2010



MANAGEMENTS DISCUSSION AND ANALYSIS































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HIGHLIGHTS



|                                                             |                                |                        |          |           |           |         
|------------------------------------------------------------ | ------------------------------ | ---------------------- | -------- | --------- | --------- | --------
|FINANCIAL AND OPERATING HIGHLIGHTS                           | Three months ended December 31 | Year ended December 31
|($CDN thousands, except volume and per Common Share amounts) | 2010                           | 2009                   | % change | 2010      | 2009      | % change
|FINANCIAL                                                    |                                |                        |          |           |           |         
|Revenue (1) (2)                                              | 111,150                        | 78,852                 | 41       | 417,093   | 418,323   | -       
|Funds flow (2)                                               | 70,509                         | 39,409                 | 79       | 237,165   | 231,347   | 3       
|Per Common Share (2) (3)                                     | 0.48                           | 0.32                   | 50       | 1.69      | 1.96      | (14)    
|Cash flow provided by operating activities                   | 80,210                         | 36,446                 | 120      | 240,126   | 228,352   | 5       
|Per Common Share (3)                                         | 0.54                           | 0.29                   | 86       | 1.71      | 1.93      | (11)    
|Net earnings (loss)                                          | (19,874)                       | (11,287)               | 76       | (28,546)  | 14,393    | (298)   
|Per Common Share (3)                                         | (0.13)                         | (0.09)                 | 44       | (0.20)    | 0.12      | (266)   
|Dividends declared                                           | 16,273                         | 18,810                 | (13)     | 78,628    | 75,838    | 4       
|Per Common Share (4)                                         | 0.11                           | 0.15                   | (27)     | 0.56      | 0.64      | (13)    
|Payout ratio (%) (2)                                         | 23.1                           | 47.7                   | (52)     | 33.2      | 32.8      | 1       
|Total assets                                                 | 1,038,206                      | 1,065,305              | (3)      | 1,038,206 | 1,065,305 | (3)     
|Net bank debt outstanding (2) (5)                            | 214,546                        | 270,843                | (21)     | 214,546   | 270,843   | (21)    
|Convertible debentures, measured at principal amount         | 234,897                        | 230,168                | 2        | 234,897   | 230,168   | 2       
|Total net debt (2) (5)                                       | 449,443                        | 501,011                | (10)     | 449,443   | 501,011   | (10)    
|Shareholders equity                                         | 253,143                        | 253,879                | -        | 253,143   | 253,879   | -       
|Capital expenditures                                         |                                |                        |          |           |           |         
|Exploration and development                                  | 38,158                         | 4,512                  | 746      | 115,202   | 57,371    | 101     
|Gas storage                                                  | 11,171                         | 5,595                  | 100      | 57,587    | 10,800    | 433     
|Acquisitions, net of dispositions                            | (34,253)                       | (10,016)               | 242      | 50,653    | 103,885   | (51)    
|Other                                                        | 332                            | 377                    | (12)     | 707       | 649       | 9       
|Net capital expenditures                                     | 15,408                         | 468                    | 3,192    | 224,149   | 172,705   | 30      
|SHARES OUTSTANDING (thousands)                               |                                |                        |          |           |           |         
|End of period                                                | 148,284                        | 126,224                | 17       | 148,284   | 126,224   | 17      
|Weighted average                                             | 147,742                        | 125,064                | 18       | 140,624   | 118,181   | 19      
|Diluted                                                      | 147,742                        | 126,149                | 17       | 140,624   | 119,266   | 18      
|March 1, 2011                                                | 148,302                        |                        |          | 148,302   |           |         





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|                                                              |                                |                        |             |         |         |         
|------------------------------------------------------------- | ------------------------------ | ---------------------- | ----------- | ------- | ------- | --------
|FINANCIAL AND OPERATING HIGHLIGHTS CONTINUED                  | Three Months Ended December 31 | Year Ended December 31
|                                                              | 2010                           | 2009                   | % change    | 2010    | 2009    | % change
|OPERATING                                                     |                                |                        |             |         |         |         
|Production                                                    |                                |                        |             |         |         |         
|Average daily natural gas (MMcf/d) (6)                        | 135.9                          | 139.8                  | (3)         | 145.1   | 153.4   | (5)     
|Average daily oil and natural gas liquids ("NGL") (bbl/d) (6) | 1,535                          | 1,014                  | 51          | 1,245   | 721     | 73      
|Average daily (MMcfe/d) (6)                                   | 145.1                          | 145.9                  | (1)         | 152.6   | 157.7   | (3)     
|Per Common Share (cubic feet equivalent/d/Common Share) (3)   | 0.98                           | 1.17                   | (16)        | 1.09    | 1.33    | (18)    
|Gas over bitumen deemed production (MMcf/d) (7)               | 24.2                           | 24.6                   | (2)         | 24.8    | 19.9    | 25      
|Average daily (actual and deemed  MMcfe/d) (6) (7)           | 169.3                          | 170.5                  | (1)         | 177.4   | 177.6   | -       
|Per Common Share (cubic feet equivalent/d/Common Share) (3)   | 1.15                           | 1.36                   | (15)        | 1.26    | 1.50    | (16)    
|Average prices                                                |                                |                        |             |         |         |         
|Natural gas  before financial instruments ($/Mcf) (8)        | 3.87                           | 3.94                   | (2)         | 4.17    | 4.12    | 1       
|Natural gas - including financial instruments ($/Mcf) (8)     | 7.83                           | 5.53                   | 42          | 7.10    | 7.09    | -       
|Oil and NGL ($/bbl)                                           | 75.88                          | 67.33                  | 13          | 68.29   | 61.91   | 10      
|RESERVES (Bcfe)                                               |                                |                        |             |         |         |         
|Company interest  proved (9) (10)                            | 250.4                          | 244.4                  | 2           | 250.4   | 244.4   | 2       
|Company interest - proved and probable (9) (10)               | 487.7                          | 471.6                  | 3           | 487.7   | 471.6   | 3       
|Per Common Share (Mcfe/Common Share) (12)                     | 3.29                           | 3.74                   | (12)        | 3.29    | 3.74    | (12)    
|Estimated present value before tax ($ millions) (11)          |                                |                        |             |         |         |         
|Proved                                                        | 710.4                          | 834.6                  | (15)        | 710.4   | 834.6   | (15)    
|Proved and probable                                           | 1,201.1                        | 1,387.3                | (13)        | 1,201.1 | 1,387.3 | (13)    
|LAND (thousands of net acres)                                 |                                |                        |             |         |         |         
|Total land holdings                                           | 3,421                          | 3,759                  | (9)         | 3,421   | 3,759   | (9)     
|Undeveloped land holdings                                     | 1,905                          | 2,093                  | (9)         | 1,905   | 2,093   | (9)     
|DRILLING (wells drilled gross/net)                            |                                |                        |             |         |         |         
|Gas                                                           | 3/2.4                          | 3/2.5                  | -/(4)       | 48/44.3 | 46/36.2 | 4/22    
|Oil                                                           | 3/1.0                          | 2/2.0                  | 50/(50)     | 14/11.6 | 2/2.0   | 600/480 
|Gas storage                                                   | -/-                            | 4/4.0                  | (100)/(100) | 6/6.0   | 4/4.0   | 50/50   
|Service                                                       | 1/1.0                          | -/-                    | 100/100     | 1/1.0   | -/-     | 100/100 
|Dry                                                           | -/-                            | -/-                    | -/-         | 1/1.0   | -/-     | 100/100 
|Total                                                         | 7/4.4                          | 9/8.5                  | (22)/(48)   | 70/63.9 | 52/42.2 | 35/51   
|Success rate                                                  | 100/100                        | 100/100                | -/-         | 99/98   | 100/100 | (1)/(2) 

(1)

Revenue includes realized gains and losses on financial instruments and call option premiums received.

(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 weighted average Common Shares outstanding for the period.

(4)

Based on Common Shares outstanding at each dividend payment date.

(5)

Net bank debt is measured as at the end of the period and includes net working capital (deficiency), excluding short-term financial instrument assets and liabilities related to the Corporations hedging activities, the current portion of convertible debentures and the option plan liability. Total net debt includes convertible debentures, measured at principal amount.

(6)

Production amounts are based on the Corporations interest before deduction of royalties.

(7)

Deemed production describes all gas shut-in or denied production pursuant to a decision report, corresponding order or general bulletin of the Alberta Energy and Utilities Board ("AEUB"), or through correspondence in relation to an AEUB ID 99-1 application. This deemed production is not actual gas sales but represents shut-in gas that is the basis of the gas over bitumen ("GOB") financial solution received monthly from the Alberta Crown as a reduction of other royalties payable. See
"Gas over bitumen royalty adjustments" in Managements Discussion and Analysis.

(8)

Perpetuals commodity hedging strategy employs both financial forward contracts and physical natural gas delivery contracts at fixed prices or price collars.

(9)

As evaluated by McDaniel & Associates Consultants Ltd. ("McDaniel") and GLJ Petroleum Consultants Ltd. ("GLJ") in accordance with National Instrument 51-101. See
"Reserves" included in this Managements Discussion and Analysis.



(10)

Reserves are presented on a company interest basis, including working interest and royalty interest volumes but before royalty burdens.

(11)

Discounted at five percent using McDaniel and GLJs forecast pricing. Reserves at various other discount rates are located in the
"Reserves" section of Managements Discussion and Analysis. Estimated present value amounts should not be taken to represent an estimate of fair market value.

(12)

Based on Common Shares outstanding at period end.





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MANAGEMENTS DISCUSSION AND ANALYSIS



The following is managements discussion and analysis ("MD&A") of Perpetual Energy Inc.s ("Perpetual" or the
"Corporation") operating and financial results for the year ended December 31, 2010 as well as information and estimates concerning the Corporations future outlook based on currently available information. This discussion should be read in conjunction with the Corporations audited consolidated financial statements for the years ended December 31, 2010 and 2009, together with accompanying notes.  Readers are referred to the advisories regarding forecasts, assumptions and other forward-looking information contained in the
"Forward Looking Information" section of this MD&A.  The date of this MD&A is March 7, 2011.



Mcf equivalent ("Mcfe") and barrel of oil equivalent ("BOE") may be misleading, particularly if used in isolation. In accordance with National Instrument 51-101 ("NI 51-101"), a conversion ratio for oil of 1 bbl: 6 Mcf has been used, which is based on an energy equivalency conversion method primarily applicable at the burner tip and does not necessarily represent a value equivalency at the wellhead. For natural gas, gigajoules ("GJ") are converted to Mcf at a conversion ratio of 1.0546 GJ: 1 Mcf.



CORPORATE



On June 30, 2010, Perpetual announced that the Corporation had completed the previously announced plan of arrangement (the
"Arrangement") involving Perpetual, Paramount Energy Trust (the "Trust") and Paramount Energy Operating Corp. pursuant to which the Trust converted into the Corporation. Unitholders of the Trust voted in favor of the Arrangement at the Annual General and Special Meeting of Trust Unitholders held on June 17, 2010. Former Unitholders of the Trust received common shares of Perpetual in consideration for the cancellation of their Trust Units on a one-for-one basis. In addition, as part of the Arrangement, the Trust was dissolved and the Corporation assumed all of the existing liabilities of the Trust, including the Trust's outstanding convertible debentures which are now convertible debentures of the Corporation.



Perpetual believes that the conversion will provide the Corporation with broadened access to capital markets by eliminating the constraints of the income trust structure imposed by changes to the trust tax legislation introduced by the federal government in 2006.  In addition, Canadian taxable Shareholders now benefit from what the Corporation believes to be a more tax-effective treatment of their cash dividends following the conversion to a corporate structure, relative to the tax treatment of the distributions which were paid to Unitholders prior to the corporate conversion.



