convertible debentures (the 8% Debentures) issued in August 2004.



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Depletion, Depreciation and Accretion



PETs 2005 depletion, depreciation and accretion (DD&A) rate decreased to $2.80 per Mcf from $2.90 per Mcf in 2004, primarily due to a lower depletable base for the Saskatchewan properties due to the impairment charge recorded on that cost centre in 2004.  The Trust calculates its depletion factor using proved reserves and production; as there is no production associated with the shut-in gas over bitumen reserves no depletion expense is recorded on the related costs. Gas over bitumen deemed production is not included in the DD&A calculation.  The DD&A rate includes accretion expense on the asset retirement obligation of $3.6 million in 2005 as compared to $2.1 million in 2004.  The increase in accretion is a function of both higher production volumes and a significant increase in the asset retirement obligation in 2005 as compared to 2004.  An upward revision of the estimated cost of individual well abandonment operations driven by a general increase in the cost of services in the oil and gas industry coupled with the Trusts larger well base in 2005, gave rise to the increase in the asset retirement obligation from $34.1 million at December 31, 2004 to $94.3 million at December 31, 2005.  (See Note 10 to the Consolidated Financial Statements.)



|                                         |         |         |       
|---------------------------------------- | ------- | ------- | ------
|Depletion, depreciation and accretion    |         |         |       
|($ thousands except where noted)         | 2005    | 2004    | 2003  
|Depletion expense                        | 145,469 | 106,777 | 61,436
|Accretion of asset retirement obligation | 3,617   | 2,090   | 1,239 
|Total                                    | 149,086 | 108,867 | 62,675
|Per Unit of production ($/Mcf)           | 2.80    | 2.90    | 2.01  



At year end 2005, property, plant and equipment costs included undeveloped land of $83.9 million (2004 - $72.5 million) currently not subject to depletion and $32.5 million (2004 - $35.4 million) of costs related to shut-in gas over bitumen reserves which are not being depleted due to the non-producing status of the wells in the affected properties .



Income Taxes



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



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



Impairment Test



PET performs impairment tests annually or as economic events dictate. An impairment loss is recognized when the carrying amount of a property is greater than the sum of the expected future cash flows (undiscounted and without interest charges) from that property. The amount of the impairment loss is calculated as the difference between the carrying amount and the present value of estimated future cash flows discounted at a rate that approximates the Trusts long-term borrowing rate.



At December 31, 2005 the sum of the expected future cash flows for each separate property within the Trust exceeds the carrying amount of its associated property, plant and equipment. As such, no impairment loss was recorded in 2005.



At December 31, 2004 PET recorded a writedown of property, plant and equipment of $65.4 million related primarily to its Saskatchewan properties.



Net Earnings and Cash Flow



Cash flow totaled $260.2 million ($3.47 per Trust Unit) for the year ended December 31, 2005 as compared to $143.6 million ($2.65 per Trust Unit) for the year ended December 31, 2004, a 31 percent increase on a per Trust Unit basis.  The 81 percent increase in cash flow in 2005 is primarily the result of the 42 percent increase in production combined with the 25 percent increase in realized gas prices, with higher gas over bitumen royalty adjustments also factoring into the increased cash flows from 2004 levels.





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Cash Flow Reconciliation



|                                      |            |         |            |        
|------------------------------------- | ---------- | ------- | ---------- | -------
|                                      | 2005       | 2004   
|                                      | $ millions | ($/Mcf) | $ millions | ($/Mcf)
|Production volume (Bcf)               |            | 53.3    |            | 37.5   
|Revenue                               | 424.7      | 7.97    | 240.0      | 6.40   
|Royalties                             | (88.7)     | (1.66)  | (41.7)     | (1.11) 
|Operating costs                       | (64.0)     | (1.20)  | (38.8)     | (1.03) 
|Transportation costs                  | (13.7)     | (0.26)  | (9.8)      | (0.26) 
|Operating netback from production     | 258.3      | 4.85    | 149.7      | 4.00   
|Gas over bitumen royalty adjustments  | 30.6       | 0.57    | 11.2       | 0.30   
|Lease rentals                         | (3.0)      | (0.06)  | (2.1)      | (0.06) 
|General and administrative (1)        | (10.8)     | (0.20)  | (7.1)      | (0.19) 
|Gas over bitumen costs                | (1.0)      | (0.02)  | (1.2)      | (0.03) 
|Interest on bank and other debt       | (8.0)      | (0.15)  | (4.8)      | (0.14) 
|Interest on convertible debentures(1) | (5.6)      | (0.10)  | (1.3)      | (0.03) 
|Capital taxes                         | (0.3)      | (0.01)  | (0.8)      | (0.02) 
|Cash flow (1)                         | 260.2      | 4.88    | 143.6      | 3.83   



(1) Excludes non-cash items



Net earnings measured $61.9 million or $0.82 per Trust Unit in 2005 as compared to a loss of $17.5 million or $0.32 per Trust Unit in 2004. Higher revenue, a lower depletion rate and the absence of impairment losses in 2005 were the primary factors in the increase in net earnings over 2004.



Fourth Quarter Information Summary



|                                                               |                                |           |          | 
|-------------------------------------------------------------- | ------------------------------ | --------- | -------- | 
|Fourth Quarter Information                                     | Three months ended December 31
|$ thousands except per Trust Unit, per Mcf and percent amounts | 2005                           | 2004      | % change
|Daily production volumes (MMcf/d)                              | 153.7                          | 128.0     | 20      
|                                                               |                                |           |         
|Natural gas revenues                                           | 129,233                        | 79,665    | 62      
|Realized natural gas price ($/Mcf)                             | $  9.14                        | $  6.78   | 35      
|                                                               |                                |           |         
|Royalties                                                      | 33,918                         | 15,342    | 121     
|Royalties as a percentage of revenues                          | 26.2%                          | 19.3%     | 36      
|                                                               |                                |           |         
|Operating expenses                                             | 16,837                         | 10,849    | 55      
|Per Mcf                                                        | $  1.19                        | $  0.92   | 29      
|                                                               |                                |           |         
|General and administrative expenses                            | 3,349                          | 1,671     | 100     
|Per Mcf                                                        | $  0.24                        | $  0.14   | 71      
|                                                               |                                |           |         
|Cash flow                                                      | 78,200                         | 56,521    | 38      
|Per Trust Unit                                                 | $  0.96                        | $  0.87   | 10      
|                                                               |                                |           |         
|Net earnings (loss)                                            | 17,928                         | (29,696)  | 160     
|Net earnings (loss) per Trust Unit                             | $  0.22                        | $  (0.46) | 148     
|                                                               |                                |           |         
|Capital expenditures  exploration and development             | 11,402                         | 13,899    | (18)    



In comparing the fourth quarter of 2005 with the same period in 2004:



·

Production increased 20 percent due primarily to the Northeast Alberta Acquisition and a successful winter capital program in 2005.

·

Natural gas prices were 35 percent higher in the fourth quarter of 2005 as a result of higher AECO daily spot and monthly index prices compared to the three months ended December 31, 2004.

·

The Trusts royalty rate increased to 26 percent of revenues as realized natural gas prices were lower than the Alberta Reference Price due to a number of fixed-price financial and physical forward sales contracts entered into by PET to lock in attractive returns on the Northeast Alberta Acquisition.



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·

Operating costs increased 29percent to $1.19 per Mcf as a result of generally higher costs for field services and supplies as compared to the prior year and additional maintenance required on the Northeast Alberta Acquisition facilities.

·

These factors combined to generate a 38 percent increase in cash flow to $78.2 million from $56.5 million for the fourth quarter of 2004.

·

Net earnings increased 160 percent to $17.9 million due to higher cash flow and a lower depletion rate; 2004 results were also impacted by an after-tax writedown of $39 million pertaining to the Trusts Saskatchewan cost centre.