References to "Common Shares" and
"Shareholders" are references to the securities of the Corporation and the holders thereof following the conversion date, and references to
"dividends" are references to dividends paid by Perpetual following the conversion date and to distributions paid by the Trust prior to the conversion date, as the context may require. The new trading symbol for Perpetuals common shares is PMT on the Toronto Stock Exchange. The trading symbols for the Corporations convertible debentures have not changed since the conversion date.



SIGNIFICANT ACCOUNTING POLICIES AND NON-GAAP MEASURES



Successful efforts accounting



The Corporation 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 are expensed rather than capitalized in the year incurred.  However, to allow reported funds flow in this MD&A to be comparable to industry practice, the Corporation reclassifies dry hole costs, geological and geophysical costs and surrendered leases from operating to investing activities in the funds flow reconciliation.



Funds flow



Management uses cash flow from operations before changes in non-cash working capital, gas over bitumen royalty adjustments not yet received, settlement of asset retirement obligations and certain exploration costs ("funds flow"), funds flow per common share and annualized funds flow to analyze operating performance and leverage. Funds 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.  Funds flow as presented is not intended to represent operating profits for the period nor should it be viewed as an alternative to cash flow provided by operating activities, net earnings or other measures of financial performance calculated in accordance with GAAP.  Funds flow is reconciled to its closest GAAP measure, cash flow provided by operating activities, as follows.



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|                                                      |                                        |                                |          |         
|----------------------------------------------------- | -------------------------------------- | ------------------------------ | -------- | --------
|Funds flow GAAP reconciliation                        | For the three months ended December 31 | For the year ended December 31
|($ thousands, except per Common Share amounts)        | 2010                                   | 2009                           | 2010     | 2009    
|Cash flow provided by operating activities            | 80,210                                 | 36,446                         | 240,126  | 228,352 
|Exploration costs (1)                                 | 1,483                                  | 646                            | 4,030    | 6,402   
|Expenditures on asset retirement obligations          | 1,201                                  | 802                            | 4,880    | 3,715   
|Gas over bitumen royalty adjustments not yet received | 1,393                                  | 5,138                          | 3,357    | 5,138   
|Changes in non-cash operating working capital         | (13,778)                               | (3,623)                        | (15,228) | (12,260)
|Funds flow                                            | 70,509                                 | 39,409                         | 237,165  | 231,347 
|Funds flow per Common Share (2)                       | 0.48                                   | 0.32                           | 1.69     | 1.96    

(1)

Certain
exploration costs are added back to funds flow in order to be more comparable to
other Corporations that use the full cost method of accounting for oil and gas
activities.  Exploration costs that are added back to funds flow include
seismic expenditures and dry hole costs and are considered by Perpetual to be
more closely related to investing activities than operating activities.

(2)

Based on weighted average Common Shares outstanding for the period.



Additional significant and new accounting policies and non-GAAP measures are discussed elsewhere in this MD&A.



DISCLOSURE CONTROLS AND PROCEDURES



Disclosure controls and procedures have been designed to ensure that information required to be disclosed by the Corporation is accumulated and communicated to the Corporations management, as appropriate, to allow timely decisions regarding required disclosure.  The Corporations Chief Executive Officer and Chief Financial Officer have concluded, based on their evaluation as of December 31, 2010 (the
"Evaluation Date"), that the Corporation's disclosure controls and procedures as of the Evaluation Date are effective to provide reasonable assurance that material information related to the Corporation, including its consolidated subsidiaries, is made known to them by others within those entities.



INTERNAL CONTROLS OVER FINANCIAL REPORTING



Internal controls have been designed to provide reasonable assurance regarding the reliability of the Corporation's financial reporting and the preparation of financial statements together with the other financial information for external purposes in accordance with Canadian Generally Accepted Accounting Principles ("GAAP").  As of December 31, 2010, the Corporation's Chief Executive Officer and Chief Financial Officer have designed or caused to be designed under their supervision internal controls over financial reporting related to the Corporation, including its consolidated subsidiaries, and have concluded that these controls are operating effectively.



The Corporation's Chief Executive Officer and Chief Financial Officer are required to cause the Corporation to disclose herein any change in the Corporation's internal control over financial reporting that occurred during the Corporation's most recent interim period that materially affected, or is reasonably likely to materially affect the Corporation's internal control over financial reporting.  During 2010, the Corporation engaged external consultants to assist in assessing the Corporation's design of internal controls over financial reporting.  No material changes were identified in the Corporation's internal control of financial reporting during the year ended December 31, 2010, that had materially affected, or are reasonably likely to materially affect, the Corporation's internal control over financial reporting.



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



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



CHANGES TO INTERNAL CONTROLS AND PROCEDURES FOR FINANCIAL REPORTING



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



CORPORATE GOVERNANCE



The Corporation is committed to maintaining high standards of corporate governance.  Each regulatory body, including the Toronto Stock Exchange, the Canadian provincial securities commissions and the Securities and Exchange Commission (whose responsibilities include implementing rules under the United States Sarbanes-Oxley Act of 2002)
has a different set of rules pertaining to corporate governance. The Corporation fully conforms to the rules of the governing bodies under which it operates.





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FOURTH QUARTER 2010 RESULTS



|                                                                                        |                                |                   |           
|--------------------------------------------------------------------------------------- | ------------------------------ | ----------------- | ----------
|Fourth quarter information                                                              | Three months ended December 31
|($ thousands except as noted)                                                           | 2010                           | 2009              | % change  
|Average daily production volumes
Natural gas (MMcf/d)
Oil & NGL (bbl/d)
Total (MMcfe/d) | 135.9
1,535
145.1              | 139.8
1,014
145.9 | (3)
51
(1)
|                                                                                        |                                |                   |           
|Natural gas revenue                                                                     | 48,412                         | 50,703            | (5)       
|Oil and NGL revenue                                                                     | 10,711                         | 6,284             | 70        
|Gas storage revenue                                                                     | 2,595                          | -                 | 100       
|Realized gains (losses) on financial instruments                                        | 49,432                         | 20,456            | 142       
|Call option premiums received                                                           | -                              | 1,409             | (100)     
|Oil and natural gas revenue, after financial instruments                                | 111,150                        | 78,852            | 41        
|                                                                                        |                                |                   |           
|AECO Monthly Index ($/Mcf)                                                              | 3.58                           | 4.23              | (15)      
|Natural gas price, before financial hedging ($/Mcf)                                     | 3.87                           | 3.94              | (2)       
|Realized natural gas price ($/Mcf)                                                      | 7.83                           | 5.53              | 42        
|WTI Average Price ($US/bbl)                                                             | 90.77                          | 76.19             | 19        
|Realized oil and NGL price ($/bbl)                                                      | 75.88                          | 67.33             | 13        
|Royalties                                                                               | 2,727                          | 2,986             | (9)       
|Royalties as a percentage of revenues (%)                                               | 2.5                            | 3.8               | (34)      
|                                                                                        |                                |                   |           
|Operating expenses                                                                      | 20,826                         | 18,970            | 10        
|Per Mcfe                                                                                | 1.56                           | 1.41              | 11        
|                                                                                        |                                |                   |           
|Cash general and administrative ("G&A") expenses                                        | 9,286                          | 10,105            | (8)       
|Per Mcfe                                                                                | 0.70                           | 0.75              | (7)       
|                                                                                        |                                |                   |           
|Funds flow                                                                              | 70,509                         | 39,409            | 79        
|Per Common Share                                                                        | 0.48                           | 0.32              | 50        
|                                                                                        |                                |                   |           
|Cash flow provided by operating activities                                              | 80,210                         | 36,446            | 120       
|Per Common Share                                                                        | 0.54                           | 0.29              | 86        
|                                                                                        |                                |                   |           
|Net earnings (loss)                                                                     | (19,874)                       | (11,287)          | 76        
|Per Common Share                                                                        | (0.13)                         | (0.09)            | 44        
|                                                                                        |                                |                   |           
|Capital expenditures  exploration and development                                      | 38,158                         | 4,512             | 746       
|Capital expenditures  gas storage                                                      | 11,171                         | 5,595             | 100       



In comparing the three months ended December 31, 2010 with the fourth quarter of 2009:



Capital expenditures



·

Exploration and development expenditures increased to $38.2 million for the fourth quarter from $4.5 million for the comparative quarter in 2009. Perpetual expanded its 2010 capital budget in the fourth quarter to accelerate the development of its Cardium oil and liquids-rich Wilrich assets in west central Alberta, and its heavy oil program at Birchwavy. In total 7 wells (4.4 net) were drilled with a 100 percent success rate, including three horizontal wells targeting the Wilrich formation and one Cardium oil well. Perpetual also completed the expansion of a compressor station at Edson during the quarter, adding 20 MMcf/d of commercial processing capacity with associated liquids of 40 bbls per MMcf. Additional capital expenditures of $11.2 million were incurred for the construction and final testing of the Corporations commercial gas storage facility at Warwick, Alberta ("WGSI Facility"). The WGSI Facility was fully operational in January 2011.



·

The second well of a three-well commitment was drilled and completed by Perpetuals joint venture partner into the Montney formation at Elmworth, as part of a previously announced farm-out agreement. The well
was completed and flow-tested at approximately 7.5 MMcf/d of raw natural gas with 20 bbls of associated free condensate per MMcf and an additional 20 to 45 bbls of NGLs per
MMcf. The third well was rig released on January 11, 2011 and completed later that month. Difficulties encountered during completion restricted the flow test but the extent of the Montney natural gas resource was established as expected.





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Production & Pricing



·

Oil and NGL production increased 51 percent to 1,535 bbl/d due to successful Cardium oil, Wilrich liquids rich gas, and Mannville heavy oil drilling programs in the second half of 2010, partially offset by a non-core oil property disposition closed in April 2010. Natural gas production declined three percent due to natural declines, non-core asset dispositions, and the shut-in of natural gas production at Legend by the Energy Resources Conservation Board ("ERCB") in November 2009 due to gas over bitumen concerns, partially offset by the acquisition of assets in the Edson area of Alberta in April 2010 ("Edson Acquisition") and drilling activities on those and other lands in the West Central District, as well as production additions from shallow gas drilling in the Eastern district concentrated in the first quarter of the year.



·

Natural gas prices before financial hedging declined two percent due to lower AECO Monthly Index prices, partially offset by the inclusion of 10,000 GJ/d of fixed price physical natural gas sales at $7.75 per GJ for November to December 2010. Realized gas prices increased by $2.30 per Mcf, driven by realized hedging gains of $49.4 million in the current quarter, as compared to $20.5 million for the three months ended December 31, 2009. Included in hedging gains for the current period is $37.3 million related to the early termination of all outstanding fixed-price financial forward contracts in November 2010. Perpetuals realized oil & NGL price increased 13 percent to $75.88 per bbl, in line with an increase in average West Texas Intermediate ("WTI") posted prices of 12 percent for the period.



Financial



·

Despite a 15 percent decrease in the AECO Monthly Index gas price, funds flow increased $31.1 million to $70.5 million for the current quarter due to higher realized gains on financial instruments combined with lower royalty expenses. An increase in the liquids component of the Corporations production mix also contributed to higher funds flows, as oil and natural gas revenues increased by $4.4 million compared to the prior period.



·

The Corporations royalty rate of 2.5 percent of revenues was 34 percent less than 2009 and lower than the Corporations historical royalty rates due to lower AECO gas prices, realized gains on financial instruments in the fourth quarter of 2010 and a recovery of $1.5 million in royalties related to prior years.



·

Cash G&A expenses decreased $0.8 million from the fourth quarter of 2009 due to increased overhead recoveries as a result of higher exploration and development expenditures as compared to the prior period.



·

Operating costs increased $1.8 million ($0.15 per Mcfe) primarily due to gas processing fees related to the Edson assets and higher chemicals charges.



·

Net loss totaled $19.9 million for the three months ended December 31, 2010, as higher funds flows were offset by an unrealized loss on financial instruments of $47.7 million for the period due to the settlement of all outstanding financial forward sale contracts during the fourth quarter of 2010.



·

Dividends for the fourth quarter of 2010 totaled $0.11 per Common Share, including $0.05 per Common Share paid on November 15, 2010, and $0.03 per Common Share paid on December 15, 2010 and January 17, 2011. Perpetuals payout ratio, which refers to dividends measured as a percentage of funds flow, was 23.1 percent for the quarter.







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ANNUAL RESULTS



|                                                                                  |                   |                 |                 | 
|--------------------------------------------------------------------------------- | ----------------- | --------------- | --------------- | 
|($ millions, except volumes and per Common Shares amounts)                        | 2010              | 2009            | 2008           
|Cash flow provided by operating activities                                        | 240.1             | 228.4           | 259.8          
|Cash flow provided by operating activities per Common Share(2)                    | 1.71              | 1.93            | 2.33           
|Funds flow (1)                                                                    | 237.2             | 231.3           | 275.4          
|Funds flow per Common Share(1) (2)                                                | 1.69              | 1.96            | 2.47           
|Net earnings (loss)                                                               | (28.5)            | 14.4            | 30.8           
|Dividends                                                                         | 78.6              | 75.8            | 133.9          
|Dividends per Common Share(3)                                                     | 0.56              | 0.64            | 1.20           
|Payout ratio (%) (1)                                                              | 33.2              | 32.8            | 48.6           
|Exploration and development expenditures                                          | 115.2             | 57.4            | 126.1          
|Gas storage capital expenditures                                                  | 57.6              | 10.8            | -              
|Acquisitions,net of dispositions                                                  | 50.7              | 103.9           | (18.5)         
|Total capital expenditures (including acquisitions, net of  dispositions)         | 224.1             | 172.7           | 109.2          
|Net bank and other debt outstanding at December 31 (4)                            | 214.5             | 270.8           | 284.9          
|Convertible debentures, measured at principal amount                              | 234.9             | 230.2           | 236.0          
|Total net debt at December 31 (4)                                                 | 449.4             | 501.0           | 520.9          
|Total net debt per Common Share(4) (6)                                            | 3.03              | 3.97            | 4.61           
|Daily average production (5)                                                      |                   |                 |                
|Natural gas (MMcf/d)
Oil & NGL (bbl/d)
Total (MMcfe/d)                            | 145.1
1,245
152.6 | 153.4
721
157.7 | 179.2
502
182.2
|Gas over bitumen deemed production                                                | 24.8              | 19.9            | 19.2           
|Total average daily (actual and deemed)                                           | 177.4             | 177.6           | 201.4          
|Production per Common Share
(cubic feet equivalent/d/Share)(2)                    | 1.09              | 1.33            | 1.63           
|Production per Common Share actual and deemed
(cubic feet equivalent/d/Share)(2) | 1.26              | 1.50            | 1.81           

(1)

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

(2)

Based on weighted average Common Shares outstanding for the period.

(3)

Based on Common Shares outstanding at each cash dividend date.

(4)

Net debt is measured as at the end of the period and includes net working capital (deficiency) excluding short-term financial instrument assets and liabilities related to the Corporations hedging activities, the current portion of convertible debentures and share option plan liabilities. Total net debt includes convertible debentures. Please refer to
"Significant accounting policies and non-GAAP measures" included in this MD&A.

(5)

Production amounts are based on company interest (working interest and royalties receivable) before royalties payable.

(6)

Based on Common Shares outstanding at period end.



Capital expenditures



·

On April 1, 2010 Perpetual closed the acquisition of oil and natural gas assets in the Edson area of west central Alberta for $123.2 million after adjustments (the
"Edson Acquisition"), enhancing the Corporations expanding footprint in the Pembina-Carrot Creek-Edson area. The acquisition included approximately 10 MMcfe/d of natural gas and liquids production as well as extensive gathering and processing infrastructure and undeveloped lands in a desirable multi-zone part of the Western Canadian Sedimentary Basin. As part of the acquisition, Perpetual agreed to farm-in on 37 gross (31 net) sections of undeveloped Cardium rights in the area of which 22 net sections are believed to be prospective for light oil. The Edson Acquisition was partially funded with an issuance of 12.1 million Common Shares at a price of $4.75 each for gross proceeds of $57.5 million.



·

Exploration and development capital spending increased to $115.2 million in 2010 from $57.4 million in 2009, as Perpetual accelerated drilling activities on the high-impact resource plays in west central Alberta obtained through the Profound and Edson Acquisitions and grassroots exploration efforts. In total 70 wells were drilled (63.9 net) with a 98 percent net success rate.



·

Perpetual completed the construction and testing of its gas storage facility at Warwick, Alberta (the
"WGSI Facility") at a total cost of $68 million, and commenced commercial operations, injecting third party natural gas beginning in May 2010 and withdrawing gas in January 2011. The Corporation expects to incur an additional $5 million in capital costs in 2011 to complete the installation of structural and safety equipment
around the facility and drill two additional injection wells to increase capacity. The WGSI Facility generated operating cash flows of $6.6 million in 2010, which is expected to increase as the initial test cycle concludes and the the working gas capacity is increased in future years. WGSI is a non-depleting asset and provides a complementary diversified cash flow stream to the Corporations existing natural gas assets.





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·

The Corporation disposed of non-core gas over bitumen assets in the Northern district for $39.8 million. As part of the disposition agreements, Perpetual will continue to receive the gas over bitumen financial solution royalty reductions related to the sold wells, although effective ownership of the natural gas reserves will be transferred to the buyers. As a result, Perpetual expects there will be no material impact on future funds flow as a result of this disposition. In total Perpetual sold $91.2 million in non-core properties in 2010 representing 12.2 MMcfe/d of production at the time of the dispositions, providing additional liquidity while high-grading the Corporations asset base.



Financial



·

Funds flow increased three percent to $237.2 million in 2010 as compared to $231.3 million for 2009 due primarily to higher oil and NGL production and lower operating costs.



·

As a result of funds flows in excess of dividends and exploration and development expenditures and non-core property dispositions, Perpetual reduced net bank debt by 21 percent from $270.8 million at December 31, 2009 to $214.5 million at December 31, 2010. Including Perpetuals convertible debentures of $234.9 million, total net debt dropped ten percent from $501.0 million at December 31, 2009 to $449.4 million at December 31, 2010.



·

The Corporation declared dividends of $78.6 million or $0.56 per Common Share in 2010, representing 33.2 percent of funds flow for the year. Cumulative dividends from the inception of the Trust in 2003 to year-end 2010 totaled over $1.1 billion ($14.324 per Common Share).



Production & Reserves



·

The Corporations average gas price including financial hedging and physical forward sales ("realized" gas price) increased marginally to $7.10 per Mcf in 2010 from $7.09 per Mcfd in 2009 despite lower AECO monthly index prices of $4.13 per Mcf and $4.14 per Mcf in 2010 and 2009 respectively.  The Corporations realized gas price was substantially bolstered by its proactive natural gas price risk management strategy in 2010, realizing $155.0 million in gains on financial instruments and $1.9 million in call option premiums (2009 - $166.3 million and $5.7 million respectively), and providing a measure of stability to realized prices and funds flows.



·

Daily average production decreased three percent to 152.6 MMcfe/d in 2010 as a result of non-core asset dispositions, the shut-in of natural gas production at Legend in November 2009 due to gas over bitumen concerns and natural production declines, partially offset by the Edson Acquisition and successful exploration and development activities during the year.



·

In 2010, Perpetual added 71.8 Bcfe (12.0 MMboe) of proved and probable reserves, replacing 129 percent of its production (111 percent on a total proved basis). After dispositions of 53.1 Bcfe (8.9 MMboe) and production of 55.7 Bcfe (9.3 MMboe) in 2010, proved and probable reserves increased three percent from 471.6 Bcfe (78.6 MMboe) at year-end 2009 to 487.7 Bcfe (81.3 MMboe) and proved reserves increased two percent to 250.4 Bcfe (41.7 MMboe) at year-end 2010. Including changes in future development capital ("FDC"), Perpetual realized finding and development costs ("F&D") of $1.69 per Mcfe ($10.14 per BOE) on a proved and probable reserve basis in 2010.



·

Perpetuals realized finding, development and acquisition costs ("FD&A"), including changes in FDC, were $2.16 per Mcfe ($12.96 per BOE) on a proved and probable basis. FD&A costs were significantly impacted by relatively low disposition metrics on a reserve basis associated with the sale of probable shut-in gas over bitumen reserves of 34.2 Bcf without the related effective fundsflow from future royalty reductions for net proceeds of $39.8 million. Perpetual retained the effective funds flow for these shut-in gas over bitumen reserves making the asset sales incomparable to other transactions, therefore the proceeds and reserves associated from these dispositions have been removed for purposes of the FD&A calculation.



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OPERATIONS



Properties



In recent years Perpetual has consciously moved to enhance its asset base and prospect inventory, adding an element of higher impact, growth oriented, resource-style opportunities to its asset portfolio, primarily in west central Alberta and also through exposure to heavy oil and bitumen opportunities in eastern Alberta.



Perpetual made significant progress in 2010 progressing its asset base transition from its legacy asset base of conventional shallow natural gas assets in northeast and east central Alberta to add commodity and play diversification with conventional heavy oil and resource-style liquids rich gas and oil plays in the Alberta deep basin. In the fourth quarter of 2010, approximately 15 percent of production came from Perpetuals resource-style assets in west central Alberta and this is expected to grow to over 25 percent in 2011.



Perpetuals producing assets were 94 percent natural gas in 2010 and 100 percent concentrated in Alberta.



Eastern District



The Eastern District is geographically comprised of assets in northeast and east central Alberta. Perpetuals legacy gas producing assets transferred with its spin out from Paramount Resources Ltd. in 2003, complemented with consolidating and operationally synergistic asset acquisitions. Production in this multi-zoned potential area is from over ten different Cretaceous or Devonian aged reservoirs and consists of both conventional and tight unconventional shallow gas reservoirs. The northern part of this district largely overlaps the Athabasca Oil Sands area and the Corporation has also amassed a material inventory of oil sands leases for future development that will require a variety of subsurface recovery technologies.



The vast majority of Perpetuals shallow gas properties feature well established, high working interest production and most are operated by Perpetual.  The base shallow gas production profile is predictable due to the lengthy production histories and the large number of independent producing entities in Perpetuals asset base.  The large number of wells and facilities means unexpected downtime at any single site does not have a material impact on overall production.



Competitive operating costs and access to markets proximal to the producing properties combine to deliver relatively high field netbacks. Perpetual has an extensive inventory of low cost opportunities for value creation including workovers, uphole recompletions and an inventory of drilling prospects which extends throughout the shallow gas asset base. The Corporation has a history of adding production through relatively modest capital expenditures to offset most of the annual natural production declines. Strategic infrastructure ownership provides additional opportunities to add value through operating synergies and economies of scale.