LIQUIDITY, CAPITALIZATION AND FINANCIAL RESOURCES



|                                                      |                        |          
|----------------------------------------------------- | ---------------------- | ---------
|Capitalization and financial resources                | Year ended December 31
|$ thousands except per Trust Unit and percent amounts | 2005                   | 2004     
|Bank and other debt                                   | 168,106                | 171,698  
|Convertible debentures                                | 64,888                 | 38,419   
|Working capital deficiency (surplus)                  | (1,131)                | 4,384    
|Net debt                                              | 231,863                | 214,501  
|Trust Units outstanding (000s)                       | 82,482                 | 65,327   
|Market price at end of period                         | 22.17                  | 15.88    
|Market value of Trust Units                           | 1,828,626              | 1,037,392
|Total marked capitalization (1)                       | 2,060,489              | 1,251,893
|Net debt as a percentage of total capitalization      | 11.3%                  | 17.1%    
|Cash flow                                             | 260,218                | 143,592  
|Net debt to cash flow ratio                           | 0.9                    | 1.5      



(1)  These are Non-GAAP measures; see Significant Accounting Policies and Non-GAAP Measures in this MD&A.



At December 31, 2005, PET had bank debt outstanding of $168.1 million compared to $171.7 million at December 31, 2004 and $64.9 million in convertible debentures outstanding versus $38.4 million at December 31, 2004. The increase in convertible debentures from 2004 levels is a result of the $100 million offering of 6.25% Debentures closed in April 2005 as partial funding for the Northeast Alberta Acquisition, less $73.2 million of debenture conversions during the year.



After financing the AcquireCo acquisition in February 2006 through PETs existing credit facilities, bank and other debt is currently approximately $263 million.



PET has a revolving credit facility with a syndicate of six Canadian Chartered Banks.  As at the date of this MD&A the revolving credit facility had a borrowing base of $310 million.  The facility consists of a demand loan of $300 million and a working capital facility of $10 million.  In addition to amounts outstanding under the facility, PET has outstanding letters of credit in the amount of $2.87 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 bankers acceptances (BA), prime rate loans or letters of credit.  In the case of BA advances, interest is a function of the BA rate plus a stamping fee based on the Trusts current ratio of debt to cash flow. In the case of prime rate loans, interest is charged at the lenders prime rate.  The average interest rate at December 31, 2005 was 4.17 percent.



Year end 2005 net debt to total capitalization was 11.3 percent (17.1 percent in 2004) and net debt to 2005 cash flow was 0.9 times (1.5 times in 2004).



The Trust expects that its distributions and capital expenditure program for 2006 will be funded by cash flow with PETs Distribution Reinvestment and Optional Trust Unit Purchase Plan (DRIP Plan) enhancing PETs balance sheet.



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



|                                    |                        |                  |           |           |              
|----------------------------------- | ---------------------- | ---------------- | --------- | --------- | -------------
|                                    | Payments due by period
|Contractual obligations ($millions) | Total                  | Less than 1 year | 1-3 years | 3-5 years | After 5 years
|Bank and other debt                 | $  168.1               | $  162.4(1)      | $  0.8    | $    0.9  | $  4.0       
|Convertible debentures              | $  64.9                | -                | -         | $  64.9   | -            
|Total contractual obligations       | $  233.0               | $  162.4         | $  0.8    | $  65.8   | $  4.0       



(1)The revolving feature of the Trust's credit facility expires on May 31, 2006, if not extended.  Pursuant to the terms of the credit agreement, the Trust has requested that the facility be extended for one year and anticipates that this request will be granted.



Convertible Debentures



The Trusts 6.25% Debentures mature on June 30, 2010, bear interest at 6.25 percent per annum paid semi-annually on June 30 and December 31 of each year and are subordinated to substantially all other liabilities of PET including the Credit Facility.  The 6.25% Debentures are convertible at the option of the holder into Trust Units at any time prior to the maturity date at a conversion price of $19.35 per Trust Unit.  During the twelve months ended December 31, 2005, $42.1 million of 6.25% Debentures were converted, resulting in the issuance of 2,175,380 Trust Units.



The Trusts 8% Debentures mature on September 30, 2009, bear interest at 8.00 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 the Credit Facility. The 8% Debentures are convertible at the option of the holder into Trust Units at any time prior to the maturity date at a conversion price of $14.20 per Trust Unit.  During the twelve months ended December 31, 2005, $31.1 million of 8% Debentures were converted, resulting in the issuance of 2,187,642 Trust Units.



At December 31, 2005, PET had $7.4 million of 8% Debentures outstanding with a fair market value of $11.6 million and $57.9 million of 6.25% Debentures outstanding with a fair market value of $66.6 million.



Unitholders Equity



PETs total market capitalization was $2,060.5 million at December 31, 2005 with the market value of the Trust Units representing 89 percent of total capitalization. During 2005, the market price of the Trust Units ranged from $15.88 to $23.44 with an average daily trading volume of 191,000 Units.



In February 2004, PET implemented an industry-leading DRIP Plan for eligible Unitholders of the Trust.  The DRIP Plan provides Unitholders with the opportunity to reinvest monthly cash distributions to acquire additional Trust Units at 94 percent of the Treasury Purchase Price, which is defined as the daily volume weighted average trading price of the Trust Units for the 10 trading days immediately proceeding a distribution payment date.  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 at the same 6 percent discount to the Treasury Purchase Price.  No additional commissions, service or brokerage fees are charged to the Unitholder for these transactions.  In 2005 the DRIP Plan resulted in an additional 2,853,601 Trust Units (2004  632,829 Trust Units) being issued at an average price of $17.34 (2004 - $12.93) raising a total of $49.5 million (2004 - $8.2 million).



On December 31, 2005 there were 82.5 million Trust Units outstanding. Trust Units were issued during 2005 as follows:



·

On April 26, 2005 PET closed an equity financing issuing subscription receipts to purchase 9.5 million Trust Units at $16.85 per Unit for net proceeds of $152.1 million.

·

During 2005, 0.4 million Trust Units were issued by way of exercised incentive rights for net proceeds of $3.8 million.

·

During 2005, 2.9 million Trust Units were issued through the DRIP Plan for net proceeds of $49.5 million.

·

In 2005, 4.4 million Trust Units were issued through the conversion of $73.2 million of convertible debentures into Trust Units.



CASH DISTRIBUTIONS



PET declared cash distributions of $205.0 million ($2.72 per Unit) in 2005 representing 79 percent of 2005 cash flow, bringing total cumulative distributions since inception to year end 2005 to $449.5 million ($7.784 per Trust Unit).  In 2004, declared cash distributions were $121.3 million ($2.18 per Trust Unit), representing 84 percent of cash flow. The Trusts focus on distribution sustainability has resulted in a reduction in the payout ratio from 2004 to 2005, as PET now reserves a higher portion of cash flow for financing capital expenditures and acquisitions.



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Taxation of 2005 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 2005 taxation year, the split between the two is 95.4 percent taxable and 4.6 percent tax deferred.



PET, in consultation with its tax advisors, is of the view that the 2005 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 2005, 86.3 percent would be reported as qualified dividends and 13.7 percent would be reported as non-taxable return of capital for U.S. residents. PET performed an earnings and profits calculation for U.S. tax purposes in order to make this determination. Residents of the U.S. should contact their own advisors with respect to their specific circumstances.



2005 Distributions by Month

($ per Trust Unit)

|                   |          |                              |              |    
|------------------ | -------- | ---------------------------- | ------------ | ---
|                   | Canadian | Canadian Tax Deferred Amount |              |    
|                   | Taxable  | (Return of                   | Total        |    
|Payment Date       | Amount   | Capital)                     | Distribution |    
|February 15, 2005  | $  0.210 | $  0.010                     | $   0.220    |    
|March 15, 2005     | 0.210    | 0.010                        | 0.220        |    
|April 15, 2005     | 0.210    | 0.010                        | 0.220        |    
|May 16, 2005       | 0.210    | 0.010                        | 0.220        |    
|June 15, 2005      | 0.210    | 0.010                        | 0.220        |    
|July 15, 2005      | 0.210    | 0.010                        | 0.220        |    
|August 15, 2005    | 0.210    | 0.010                        | 0.220        |    
|September 15, 2005 | 0.210    | 0.010                        | 0.220        |    
|October 17, 2005   | 0.229    | 0.011                        | 0.240        |    
|November 15, 2005  | 0.229    | 0.011                        | 0.240        |    
|December 15, 2005  | 0.229    | 0.011                        | 0.240        |    
|January 16, 2006   | 0.229    | 0.011                        | 0.240        |    
|Total              | $  2.596 | $  0.124                     | $   2.720    | (1)
|Percent            | 95.4%    | 4.6%                         | 100.0%       |    