Northeast  The Northeast area has been Perpetuals largest core area measured by production and total acreage, and is comprised primarily of the original assets acquired from Paramount Resources at the inception of the Trust in 2003. Significant areas of production in this core area include Liege, Saleski, Woodenhouse, Cold Lake, Craigend and Leismer. Production is primarily from the Devonian Grosmont and various overlying Cretaceous formations.  The majority of the shut-in gas related to the gas over bitumen issue is in the Wabiskaw-McMurray formation in this area. Production was shut-in in 2003 and 2004 as a result of shut-in orders related to the gas over bitumen regulatory issue. Production at Legend was shut-in on October 31, 2009 as a result of an interim ERCB shut-in order related to a more recent gas over bitumen dispute with oil sands owners in the area. The shut-in assets at Legend were sold in 2010.



Athabasca  Athabasca includes assets south and west of the Corporations original spin-out assets in the Northeast area. Production is from multiple stratigraphic horizons including Cretaceous clastic and Devonian carbonate reservoirs. Significant gas producing properties in this core operating area include Calling Lake, Darwin, Marten Hills, Mitsue, Panny, Peter Lake and Wabasca/Hoole.



Bitumen/Heavy Oil  Perpetual has over 333,000 net acres of bitumen rights within the northeast area of the Eastern District, including leases at Liege, Ells, Clyde, Saleski, Panny, Wabasca Lake, Calling Lake and Marten Hills. Certain reservoirs exhibit potential to achieve production through cold-flow technology whereas others will likely require intensive thermal recovery techniques to develop the bitumen resource. Perpetual is in the process of drilling evaluation wells on several leases to further define the resource potential of its bitumen leaseholdings.



Birchwavy East  Shallow gas production from the Birchwavy East area is primarily from Colony channel reservoirs in the Cretaceous Mannville zone as well as other conventional Mannville sand reservoirs.  In addition, unconventional, tight, shallow gas resource play potential in the Viking and Colorado Group extend across these asseMannville and Duvernay are the largest properties in this area. The region also has multiple horizons with medium and heavy oil
accumulations.  Perpetual has defined and initiated development of several medium and heavy oil pools in Birchwavy East.  The oil quality is consistent with Western Canadian Blend at
Hardisty.



Birchwavy West - Warwick, Bruce and Killam areas of central Alberta are the major producing properties in this core area.  A significant inventory of proved and probable undeveloped reserves in the resource play in the Viking formation is booked in this area. As in Birchwavy East, this area holdssignificant potential for Viking and Colorado shale gas development in the future.





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West Central District



The strategic focus on growth in west central Alberta was initiated in 2008 with the purchase of a significant Crown acreage position for Montney gas in the Elmworth area south of Grande Prairie. In 2009, Perpetual completed the acquisitions of Profound Energy Inc. ("Profound") with focused assets in the Pembina/Carrot Creek area, and in 2010 acquired additional assets in the Edson area ("Edson Acquisition") to further establish the West Central district.



Production is established from the greater Pembina area and includes light crude oil from the cardium, second white specks, ostracod, ellerslie and fernie sand formations. Liquids-rich natural gas (20 to 40 bbl/MMcf) comes from both vertical wells with multiple commingled Cretaceous and Jurassic aged objectives ,and horizontal well with multi-stage fracture stimulations in the Wilrich,Notikewin and Rock Creek formations. The West Central lands complement the Corporations existing shallow gas prospect inventory with higher impact, deep basin style resource play opportunities, and the liquids production provides diversification of commodity price risk. Development and exploitation of the reserves is being undertaken with both vertical wells and horizontal wells with.



Elmworth Montney Through grass roots exploration efforts and successful Crown lands sale purchases, Perpetual acquired material exposure to the Montney liquids-rich gas play developing at Elmworth in west central Alberta.  To manage operational and technical risk, Perpetual entered into a joint venture arrangement with an industry partner whereby the partner would fund and operate three wells to evaluate the lands to earn a 50 percent working interest. The farm-in arrangement was completed in January 2011, and as a result Perpetual has a 50 percent interest in 78 sections of land with contingent resource and reserves established for Montney gas development.



Warwick Gas Storage Inc. ("WGSI")



In late 2009, Perpetual initiated the development of a  partially depleted gas reservoir within the Corporations existing asset base near Vegreville, Alberta for commercial gas storage purposes. The WGSI Facility  is located in close proximity to Alberta gas transmission lines. The injection phase of the first test cycle began in May 2010 and the WGSI Facility was fully operational for withdrawal as of January 2011, following construction of compression and other facilities. The WGSI Facility is currently in the withdrawal phase of the test cycle and is capable of withdrawal of third party natural gas at rates of up to 205 MMcf/d.



Production



|                                      |                   |              |                 |                   |              |                 |                   |              |                
|------------------------------------- | ----------------- | ------------ | --------------- | ----------------- | ------------ | --------------- | ----------------- | ------------ | ---------------
|Production by core area and commodity |                   |              | 2010            |                   |              | 2009            |                   |              | 2008           
|Eastern District                      | Oil & NGL
(bbl/d) | Gas
(MMcf/d) | Total (MMcfe/d) | Oil & NGL
(bbl/d) | Gas
(MMcf/d) | Total (MMcfe/d) | Oil & NGL
(bbl/d) | Gas (MMcf/d) | Total (MMcfe/d)
|Northeast (1)                         | -                 | 41.2         | 41.2            | -                 | 57.5         | 57.5            | -                 | 68.9         | 68.9           
|Athabasca (2)                         | 49                | 38.8         | 39.1            | 62                | 46.9         | 47.3            | 64                | 59.1         | 59.5           
|Birchwavy West                        | 27                | 19.0         | 19.2            | 44                | 16.1         | 16.4            | 95                | 22.0         | 22.6           
|Birchwavy East                        | 180               | 27.2         | 28.3            | 299               | 26.2         | 28.0            | 337               | 27.5         | 29.5           
|Eastern District total                | 256               | 126.2        | 127.8           | 405               | 146.7        | 149.2           | 496               | 177.5        | 180.5          
|West Central District                 | 986               | 18.2         | 24.1            | 312               | 5.6          | 7.5             | -                 | -            | -              
|Other                                 | 3                 | 0.7          | 0.7             | 4                 | 1.0          | 1.0             | 6                 | 1.7          | 1.7            
|Total                                 | 1,245             | 145.1        | 152.6           | 721               | 153.4        | 157.7           | 502               | 179.2        | 182.2          







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|                                                               |       |       |      
|-------------------------------------------------------------- | ----- | ----- | -----
|Average total daily production (MMcfe/d)                       | 2010  | 2009  | 2008 
|Average daily production                                       | 152.6 | 157.7 | 182.2
|Deemed production from gas over bitumen financial solution (1) | 24.8  | 19.9  | 19.2 
|Total actual plus deemed production                            | 177.4 | 177.6 | 201.4

(1)

Effective October 31, 2009 the Energy Resources Conservation Board ("ERCB") ordered the shut-in of approximately 8.6 MMcf/d of natural gas production from Perpetuals Legend property in the Northeast core area due to gas over bitumen concerns. The Corporation shut-in an additional 1.9 MMcf/d of gas production due to the shut-in of facilities in the area. The majority of this production qualified for the gas over bitumen financial solution, and as such has been added to Perpetuals deemed production.

(2)

Perpetual has a controlling interest in Severo Energy Corp. ("Severo"), a private company engaged in oil and gas exploration in Canada. Since the Corporation retained control of Severo, the results, assets and liabilities of this entity have always been included in Perpetuals financial statements. Effective October 5, 2010 Perpetual purchased the remaining 11 percent interest in Severo and Severo became a wholly-owned subsidiary of the Corporation. As such, the Severo assets have been included in the Athabasca area.



Natural gas production volumes decreased five percent to 145.1 MMcf/d in 2010 from 153.4 MMcf/d in 2009, primarily due to the full year effect of shut-in of natural gas production by the ERCB at Legend in November 2009 and non-core property dispositions during the year, partially offset by the Edson Acquisition completed on April 1, 2010. Oil and NGL production volumes increased 524 bbl/d or 73 percent from 2009 levels due to positive results from capital spending in the Edson and Carrot Creek areas targeting oil and liquids rich gas and an increased focus on development of several heavy oil pools in eastern Alberta. Total actual and deemed production was unchanged year over year at 177.4 MMcfe/d as compared to 177.6 MMcfe/d in 2009.



Capital expenditures



|                                   |          |          |         
|---------------------------------- | -------- | -------- | --------
|Capital expenditures ($ thousands) | 2010     | 2009     | 2008    
|Exploration and development (1)    | 101,365  | 53,463   | 99,512  
|Crown and freehold land purchases  | 13,837   | 3,908    | 26,579  
|Gas storage                        | 57,587   | 10,800   | -       
|Acquisitions                       | 141,905  | 17,436   | 5,706   
|Profound acquisition (2)           | -        | 113,029  | -       
|Dispositions (3)                   | (91,252) | (26,580) | (24,220)
|Other                              | 707      | 649      | 1,588   
|Total capital expenditures         | 224,149  | 172,705  | 109,165 

(1)

Exploration and development expenditures for 2010 include approximately $4.0 million in exploration costs which have been expensed directly on the Corporations statement of earnings (2009 - $6.4 million) in accordance with the successful efforts method of accounting. Exploration costs including seismic expenditures and dry hole costs are considered by Perpetual to be more closely related to investing activities than operating activities, and therefore they are included with capital expenditures.

(2)

Includes cash and share consideration plus assumption of Profounds outstanding net debt as of the closing date.

(3)

Dispositions include the receipt of $7.1 million in common shares of Trioil Resources Ltd., a junior oil and gas company focused on the exploration and development of Cardium oil plays in southern Alberta, which were received as partial consideration for the sale of Perpetuals Cochrane property completed in the second quarter of 2010. Since this is a non-cash transaction, those proceeds are not included in the Corporations statement of cash flows for the current year.



Exploration and development expenditures excluding land, measured $101.4 million in 2010 as compared to $53.5 million for 2009. West Central District capital spending totaled $59.1 million, directed primarily towards the drilling and completion of 5 Cardium oil wells (3.2 net) and 5 wells (4.5 net) targeting liquids-rich gas in the Wilrich formation and the expansion of a compressor station at Edson to increase processing capacity by 20 MMcf/d plus associated liquids of 40 bbls perMMcf. Eastern district expenditures of $39.4 million were concentrated on low-cost shallow gas recompletions to maintain production levels, the drilling and completion of 9 gas and oil wells (7.5 net) in Birchwavy, facilities optimization projects designed to reduce production costs and evaluation of the Corporations oilsands leases at Panny and Marten Hills. Capital spending of $2.9 million was allocated to Perpetuals New Ventures areas.



Land acquisitions totaled $13.8 million in 2010, a $9.9 million increase from 2009 levels. Acquisitions included several exploratory parcels in the Caroline, Waskahigan and Del Bonita areas of Alberta as well as additional land purchases in the West Central district and minor maintenance acreage purchases in the Eastern district.







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Acquisition spending totaled $141.9 million including the Edson Acquisition and an acquisition of shallow natural gas production in eastern Alberta for $16.6 million. Through the Edson Acquisition, Perpetual obtained approximately 10 MMcfe/d natural gas and liquids production (80 percent natural gas) as well as extensive gathering and processing infrastructure and 13,393 net acres of undeveloped lands prospective for the Wilrich formation in a desirable multi-zone part of the Alberta deep basin (the
"Edson Assets"). Perpetual has identified significant upside in the acquired assets through further intensified development of the Rock Creek basin-centered gas zone, development of the liquids rich Wilrich formation and through other deep basin, gas-saturated zones that are prospective for horizontal development.



As part of the Edson Acquisition, Perpetual negotiated a farm-in arrangement on 37 gross (31 net) sections of undeveloped Cardium rights in the area of which 22 net sections are believed by Perpetual to be prospective for light oil. The farm-in includes a two well horizontal drilling and completion commitment, each earning 50 percent of the vendors net interest in four sections followed by a rolling option to earn the additional lands on the same basis. In 2010 Perpetual drilled 2 Cardium wells (1.2 net) fulfilling its farm-in commitment.