(1)  Total is based upon cash distributions paid and payable during 2005



2006 Cash Distributions



PET has declared three consecutive distributions of $0.24 per Trust Unit per month in 2006 and estimates that this level of monthly distributions 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.  The Trust estimates a payout ratio for 2006 of approximately 85 percent of cash flow, given current forward natural gas prices and the Trusts estimates for 2006 production and cash flow.



SUMMARY OF QUARTERLY RESULTS



|                                                |                    |               |               |             
|----------------------------------------------- | ------------------ | ------------- | ------------- | ------------
|                                                | Three months ended
|(thousands of dollars, except per Unit amounts) | Dec 31, 2005       | Sept 30, 2005 | June 30, 2005 | Mar 31, 2005
|                                                |                    |               |               |             
|Natural gas revenues before royalties           | $  129,233         | $  118,928    | $ 100,234     | $   76,346  
|Net earnings                                    | $    17,928        | $    30,432   | $   11,357    | $     2,153 
|Net earnings per Unit - basic                   | $        0.22      | $        0.39 | $       0.15  | $       0.03
|- diluted                                       | $        0.22      | $        0.38 | $       0.15  | $       0.03



|                                                |                    |               |               |             
|----------------------------------------------- | ------------------ | ------------- | ------------- | ------------
|                                                | Three months ended
|(thousands of dollars, except per Unit amounts) | Dec 31, 2004       | Sept 30, 2004 | June 30, 2004 | Mar 31, 2004
|                                                |                    |               |               |             
|Natural gas revenues before royalties           | $      79,665      | $   59,156    | $   49,904    | $   51,232  
|Net earnings (loss)                             | $   (29,696)       | $     4,813   | $     5,147   | $     2,192 
|Net earnings (loss) per Unit - basic            | $       (0.46)     | $       0.08  | $       0.11  | $       0.05
|- diluted                                       | $       (0.46)     | $       0.08  | $       0.11  | $       0.05



Natural gas revenues have trended steadily higher over the eight quarters shown above. The increase is primarily a result of higher production volumes due to acquisition activity in the second half of 2004 and early 2005, as well as increased natural gas prices over the two-year period.



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The increased net earnings in the second, third and fourth quarters of 2005 are due to higher production and natural gas prices, offset somewhat by higher royalties and DD&A expenses as compared to prior quarters.  The net loss in the fourth quarter of 2004 was a result of an after-tax write-down of property, plant and equipment of $39 million pertaining to the Trusts Saskatchewan cost centre.



2006 OUTLOOK AND SENSITIVITIES



Based on budgeted forecast commodity prices, PETs hedging portfolio, production levels and the Trusts exploration and development capital expenditure budget and targeted results, following are PETs budgeted estimates of key measures for 2006:



|                                   |              |         |             
|---------------------------------- | ------------ | ------- | ------------
|                                   |              | 2005    | 2006E (1)(2)
|                                   |              |         |             
|Natural gas production             | MMcf/d       | 146.0   | 156.2       
|Gas prices                         |              |         |             
|AECO Monthly Index                 | $/GJ         | $  8.50 | $  8.50     
|PET realized                       | $/Mcf        | $  7.97 | $  8.73     
|Monthly cash flow                  | $/Unit/month | $  0.29 | $  0.31     
|Monthly average distributions      | $/Unit/month | $  0.23 | $  0.24     
|Payout ratio                       | %            | 78.8%   | 72.0%       
|Ending debt to cash flow Ratio (3) | times        | 0.9     | 0.8         



(1)

Cash flow and payout ratio are non-GAAP terms; please refer to Significant Accounting Policies and Non-GAAP Measures in this MD&A

(2)

Amounts are based on PETs 2006 budget and may not reflect the current market for forward natural gas prices or PETs current hedging position.