Disposition proceeds increased to $91.3 million, including $7.1 million in shares of TriOil Resources Ltd. in 2010 from $26.6 million in 2009. The current year total includes the disposal of shut-in gas over bitumen assets for $39.8 million, minor oil and gas property dispositions in Birchwavy East and Athabasca, and the sale of producing non-core assets in west central Alberta obtained through the acquisition of Profound Energy Inc. ("Profound") in 2009.



Gas storage capital spending totaled $57.6 million in 2010, as compared to $10.8 million in 2009. Spending for the current year was focused on design, construction, installation and testing of the compression facilities for the winter withdrawal phase of operations, as well as drilling additional wells into the storage reservoir to increase injection and withdrawal capability. The WGSI facility was fully operational for natural gas withdrawal in January 2011.



Drilling



|                 |       |      |       |      |       |     
|---------------- | ----- | ---- | ----- | ---- | ----- | ----
|                 | 2010  | 2009 | 2008 
|Wells drilled    | Gross | Net  | Gross | Net  | Gross | Net 
|Gas              | 48    | 44.3 | 46    | 36.2 | 91    | 75.4
|Oil              | 14    | 11.6 | 2     | 2.0  | -     | -   
|Service          | 1     | 1.0  | -     | -    | -     | -   
|Gas storage      | 6     | 6.0  | 4     | 4.0  | -     | -   
|Dry              | 1     | 1.0  | -     | -    | 2     | 1.6 
|Total            | 70    | 63.9 | 52    | 42.2 | 93    | 77.0
|Success rate (%) | 99    | 98   | 100   | 100  | 98    | 98  



Perpetual drilled 63.9 net wells in 2010 as compared to 42.2 wells in 2009. Drilling activity in 2010 included 22 (20.8 net) wells in the northeast Alberta, 25 (22.5 net) wells in east central Alberta,, 17 (14.6 net) wells in the West Central district, including two oil wells, and 6 wells (6.0 net) as part of the reservoir delineation and development of Perpetuals gas storage facility.



Reserves



Perpetuals complete National Instrument 51-101 ("NI 51-101") reserves disclosure as at December 31, 2010 including underlying assumptions regarding commodity prices, expenses and other factors, and reconciliation of reserves on a net interest basis (working interest less royalties payable) is contained in the Corporations Annual Information Form for the year ended December 31, 2010.



The reserves data set out below (the
"Reserves Data") is based primarily upon an evaluation by McDaniel and Associates Consultants Ltd. ("McDaniel") with an effective date of December 31, 2010 contained in a report of McDaniel dated February 7, 2011 (the
"McDaniel Report"). In addition to the McDaniel Report, Perpetual also engaged GLJ Petroleum Consultants ("GLJ") to prepare a supplemental independent reserve report for its Elmworth Montney property (the
"GLJ Report"). The Reserves Data is equal to the sum of the reserves assigned in the McDaniel Report and the GLJ Report, and summarizes the oil, liquids and natural gas reserves of the Corporation and the net present values of future net revenue for these reserves using McDaniel and GLJ forecast prices and costs. Reserves are presented on a company interest basis, including royalty interests and before royalty burdens. Columns and rows in reserve and net present value tables may not add due to rounding.





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|                                                      |                  |            |               |                  |            |               |                  |            |              
|----------------------------------------------------- | ---------------- | ---------- | ------------- | ---------------- | ---------- | ------------- | ---------------- | ---------- | -------------
|Oil and natural gas reserves as at December 31        |                  |            | 2010          |                  |            | 2009          |                  |            | 2008         
|Proved                                                | Oil & NGL (Mbbl) | Gas (MMcf) | Total
(MMcfe) | Oil & NGL (Mbbl) | Gas (MMcf) | Total (MMcfe) | Oil & NGL (Mbbl) | Gas (MMcf) | Total (MMcfe)
|Developed
producing                                   | 2,360            | 187,223    | 201,380       | 1,786            | 192,033    | 202,757       | 580              | 207,374    | 210,855      
|Developed
non-producing                               | 141              | 20,786     | 21,633        | 81               | 7,808      | 8,293         | 16               | 13,531     | 13,621       
|Undeveloped                                           | 733              | 22,990     | 27,390        | 384              | 31,018     | 33,322        | 20               | 39,018     | 39,138       
|Total proved                                          | 3,234            | 230,999    | 250,402       | 2,251            | 230,859    | 244,372       | 616              | 259,923    | 263,615      
|Probable producing, non-producing and undeveloped     | 2,017            | 198,030    | 210,133       | 1,129            | 174,626    | 181,398       | 341              | 194,749    | 196,793      
|Probable shut-in gas over bitumen (1)                 | -                | 27,196     | 27,196        | -                | 45,806     | 45,806        | -                | 26,648     | 26,648       
|Total probable                                        | 2,017            | 225,226    | 237,329       | 1,129            | 220,432    | 227,204       | 341              | 221,397    | 223,441      
|Total proved & probable                               | 5,252            | 456,224    | 487,731       | 3,380            | 451,291    | 471,576       | 957              | 481,320    | 487,055      
|Total proved & probable per Common Share (Mcfe/Share) |                  |            | 3.29          |                  |            | 3.74          |                  |            | 4.31         



The proved producing reserves comprise 80 percent of the total proved reserves and 41 percent of the total proved and probable reserves, while proved and probable developed producing reserves are 55 percent of the total proved and probable reserves. Total proved reserves account for 51 percent of the total proved and probable reserves. McDaniel and GLJ have estimated the future development costs ("FDC") required to convert non-producing and undeveloped reserves to producing reserves at $279.8 million.



The Corporations total proved & probable natural gas reserves at December 31, 2010 increased one percent from 2009, primarily as a result of the Edson Acquisition, follow up drilling activity at Elmworth and reserve additions related to drilling and completion activities and upward technical revisions in the Eastern district. These additions were partially offset by production during the year, the disposition of shut-in gas over bitumen assets and other non-core asset sales and negative revision related to substantially reduced natural gas price assumptions.



Proved & probable oil and NGL reserves increased by 55 percent over prior year levels due to the Edson Acquisition and increased focus on oil and liquids-rich gas development as part of the Perpetuals 2010 capital spending programs. Perpetual intends to continue to increase liquids reserves as a portion of the Corporations asset portfolio in 2011 with development capital directed preferential to these assets.







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McDaniels price forecast utilized in the evaluation is summarized below.



McDaniel January 1, 2011 Price Forecast

|                       |                                             |                                     |                                  |                            
|---------------------- | ------------------------------------------- | ----------------------------------- | -------------------------------- | ---------------------------
|Year                   | West Texas Intermediate Crude Oil ($US/bbl) | Edmonton Light Crude Oil ($Cdn/bbl) | Natural Gas at AECO
($Cdn/MMBtu) | Foreign Exchange ($US/$Cdn)
|2011                   | 85.00                                       | 84.20                               | 4.25                             | 0.975                      
|2012                   | 87.70                                       | 88.40                               | 4.90                             | 0.975                      
|2013                   | 90.50                                       | 91.80                               | 5.40                             | 0.975                      
|2014                   | 93.40                                       | 94.80                               | 5.90                             | 0.975                      
|2015                   | 96.30                                       | 97.70                               | 6.35                             | 0.975                      
|2016                   | 99.40                                       | 100.90                              | 6.75                             | 0.975                      
|2017                   | 101.40                                      | 102.90                              | 7.10                             | 0.975                      
|2018                   | 103.40                                      | 104.90                              | 7.40                             | 0.975                      
|2019                   | 105.40                                      | 107.00                              | 7.60                             | 0.975                      
|2020                   | 107.60                                      | 109.20                              | 7.75                             | 0.975                      
|2021                   | 109.70                                      | 111.30                              | 7.85                             | 0.975                      
|2022                   | 111.90                                      | 113.60                              | 8.05                             | 0.975                      
|2023                   | 114.10                                      | 115.80                              | 8.20                             | 0.975                      
|2024                   | 116.40                                      | 118.10                              | 8.40                             | 0.975                      
|Escalate thereafter at | 2%                                          | 2%                                  | 2%                               | 0.975                      



The GLJ price forecasts utilized in the evaluation of the Elmworth Montney assets are summarized below.



GLJ January 1, 2011 Price Forecast

|                       |                                             |                                     |                                  |                            
|---------------------- | ------------------------------------------- | ----------------------------------- | -------------------------------- | ---------------------------
|Year                   | West Texas Intermediate Crude Oil ($US/bbl) | Edmonton Light Crude Oil ($Cdn/bbl) | Natural Gas at AECO
($Cdn/MMBtu) | Foreign Exchange ($US/$Cdn)
|2011                   | 88.00                                       | 86.22                               | 4.16                             | 0.98                       
|2012                   | 89.00                                       | 89.29                               | 4.74                             | 0.98                       
|2013                   | 90.00                                       | 90.92                               | 5.31                             | 0.98                       
|2014                   | 92.00                                       | 92.96                               | 5.77                             | 0.98                       
|2015                   | 95.17                                       | 96.19                               | 6.22                             | 0.98                       
|2016                   | 97.55                                       | 98.62                               | 6.53                             | 0.98                       
|2017                   | 100.26                                      | 101.39                              | 6.76                             | 0.98                       
|2018                   | 102.74                                      | 103.92                              | 6.90                             | 0.98                       
|2019                   | 105.45                                      | 106.68                              | 7.06                             | 0.98                       
|2020                   | 107.56                                      | 108.84                              | 7.21                             | 0.98                       
|Escalate thereafter at | 2%                                          | 2%                                  | 2%                               | 0.98                       



Perpetuals proved and probable reserves to production ratio at December 31, 2010, also referred to as reserve life index ("RLI") was 8.7 years while the proved RLI was 4.9 years, based on 2011 production estimates in the McDaniel Report and GLJ Report.







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The net present values of future net revenues ("NPV") for Perpetuals reserves, before taxes using McDaniel and GLJ forecast prices and costs at zero, five and ten percent discount rates are presented in the table below.



|                                                   |         |         |       |         |         |         |         |         |        
|-------------------------------------------------- | ------- | ------- | ----- | ------- | ------- | ------- | ------- | ------- | -------
|NPV of reserves at
December 31                     |         |         | 2010  |         |         | 2009    |         |         | 2008   
|($ millions)                                       | 0%      | 5%      | 10%   | 0%      | 5%      | 10%     | 0%      | 5%      | 10%    
|Proved                                             |         |         |       |         |         |         |         |         |        
|Developed producing                                | 674.3   | 537.7   | 453.4 | 784.3   | 654.6   | 569.5   | 1,008.7 | 845.7   | 739.2  
|Developed non-producing (1)                        | 99.7    | 44.4    | 26.4  | 17.6    | 14.0    | 11.9    | 9.8     | 14.2    | 14.8   
|Gas over bitumen
royalty adjustments               | 110.6   | 92.3    | 78.8  | 129.9   | 109.9   | 94.9    | 79.6    | 70.5    | 63.2   
|Undeveloped                                        | 57.2    | 36.0    | 23.2  | 77.2    | 56.0    | 41.1    | 112.5   | 81.0    | 58.8   
|Total proved                                       | 941.8   | 710.4   | 581.8 | 1,009.0 | 834.5   | 717.4   | 1,210.6 | 1,011.4 | 876.0  
|Probable                                           |         |         |       |         |         |         |         |         |        
|Developed and
undeveloped                          | 652.6   | 417.0   | 293.4 | 727.2   | 497.4   | 359.9   | 797.4   | 552.5   | 405.9  
|Shut-in gas over
bitumen reserves (2)              | 105.9   | 73.6    | 53.0  | 100.3   | 55.3    | 32.3    | 123.1   | 78.3    | 51.7   
|Total probable                                     | 758.5   | 490.6   | 346.4 | 827.5   | 552.7   | 392.2   | 920.5   | 630.8   | 457.6  
|Total proved & probable                            | 1,700.3 | 1,201.0 | 928.2 | 1,836.5 | 1,387.2 | 1,109.6 | 2,131.1 | 1,642.2 | 1,333.6
|Common Shares outstanding (millions)               | 148.3   | 148.3   | 148.3 | 126.2   | 126.2   | 126.2   | 113.0   | 113.0   | 113.0  
|Total proved & probable per Common Share ($/Share) | 11.47   | 8.10    | 6.26  | 14.55   | 10.99   | 8.79    | 18.86   | 14.53   | 11.80  

(1)

The McDaniel and GLJ Reports incorporate an estimate for abandonment costs for producing and non-producing wells.  This may result in a net liability to Perpetual for wells in this category.