(3)

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



Below is a table that shows sensitivities of PETs 2006 budgeted cash flow to operational changes and changes in the business environment:



|                               |             |                                    |        
|------------------------------ | ----------- | ---------------------------------- | -------
|Cash flow sensitivity analysis |             | Impact on cash flow per Trust Unit
|                               | Change      | Annual                             | Monthly
|Business Environment           |             |                                    |        
|Price per Mcf of natural gas   | $  0.25     | 0.07                               | 0.006  
|                               |             |                                    |        
|Interest rate on debt          | 1%          | 0.03                               | 0.003  
|Operational                    |             |                                    |        
|Gas production volume          | 5 MMcf/d    | 0.10                               | 0.008  
|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 $1.20 per Mcf, cash G&A expenses of $0.19 per Mcf, and an interest rate on long term bank debt of 4.65 percent. Cash G&A expenses are equal to G&A expenses before Trust Unit based compensation.



SIGNIFICANT ACCOUNTING POLICIES AND NON-GAAP MEASURES



Successful Efforts Accounting



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





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Cash Flow



Management uses funds flow from operations before changes in non-cash working capital (cash flow) and cash flow per Trust Unit to analyze operating performance and leverage. Cash flow as presented does not have any standardized meaning prescribed by 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 GAAP.  Cash flow is reconciled to its closest GAAP measure, cash provided by operating activities, as follows:



|                                                      |                                |           
|----------------------------------------------------- | ------------------------------ | ----------
|                                                      | For the year ended December 31
|(thousands of dollars, except per Trust Unit amounts) | 2005                           | 2004      
|Cash provided by operating activities                 | $  237,349                     | $  136,441
|Exploration costs (1)                                 | 16,850                         | 774       
|Settlement of asset retirement obligations            | 660                            | -         
|Changes in non-cash operating working capital         | 5,359                          | 6,377     
|Cash flow                                             | $  260,218                     | $  143,592
|Cash flow per Trust Unit (2)                          | $  3.47                        | $  2.65   



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

(2)Based on weighted average Trust Units outstanding for the period.



Payout Ratio



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



Operating and Cash Flow Netbacks



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



Total Capitalization



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



CRITICAL ACCOUNTING ESTIMATES



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



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





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Accounting for petroleum and natural gas operations



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



Reserve estimates



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



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



Impairment of petroleum and natural gas properties



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



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



Asset retirement obligations



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



NEW ACCOUNTING POLICIES



Financial Instruments



Canadian Institute of Chartered Accountants (CICA) Handbook section 3860 Financial Instruments requires that fixed-amount contractual obligations that can be settled by issuing a variable number of equity instruments be classified as liabilities.  The convertible debentures previously issued by the Trust have characteristics that meet the noted criteria



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and therefore we have retroactively accounted for these instruments as debt, with a portion representing the value of the equity conversion feature in equity and reflected interest costs as interest expense in the statement of earnings.



Variable Interest Entities (VIEs)



In June 2003, the CICA issued Accounting Guideline 15 Consolidation of Variable Interest Entities (AcG-15).  AcG-15 defines VIEs as entities in which either: the equity at risk is not sufficient to permit that entity to finance its activities without additional financial support from other parties or equity investors lack voting control, an obligation to absorb expected losses or the right to receive expected residual returns.  AcG-15 harmonizes Canadian and U.S. GAAP and provides guidance for companies consolidating VIEs in which they are the primary beneficiary.  The guideline is effective for all annual and interim periods beginning on or after November 1, 2004.  We have performed a review of entities in which PET has an interest and have determined that we do not have any variable interest entities at this time.



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.