(2)

The McDaniel Report assumes that the shut-in gas over bitumen reserves are probable but the future abandonment and reclamation liability associated with the wells is proved, that the reserves return to production after ten years of shut-in and that such production is subject to an incremental ten percent gross overriding royalty payable to the Crown.



At a 10 percent discount factor, the proved producing reserves comprise 57 percent of the total proved and probable value while proved and probable developed producing reserves represent 71 percent of the total proved and probable value. Total proved reserves account for 63 percent of the proved and probable value.



After-tax reserve amounts from the McDaniel and GLJ Reports using forecast prices and costs are shown below.



|                                                     |              |                           |         |        
|---------------------------------------------------- | ------------ | ------------------------- | ------- | -------
|After-tax net present values as at
December 31, 2010 | Total proved | Total proved and probable
|($ millions, discounted at 0% and 10%)               | 0%           | 10%                       | 0%      | 10%    
|Net present value, before taxes                      | 941.8        | 581.8                     | 1,700.3 | 928.2  
|Income taxes                                         | (43.2)       | (17.9)                    | (231.9) | (109.6)
|Net present value, after taxes                       | 898.6        | 563.9                     | 1,468.4 | 818.6  



The McDaniel and GLJ Reports assume the utilization of Perpetuals current existing tax pools plus additions from future development costs, beginning in 2011 with taxation of after-tax cash flow at corporate income tax rates beginning in 2013.







Page 16



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The following table sets forth a reconciliation of the changes in reserves for the year ended December 31, 2010 from the opening balance on December 31, 2009 derived from the McDaniel and GLJ Reports at those dates, using McDaniel and GLJ forecast prices.

|                                  |          |          |                  
|--------------------------------- | -------- | -------- | -----------------
|Reserves reconciliation (MMcfe)   | Proved   | Probable | Proved & Probable
|December 31, 2009                 | 244,372  | 227,204  | 471,576          
|Discoveries and extensions        | 42,934   | 33,849   | 76,783           
|Technical revisions               | 31,544   | (4,332)  | 27,212           
|Acquisitions, net of dispositions | 11,243   | (21,096) | (9,853)          
|Production                        | (55,704) | 0        | (55,704)         
|Economic factors                  | (23,987) | 1,704    | (22,283)         
|December 31, 2010                 | 250,402  | 237,329  | 487,731          



Finding and development ("F&D") costs



Under National Instrument 51-101, the methodology to be used to calculate F&D and finding, development and acquisition ("FD&A") costs includes incorporating changes in FDC required to bring the proved undeveloped and probable reserves to production. For continuity, Perpetual has presented herein FD&A costs calculated both excluding and including FDC. Changes in forecast FDC occur annually as a result of development activities, acquisitions and disposition activities and capital cost estimates that reflect the independent evaluators best estimate of what it will cost to bring the proved undeveloped and probable reserves on production.



The following table summarizes Perpetuals F&D cost as well as finding, development and acquisition costs, before and after the inclusion of changes in FDC. Finding and development costs, including changes in FDC were $1.69 per Mcfe ($10.14 per BOE) on a proved and probable basis in 2010.



The same metrics are presented below with the impact of the sale of probable shut-in gas over bitumen reserves removed, as the dispositions are not comparable to other acquisitions and dispositions since Perpetual retained the effective funds flow related to the Government of Albertas gas over bitumen financial solution through royalty reductions associated with the shut-in properties. Including changes in FDC, FD&A costs were $2.16 per Mcfe ($12.96 per BOE) on a proved and probable basis.



Perpetual has also summarized in the table below these same metrics with the effect of the price-related revisions removed. Perpetual believes that the majority of these reserves will return to the books with a recovery in natural gas prices as the technical merits for booking the reserves have not changed, only the economic circumstances. Excluding the effects of negative reserve revisions related to substantially lower forward gas prices, including changes in FDC, Perpetuals F&D costs were $1.33 per Mcfe ($7.98 per BOE) for proved and probable reserves and FD&A costs were $1.78 per Mcfe ($10.68 per BOE) in 2010 on a proved and probable basis.





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2010 FD&A costs  company interest reserves

|                                                     |        |                                     |                                                         |                   |                                                     |                                                                         |  |  | 
|---------------------------------------------------- | ------ | ----------------------------------- | ------------------------------------------------------- | ----------------- | --------------------------------------------------- | ----------------------------------------------------------------------- |  |  | 
|($millions, except as noted)                         | Proved | Proved excluding GOB disposition(2) | Proved Excluding GOB disposition & price revisions(2,4) | Proved & probable | Proved and probable excluding GOB disposition
(2,3) | Proved and probable excluding GOB disposition & price revisions
(2,3,5)
|F&D costs, excluding FDC                             |        |                                     |                                                         |                   |                                                     |                                                                        
|Exploration and development capital expenditures(1)  | 115.2  | 115.2                               | 115.2                                                   | 115.2             | 115.2                                               | 115.2                                                                  
|Reserve additions including revisions  Bcfe         | 50.5   | 50.5                                | 74.5                                                    | 81.7              | 81.7                                                | 104.0                                                                  
|F&D costs  $/Mcfe(6)                                | 2.28   | 2.28                                | 1.55                                                    | 1.41              | 1.41                                                | 1.11                                                                   
|                                                     |        |                                     |                                                         |                   |                                                     |                                                                        
|F&D costs, including FDC                             |        |                                     |                                                         |                   |                                                     |                                                                        
|Exploration and development capital expenditures     | 115.2  | 115.2                               | 115.2                                                   | 115.2             | 115.2                                               | 115.2                                                                  
|Total change in FDC                                  | (0.6)  | (0.6)                               | (0.6)                                                   | 22.8              | 22.8                                                | 22.8                                                                   
|Total F&D capital including change in FDC            | 114.6  | 114.6                               | 114.6                                                   | 138.0             | 138.0                                               | 138.0                                                                  
|Reserve additions including revisions  Bcfe         | 50.5   | 50.5                                | 74.5                                                    | 81.7              | 81.7                                                | 104.0                                                                  
|F&D costs $/Mcfe(6)                                 | 2.27   | 2.27                                | 1.54                                                    | 1.69              | 1.69                                                | 1.33                                                                   
|                                                     |        |                                     |                                                         |                   |                                                     |                                                                        
|FD&A costs, excluding FDC                            |        |                                     |                                                         |                   |                                                     |                                                                        
|Exploration and development capital expenditures     | 115.2  | 115.2                               | 115.2                                                   | 115.2             | 115.2                                               | 115.2                                                                  
|Net acquisitions                                     | 50.7   | 90.5                                | 90.5                                                    | 50.7              | 90.5                                                | 90.5                                                                   
|FD&A capital expenditures including net acquisitions | 165.9  | 205.7                               | 205.7                                                   | 165.9             | 205.7                                               | 205.7                                                                  
|Reserve additions including net acquisitions  Bcfe  | 61.7   | 61.7                                | 85.7                                                    | 71.9              | 106.0                                               | 128.3                                                                  
|FD&A costs  $/Mcfe                                  | 2.69   | 3.33                                | 2.40                                                    | 2.31              | 1.94                                                | 1.60                                                                   
|                                                     |        |                                     |                                                         |                   |                                                     |                                                                        
|FD&A costs, including FDC                            |        |                                     |                                                         |                   |                                                     |                                                                        
|FD&A capital expenditures including net acquisitions | 165.9  | 205.7                               | 205.7                                                   | 165.9             | 205.7                                               | 205.7                                                                  
|Total change in FDC                                  | (0.6)  | (0.6)                               | (0.6)                                                   | 22.8              | 22.8                                                | 22.8                                                                   
|Total FD&A capital including change in FDC           | 165.3  | 205.1                               | 205.1                                                   | 188.7             | 228.5                                               | 228.5                                                                  
|Reserve additions including net acquisitions  Bcfe  | 61.7   | 61.7                                | 85.7                                                    | 71.9              | 106.0                                               | 128.3                                                                  
|FD&A costs including FDC   $/Mcfe                   | 2.68   | 3.32                                | 2.39                                                    | 2.62              | 2.16                                                | 1.78                                                                   

(1)

$57.6 million of capital expenditures associated with the Warwick Gas Storage project have been excluded, includes $13.8 million of undeveloped land purchases.

(2)

Disposition proceeds totaling $39.8 million associated with the gas over bitumen asset dispositions have been added back into the net acquisition capital.

(3)

34.2 Bcf of probable reserves associated with the gas over bitumen asset dispositions have been added back into the net acquired reserves.

(4)

24.0 Bcf of proved reserves associated with price related revisions have been added back into the total reserve additions and revisions.

(5)

22.3 Bcf of proved and probable reserves associated with price related revisions have been added back into the total reserve additions and revisions.



Land



|               |           |                              |           |                              |           |                             
|-------------- | --------- | ---------------------------- | --------- | ---------------------------- | --------- | ----------------------------
|               | 2010      | 2009                         | 2008     
|Land inventory | Net acres | Average working interest (%) | Net acres | Average working interest (%) | Net acres | Average working interest (%)
|Developed      | 1,516,366 | 67.49                        | 1,666,352 | 68.0                         | 1,694,944 | 65.9                        
|Undeveloped    | 1,905,009 | 84.09                        | 2,092,637 | 83.1                         | 2,106,021 | 81.1                        
|Total          | 3,421,375 | 75.82                        | 3,758,989 | 75.6                         | 3,800,965 | 73.6                        



Perpetuals undeveloped net acreage position decreased nine percent from 2009 levels due to lease expiries and disposed acreage, partially offset by the Edson acquisition and land purchases in west central Alberta and new ventures areas.  Perpetual has the most extensive inventory of undeveloped land in the intermediate oil and gas sector relative to its production and reserves base.



The Corporations undeveloped acreage in the Northeast core area includes approximately 239,000 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.





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Further, the Corporation now has in inventory a total of 336,000 net acres of undeveloped oil sands leases.



Perpetuals third party estimate of the fair market value of its undeveloped acreage by region for purposes of the above net asset value calculation is based on recent Crown land sale activity adjusted for tenure and other considerations and is as follows.



Fair market value of undeveloped land

|             |           |                 |        | 
|------------ | --------- | --------------- | ------ | 
|Area         | Acres     | Total Value ($) | $/Acre
|North        | 1,001,029 | 41,042,433      | 41.00 
|South        | 405,289   | 59,761,578      | 147.45
|West Central | 140,082   | 66,445,075      | 474.33
|New Ventures | 25,350    | 8,607,925       | 339.56
|Heavy Oil    | 333,259   | 27,809,494      | 83.45 
|Totals       | 1,905,009 | 203,666,505     | 106.91



The 43 percent increase in estimated fair value to $204 million at December 31, 2010 from $143 million at December 31, 2009 is primarily related to the prospective lands acquired in west central Alberta through the Edson acquisition, and higher values attributed to the Corporations heavy oil leases.