Gas Over Bitumen Issue



On January 24, 2006, the AEUB invited members in industry to a meeting to discuss its intent to commence a process with respect to bitumen conservation policies in the Cold Lake and Peace River Oil Sands Areas of Alberta.  Industry comment was solicited prior to February 14, 2006 however the AEUB has not yet announced if or how it will proceed with respect to this matter.  PET has current production of approximately 5.8 MMcf/d from the Bluesky-Gething formations in the portion of the Panny field and the Darwin field which are located within the Peace River Oil Sands Area. Gas production from these zones may be identified in the future as posing a potential concern with respect to communication with potentially recoverable bitumen resources.  This production represents less than 5% of PETs current production.  The Government of Alberta has not made comment as to whether the Gas over Bitumen Royalty Adjustment applied to shut-in gas in the Wabiskaw-McMurray in the Athabasca Oils Sands Area would apply to these other regions.  There has been no expression of concern from bitumen resource owners in the Panny or Darwin areas.



While we have no significant additional production recommended for shut-in by any party or the AEUB at this time and royalty adjustments are being received for production currently shut-in, we cannot ensure that additional production will not be shut-in in the future or that we will be able to negotiate adequate compensation for having to shut-in any such production.  This could have a material adverse effect on the amount of income available for distribution to Unitholders.



Reserve Estimates



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

·

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

·

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

·

whether natural gas and other prices will remain the same as on the date estimates are made;

·

the production performance of our reservoirs;

·

extensive engineering judgments;

·

the price at which recovered natural gas can be sold;

·

the costs associated with recovering natural gas;

·

the prevailing environmental conditions associated with drilling and production sites;

·

the availability of enhanced recovery techniques; and

·

the ability to transport natural gas to markets.



Cyclical and Seasonal Impact on Industry



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





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Operational Matters



The Trusts operations may be delayed or unsuccessful for many reasons including cost overruns, lower natural gas prices, equipment shortages, mechanical and technical difficulties and labour problems.  The Trusts operations will also often require the use of new and advanced technologies which can be expensive to develop, purchase and implement and may not function as expected.  PET may experience substantial cost overruns caused by changes in the scope and magnitude of our operations, employee strikes and unforeseen technical problems including natural hazards which may result in blowouts, environmental damage or other unexpected or dangerous conditions giving rise to liability to third parties.  In particular, drilling activities are subject to many risks, including the risk that no commercially productive reservoirs will be encountered.  Drilling for natural gas could result in unprofitable efforts, not only from dry wells but from wells that are productive but do not produce enough net revenue to return a profit after drilling, operating and other costs.  The costs of drilling, completing and operating wells are often uncertain.  In addition, our operations depend on the availability of drilling and related equipment in the particular areas where exploration and development activities will be conducted.  Demand for the equipment or access restrictions may affect the availability of that equipment and, consequently, delay operations.



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



Expansion of Operations



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



Acquisitions



The price paid for 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.





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Depletion of Reserves



The Trust has certain unique attributes which differentiate it from other oil and gas industry participants.  Distributions, absent commodity price increases or cost effective acquisition and development activities, will decline over time in a manner consistent with declining production from typical oil and natural gas reserves.  PET will not be reinvesting cash flow in the same manner as other industry participants as one of the main objectives of the Trust is to maximize long-term distributions.  Accordingly, absent capital injections, PETs initial production levels and reserves will decline.



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



To the extent that external sources of capital, including the issuance of additional Trust Units become limited or unavailable, PETs ability to make the necessary capital investments to maintain or expand its oil and natural gas reserves will be impaired.  To the extent that PET is required to use cash flow to finance capital expenditures or property acquisitions, the level of distributions will be reduced.



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



Net Asset Value



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



Insurance Risk



Exploration for natural gas and the production of natural gas are hazardous undertakings.  Further, natural disasters, operator error or other occurrences can result in oil spills, blowouts, cratering, fires, equipment failure and loss of well control, which can injure or kill people, damage or destroy wells and production facilities and damage other property and the environment.  Losses and liabilities arising from such events could significantly reduce the Trusts revenues or increase costs and have a material adverse effect on the Trusts operations or financial condition.