Net Asset Value



The following net asset value ("NAV") table shows what is normally referred to as a "produce-out" NAV calculation under which the Corporation's reserves would be produced at forecast future prices and costs. The value is a snapshot in time and is based on various assumptions including commodity prices and foreign exchange rates that vary over time. It should not be assumed that the NAV represents the fair market value of Perpetual common shares. Actual results will differ materially from the assumptions mandated by NI 51-101, as these do not reflect the full potential value of the Corporations extensive prospect inventory.



As of December 31, 2010, no reserves or contingent resources are yet assigned to any of Perpetuals heavy oil projects in northeast Alberta. The incremental value of Perpetuals extensive prospect inventory for its game-changing opportunities in the Montney at Elmworth, Cardium light oil at Carrot Creek, Wilrich liquids-rich gas at Edson, the Colorado shallow shale gas in east central Alberta and the bitumen projects in northeast Alberta, above the nominal amount which is currently recognized by McDaniel and GLJ, is captured only through the assessment of the fair market value of undeveloped land based on current land sale valuation parameters.



The value of the Corporations Warwick Gas Storage asset has been recorded at cost in the net asset value calculation below. Construction of the Warwick Gas Storage facility was completed in the fourth quarter of 2010 and withdrawal has now commenced on the test cycle which will be complete at the end of March 2011. Information gathered during the test cycle will define the developed working gas capacity of the storage reservoir at that time. This in turn will lead to a more comprehensive valuation of the asset.







Page 19



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|                                                                    |              |       |       |                  
|------------------------------------------------------------------- | ------------ | ----- | ----- | -----------------
|Pre-tax Net Asset Value at December 31, 2010(1)                     |              |       |      
|($millions except as noted)                                         | Undiscounted | 5%    | 8%    | Discounted at 10%
|Total proved and probable reserves (2)                              | 1,700        | 1,201 | 1,021 | 928              
|Fair market value of undeveloped land (3)                           | 204          | 204   | 204   | 204              
|Market value of TriOil Resources Ltd. shares                        | 6            | 6     | 6     | 6                
|Warwick gas storage (4)                                             | 68           | 68    | 68    | 68               
|Net bank debt (5)                                                   | (211)        | (211) | (211) | (211)            
|Convertible debentures                                              | (235)        | (235) | (235) | (235)            
|Estimate of additional future abandonment and reclamation costs (6) | (110)        | (63)  | (46)  | (38)             
|Mark to McDaniels cost of WGSI forward sale obligation (7)         | (40)         | (34)  | (31)  | (29)             
|Net Asset Value                                                     | 1,382        | 936   | 775   | 693              
|Common Shares Outstanding (million) - basic                         | 148.3        | 148.3 | 148.3 | 148.3            
|Net Asset Value per Share ($/Common Share)                          | 9.32         | 6.31  | 5.23  | 4.67             



(1)

Financial information is per Perpetuals 2010 unaudited consolidated financial statements.

(2)

Reserve values per McDaniel Report and GLJ Report as at December 31, 2010.

(3)

Third party estimate.

(4)

Book value recorded at cost as at December 31, 2010.

(5)

Includes $10 million held in escrow at year-end relating to the WGSI Facility funding arrangement, which was not included in net debt in the Corporations balance sheet at December 31, 2010.

(6)

Amounts are net of salvage value and in addition to amounts in the McDaniel Report and GLJ Report for future well abandonment costs related to developed reserves. See
"Abandonment and reclamation costs".

(7)

Value of Perpetuals forward sale obligation related to the gas storage funding arrangement at year end 2010 assuming settlement against the McDaniel price forecast.



In the absence of adding reserves to the Corporation, the NAV per share will decline as the reserves are produced out. The funds flow generated by the production relates directly to the cash dividends paid to Perpetual shareholders. The above evaluation includes future capital expenditure expectations required to bring undeveloped reserves recognized by McDaniel and GLJ that meet the criteria for booking under NI 51-101 on production. In order to independently assess the "going concern" value of the Corporation, a more detailed independent assessment would be required of the upside potential of specific properties and the ability of the Perpetual team to continue to make value-adding capital expenditures, some of which may require external financing.



Perpetuals three year history of net asset value and net asset value per Common Share, discounted at eight percent and including dividends paid to Shareholders, is as follows.



|                                                                                              |      |      |      
|--------------------------------------------------------------------------------------------- | ---- | ---- | -----
|Pre-tax net asset value at December 31, discounted at 8%
($ millions except per unit amounts) | 2010 | 2009 | 2008 
|Net asset value                                                                               | 775  | 830  | 1,010
|Net asset value per Common Share ($/Share)                                                    | 5.23 | 6.59 | 8.94 
|Dividends per Common Share ($/Share)                                                          | 0.56 | 0.64 | 1.20 
|Net asset value per Common Share including dividends paid ($/Share)                           | 5.79 | 7.23 | 10.14



The decline in net asset value is directly related to declines in natural gas prices. The AECO Monthly Index price was $8.13, $4.14 and $4.13 per Mcf at AECO in 2008, 2009 and 2010 respectively.











Page 20



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MARKETING



Natural gas prices



|                                                           |      |      |     
|---------------------------------------------------------- | ---- | ---- | ----
|Natural gas price ($/Mcf, except percentages)              | 2010 | 2009 | 2008
|Reference prices                                           |      |      |     
|AECO Monthly Index                                         | 4.13 | 4.14 | 8.13
|AECO Daily Index                                           | 4.00 | 3.98 | 8.15
|Alberta Gas Reference Price (1)                            | 3.77 | 3.85 | 7.88
|                                                           |      |      |     
|Average Perpetual prices                                   |      |      |     
|Before financial hedging (2)                               | 4.17 | 4.12 | 8.15
|Percent of AECO Monthly Index                              | 101  | 100  | 100 
|                                                           |      |      |     
|Including financial hedging ("Realized" natural gas price) | 7.10 | 7.09 | 8.18
|Percent of AECO Monthly Index                              | 172  | 171  | 101 

(1)

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

(2)

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



U.S. natural gas prices are typically referenced to NYMEX at the Henry Hub in Louisiana, while western Canada natural gas prices are referenced to the AECO Hub in Alberta.  AECO Monthly Index prices were relatively consistent from 2009 to 2010, averaging $4.14 per Mcf and $4.13 per Mcf respectively. North American natural gas prices have been under downward pressure since 2008 as a result of increased supply from shale gas plays coupled with reduced industrial demand due to the economic recession. Perpetuals natural gas price before financial hedging increased one percent to $4.17 per Mcf in 2010 from $4.12 per Mcf in 2009 due to the inclusion of a physical fixed-price contract for 10,000 GJ/d at a price of $7.75 per GJ in the Corporations natural gas revenues for November to December 2010. Physical fixed-price forward contracts are included in gas revenue, while monthly settlements from financial forward contracts are included in realized gains on financial instruments.



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, and is used to calculate Alberta Gas Crown Royalties.  The Alberta Gas Reference Price decreased two percent from $3.85 per Mcf in 2009 to $3.77 per Mcf in 2010.



Perpetuals average realized gas price was $7.10 per Mcf in 2010 compared to $7.09 per Mcf in 2009. Realized gas prices are well above the AECO Monthly Index for 2010 and 2009 due to realized hedging gains of $155.0 million and $166.3 million, respectively. The Corporations active gas price hedging program has been instrumental in maintaining cash flows for the last two years despite the decrease in AECO prices.



Oil and NGL prices



|                                                    |       |       |      
|--------------------------------------------------- | ----- | ----- | -----
|Oil and NGL prices ($/bbl)                          | 2010  | 2009  | 2008 
|West Texas Intermediate ("WTI") light oil (US$/bbl) | 79.53 | 61.80 | 99.66
|Average Perpetual realized price ($/bbl)            | 68.29 | 61.91 | 82.82



The Corporations average realized price for oil and NGLs increased to $68.29 per bbl in 2010 from $61.91 per bbl in 2009, primarily due to higher WTI oil prices, partially offset by an increasing proportion of NGL production included in Perpetuals liquids production mix. The 2009 realized price for oil and NGLs was higher than the average WTI price as the majority of the Corporations 2009 liquids production occurred in the second half of the year subsequent to the Profound acquisition, when WTI prices were highest.



Hedging and risk management



Perpetuals gas price risk management strategy is focused on using financial instruments to mitigate the effect of commodity price volatility on funds flow and dividends, to lock in attractive economics on capital programs and acquisitions and to take advantage of perceived anomalies in natural gas markets. The Corporation uses both financial arrangements and physical forward sales to economically hedge up to a maximum of 60 percent of the trailing quarters production including gas over bitumen deemed volumes in accordance with the limits under the Corporations credit facility and Hedging and Risk Management Policy. Perpetual will also enter into foreign exchange swaps and physical or financial swaps related to the differential between natural gas prices at the AECO and NYMEX trading hubs in order to mitigate the effects of fluctuations in foreign exchange rates and basis differentials on the Corporations realized gas price. The term
"financial instruments"
includes all financial and physical risk management contracts. Although Perpetual considers the majority of these risk management contracts to be effective economic hedges against potential gas price volatility, the Corporation does not follow hedge accounting for its financial instruments.





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Perpetuals hedging activities are conducted by an internal Risk Management Committee under guidelines approved by the Corporations Board of Directors. Perpetuals hedging strategy, though designed primarily to protect funds flow and dividends, capital programs and debt management, is opportunistic in nature. Depending on managements perceived position in the commodity price cycle the Corporation may elect to reduce or increase its hedging position within the approved guidelines. The Corporation mitigates credit risk by entering into risk management contracts with financially sound, credit-worthy counterparties.



For a complete list of Perpetuals outstanding financial instruments as at December 31, 2010, please see note 12 to the annual consolidated financial statements as at and for the year ended December 31, 2010.  The Corporation had no outstanding financial or physical fixed-price natural gas contracts as at March 7, 2011.



As part of Perpetuals risk management strategy, the Corporation has also sold forward financial call options to counterparties to purchase natural gas from Perpetual at strike prices in excess of current forward prices. Option premiums of $7.6 million have been received and included in funds flows in respect of these transactions, of which $5.7 million was recorded in 2009 and $1.9 million was recorded in 2010. Call option contracts outstanding as of March 7, 2011 are as follows:



|                 |                        |                              |                        |                          |                     
|---------------- | ---------------------- | ---------------------------- | ---------------------- | ------------------------ | --------------------
|Type of
Contract | Volumes at AECO (GJ/d) | % of 2010 Budgeted Volume(2) | Strike Price ($/GJ)(1) | Futures Market(3) ($/GJ) | Term                
|Sold Call        | 30,000                 | 16                           | 6.00                   | 3.22                     | April  October 2011



(1)

Weighted average prices are calculated by netting the volumes of the lowest-priced financial and physical sold/bought contracts together and measuring the net volume at the weighted average "sold" price for the remaining financial and physical contracts.

(2)

Calculated using 185,000 GJ/d and includes actual and gas over bitumen deemed projected production volumesand voluntary production shut-ins.

(3)

Futures market reflects AECO/NYMEX forward market prices as at March 7, 2011.