PET may be unable to obtain insurance against these risks at premium levels that justify its purchase.  Further, insurance may be unavailable or any insurance we may obtain may be insufficient to provide full coverage.  The occurrence of a significant event that is not fully insured could have a material adverse effect on PETs financial position and reduce or eliminate distributions to Unitholders.



Additional Financing



PETs primary source of bank financing is a demand credit facility with a syndicate of Canadian chartered banks in the amount of $310 million.  The credit facility is presently due March 31, 2006.  PET expects that the facility will be extended at that date.  If the facility is not extended the Trust will need to find alternative sources of financing.  If alternative sources of financing are not available, or are more expensive than the current credit facility, PET may be unable to effectively operate our business or pay distributions to Unitholders.



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





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Hedging



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

·

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

·

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

·

entering into fixed price contract for natural gas production;

·

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

·

entering into contracts to fix the price differential between light and heavy oil.



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



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

·

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

·

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

·

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

ceiling price.



Non-resident Ownership of Trust Units



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



Accounting Write-Downs as a Result of GAAP



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



Income Tax Legislation



The treatment of mutual fund trusts could be changed in a manner which adversely affects Unitholders.  If PET ceases to qualify as a mutual fund trust under the Income Tax Act (Canada), the Trust Units will cease to be qualified investments for registered retirement savings plans, registered education savings plans, deferred profit sharing plans and registered retirement income funds.



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



The Administrator intends that PET will continue to qualify as a mutual fund trust for purposes of the Income Tax Act (Canada).



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.



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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



Compliance with health, safety and environmental laws and regulations could materially increase the Trusts costs.  PET will incur substantial capital and operating costs to comply with increasingly complex laws and regulations covering the protection of the environment and human health and safety.  These include costs to reduce certain types of air emissions and discharges and to remediate contamination at various facilities and third party sites where the Trusts products or wastes will be handled or disposed.



PET are subject to statutory strict liability in respect of losses or damages suffered as a result of pollution caused by spills or discharges of petroleum from petroleum facilities covered by any of the Trusts licenses.  As a result, anyone who suffers losses or damages as a result of pollution caused by PETs operations can claim compensation without needing to demonstrate that the damage is due to any fault on the Trusts part.



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



·

modify operations;

·

install pollution control equipment;

·

perform site clean-ups; or

·

curtail or cease certain operations.



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



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





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Government Regulation Risk



PET operates in a highly regulated industry and it is possible any changes in such regulation or adverse regulatory decisions could affect our production which could reduce distributions to Unitholders. Additional details with respect to the gas over bitumen regulatory issue are described elsewhere in this MD&A.



Commodity Price, Foreign Exchange and Interest Rate Risk



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

·

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

·

weather conditions that influence the demand for natural gas;

·

transportation availability and costs; and

·

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



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



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



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



Nature of Trust Units



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



FORWARD-LOOKING INFORMATION



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



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



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



·

the quantity and recoverability of PETs reserves;

·

the timing and amount of future production;

·

prices for natural gas produced;

·

operating and other costs;

·

business strategies and plans of management;

·

supply and demand for natural gas;

·

expectations regarding PETs access to  capital to fund its acquisition exploration and development activities add to its reserves through acquisitions as well as through exploration and development activities;

·

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

·

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

·

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



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·

drilling, completion, facilities and construction plans;

·

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

·

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

·

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

·

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

·

PETs treatment under governmental regulatory regimes;

·

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

·

the emergence of accretive growth opportunities; and

·

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



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

·

volatility in market prices for natural gas;

·

risks inherent in PETs operations;

·

uncertainties associated with estimating reserves;

·

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

·

incorrect assessments of the value of acquisitions;

·

geological, technical, drilling and process problems;

·

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

·

industry conditions including fluctuations in the price of natural gas;

·

royalties payable in respect of PETs production;

·

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

·

fluctuation in foreign exchange or interest rates;

·

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

·

stock market volatility and market valuations; and

·

the need to obtain required approvals from regulatory authorities.



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



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





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