FINANCIAL RESULTS



Revenue



|                                                     |         |         |        
|---------------------------------------------------- | ------- | ------- | -------
|Revenue ($ thousands)                                | 2010    | 2009    | 2008   
|Natural gas revenue (1)                              | 221,099 | 229,943 | 528,355
|Oil and NGL revenue                                  | 31,036  | 16,300  | 15,221 
|Gas storage revenue                                  | 8,082   | -       | -      
|Realized gains (losses) on financial instruments (2) | 155,025 | 166,340 | (1,283)
|Call option premiums received (3)                    | 1,851   | 5,740   | 3,408  
|Total oil and natural gas revenue                    | 417,093 | 418,323 | 545,701

(1)

Includes revenues related to physical forward sales contracts which settled during the period.

(2)

Realized gains (losses) on financial instruments include settled financial forward contracts and options.

(3)

Call option premiums received are included in the calculation of the Corporations realized gas price and funds flows.



Natural gas revenue decreased to $221.1 million in 2010 from $229.9 million in 2009 due to lower production volumes, while oil and NGL revenues increased by $14.7 million as a result of higher production and pricing compared to prior year. Realized gains on financial instruments totaled $155.0 million in 2010 as compared to $166.3 million in 2009.



The Corporation also recorded unrealized losses on financial instruments of $63.2 million in 2010, reflecting the change in the fair value of financial and physical forward natural gas and foreign exchange contracts during the year. As the majority of Perpetuals outstanding financial instrument contracts at January 1, 2010 settled during the year and others were terminated in advance of their maturity dates, the Corporations financial instrument asset at December 31, 2010 decreased, leading to the unrealized loss.



Gas storage revenue is derived from injecting, storing and withdrawing natural gas from the WGSI Facility on behalf of third parties, and is recorded in accordance with the terms of the storage contracts. Storage revenue of $8.1 million for 2010 is comprised primarily of gas injection revenue received from May 1, 2010 to October 31, 2010 for the first test cycle of the WGSI Facility. Gas withdrawals were not initiated until 2011. Including operating costs, the WGSI facility generated operating cash flows of $6.6 million in 2010.







Page 22



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Funds flow



|                                      |            |          |            |          |            |          | 
|------------------------------------- | ---------- | -------- | ---------- | -------- | ---------- | -------- | 
|                                      | 2010       | 2009     | 2008      
|Funds flow reconciliation             | $ millions | ($/Mcfe) | $ millions | ($/Mcfe) | $ millions | ($/Mcfe)
|Production volume (Bcfe)              | 55.7       | 57.5     | 66.7      
|Revenue (1)                           | 417.1      | 7.49     | 418.3      | 7.27     | 545.7      | 8.18    
|Royalties                             | (22.1)     | (0.40)   | (17.4)     | (0.30)   | (92.3)     | (1.38)  
|Operating costs                       | (91.2)     | (1.64)   | (105.1)    | (1.83)   | (120.6)    | (1.81)  
|Transportation costs                  | (11.9)     | (0.21)   | (11.7)     | (0.20)   | (14.1)     | (0.21)  
|Operating netback from production     | 291.9      | 5.24     | 284.1      | 4.94     | 318.7      | 4.78    
|Gas over bitumen royalty adjustments  | 12.3       | 0.22     | 10.4       | 0.18     | 20.8       | 0.31    
|Lease rentals                         | (4.4)      | (0.08)   | (4.2)      | (0.07)   | (3.5)      | (0.05)  
|General and administrative (2)        | (34.4)     | (0.62)   | (32.1)     | (0.56)   | (31.9)     | (0.48)  
|Interest and other (2)                | (11.9)     | (0.21)   | (11.9)     | (0.21)   | (13.7)     | (0.20)  
|Interest on convertible debentures(2) | (16.3)     | (0.29)   | (15.0)     | (0.26)   | (15.0)     | (0.23)  
|Funds flow (2) (3)                    | 237.2      | 4.26     | 231.3      | 4.02     | 275.4      | 4.13    

(1)

Revenue includes realized gains and losses on financial instruments, call option premiums received and gas storage revenue.

(2)

Excludes non-cash items.

(3)

This is a non-GAAP measure; see
"Other non-GAAP measures" in this MD&A.



Royalties



Perpetual pays Crown, freehold and gross 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, which are based on processing fees and allowable capital costs incurred at a property and are in accordance with Crown royalty regulations. Crown royalty rates tend to decrease with decreases in the Alberta Gas Reference Price, and rise as the reference price increases. Oil royalties are taken in kind directly from the wellhead by the Alberta Crown, and an amount is included in royalty expense based on the oil price received by the Corporation.



The effective royalty rate applicable to the Corporation in 2010 was 5.3 percent (2009  4.1 percent) or $0.40 per Mcfe (2009 - $0.30 per Mcfe).  Royalty rates in both 2010 and 2009 were below the Corporations historical average royalty rates due to the inclusion of realized gains on financial instruments of $155.0 million and $166.3 million, respectively in revenue. Perpetuals 2010 royalty rate, measured as a percentage of oil and gas revenues before financial instruments, gas storage revenue or call option premiums, increased to 8.8 percent from 7.1 percent in 2009 due to  higher royalty rates on production from the West Central district assets, which have higher productivity per well than Perpetuals legacy assets in the Eastern district, as well as higher royalty rates on oil wells due to higher prices relative to natural gas.







Page 23



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In 2009 the Government of Alberta announced a new incentive program designed to increase industry activity despite low oil and natural gas prices and tightened credit markets caused by the global financial crisis. The program was effective April 1, 2009, and offered two separate incentives:



·

A $200 per metre drilling royalty credit for new conventional oil and natural gas wells drilled between April 1, 2009 and March 31, 2011, available to companies on a sliding scale based on company production levels from 2008.



·

A maximum five percent royalty rate for the first year of production from new oil or gas wells, subject to a maximum annual production of 50,000 bbl or 500,000 Mcf. The maximum rate applies to all wells which begin production after March 31, 2009 and before April 1, 2011.



Perpetual realized $3.9 million in drilling royalty credits through 2010 drilling activity (2009 - $1.6 million), which have been recorded as a reduction to property, plant and equipment on the Corporations balance sheet, and a reduction to exploration and development capital expenditures on the statement of cash flows.



Operating costs



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 Perpetuals facilities is netted against operating costs.





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Operating costs decreased 13 percent to $91.2 million ($1.64 per Mcfe) in 2010 as compared to $105.1 million ($1.83 per Mcfe) in 2009, primarily due to lower repair and maintenance costs and higher processing income from charges to third parties, which is recorded as a credit against operating costs. In 2009 Perpetual implemented cost reduction initiatives at all operated fields to enhance competitiveness, profitability and efficiency. Approximately $1.5 million of 2010 operating costs relate to the operation of the WGSI Facility. Unit operating costs excluding WGSI expenses were $1.61 per Mcfe for 2010.



Transportation costs



Costs to transport gas from the plant gate to the commercial market sales point are not reflected as an operating cost but rather are separately recorded as transportation costs for the product. Albertas gas transportation system operates on a postage stamp basis. Total transportation costs increased to $11.9 million in 2010 from $11.7 million in 2009, despite a decrease in production levels from year to year, as a result of fewer point to point contracts with end users of natural gas in proximity to Perpetuals northeast Alberta gas production in the current period. On a unit-of-production basis, transportation costs increased to $0.21 per Mcfe compared to $0.20 per Mcfe in 2009.



Operating netbacks



Lower operating costs and a three percent increase in the Corporations realized natural gas price were the primary drivers in increasing Perpetuals operating netback by $7.8 million to $291.9 million for the year ended December 31, 2010 from $284.1 million for the prior year.



Operating netback reconciliation ($ millions)Realized price increase12.4Production decrease(13.5)Royalty expense increase(4.8)Operating cost decrease13.9Transportation cost increase(0.2)Increase in operating netback7.8




Gas over bitumen royalty adjustments



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



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



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

|                                                        |        |        |       
|------------------------------------------------------- | ------ | ------ | ------
|                                                        |        |        |       
|Gas over bitumen royalty adjustment netback ($ per Mcf) | 2010   | 2009   | 2008  
|Average deemed volume (MMcf/d)                          | 24.8   | 19.9   | 19.2  
|Gas price                                               | 3.77   | 3.85   | 7.88  
|Royalties                                               | (0.75) | (0.77) | (1.58)
|Operating costs                                         | (0.40) | (0.40) | (0.40)
|50% reduction factor                                    | (1.31) | (1.34) | (2.95)
|Gas over bitumen royalty adjustment netback             | 1.31   | 1.34   | 2.95  





The Corporations net deemed production volume for purposes of the royalty adjustment was 24.8 MMcf/d for 2010. Deemed production represents all Perpetual natural gas production shut-in or denied production pursuant to a decision report, corresponding order or general bulletin of the AEUB or ERCB, 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 ten percent per year on the anniversary date of the shut-in order. Deemed production increased by 4.9 MMcf/d from the 19.9 MMcf/d recorded for 2009 as a result of the shut-in of the Corporations Legend property in the Northeast core area effective November 1, 2009, partially offset by the annual ten percent reduction in deemed
production volumes discussed previously.





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



Perpetual has disposed of certain shut-in gas wells in the gas over bitumen area. As part of the disposition agreements, the Corporation continues to receive the gas over bitumen royalty adjustments related to the sold wells, although the ownership of the natural gas reserves is transferred to the buyer. As such, any overriding royalty payable to the Crown when gas production recommences from the affected wells is no longer Perpetuals responsibility. As a result of these dispositions, the gas over bitumen royalty adjustments received by the Corporation for the affected wells are now considered revenue since they will not be repaid to the Crown. For the year ended December 31, 2010 a total of $13.8 million in royalty adjustments were reclassified from the gas over bitumen liability to revenues in respect of these dispositions. In addition, a portion of the sold area is subject to an interim ERCB hearing is in process to consider a shut-in order for gas production.  Assuming the production will be subject to such an order, the Corporation expects to receive the financial solution for approximately 6 MMcf/d of additional gas over bitumen deemed production in accordance with the royalty regulations at that time. As of December 31, 2010, Perpetual had realized a total of $112.5 million of gas over bitumen royalty adjustments, of which $42.0 million was recorded as revenues and $70.5 million is recorded as a liability on the Corporations balance sheet.



Gas over bitumen royalty adjustments are not paid to Perpetual in cash, but are a deduction from the Corporations monthly natural gas royalty invoices. In periods of exceptionally low gas prices, such as those experienced in the second half of 2009 and 2010, the Corporations net Crown royalty expenses were too low to recover the full amount of the gas over bitumen royalty adjustments, and as such royalty adjustments for past periods will be recovered in future periods. Eventual realization of the royalty adjustments is highly likely as deemed production is reduced by ten percent annually, whereas the Corporation is focused on maintaining production and reserves year over year through capital spending programs, complemented with strategic acquisitions. Perpetual has a total of $8.5 million in royalty adjustments receivable as at December 31, 2010 ($5.1 million as of December 31, 2009), which are netted against the gas over bitumen liability on the Corporations balance sheet. These amounts are included in funds flows. A reconciliation of Perpetuals gas over bitumen liability is as follows.



Gas over bitumen royalty adjustments ($ thousands)Net liability, December 31, 200874,643Royalty adjustments recorded for 20097,662Less: royalty adjustments not yet received(5,138)Net liability, December 31, 200977,167Royalty adjustments recorded for 201010,454Less: revenue adjustments on dispositions for 2010(13,767)Less: royalty adjustments not yet received(3,357)Net liability, December 31, 201070,497




Lease rentals



Lease rentals reflect annual payments made to the Alberta Crown or other land owners in order to maintain the rights to explore previously-acquired undeveloped acreage. These payments
are expensed by the Corporation in accordance with the successful efforts method of accounting for oil and gas assets, whereas they are typically capitalized by companies employing the full cost method of accounting. Lease rentals increased from $4.2 million in 2009 to $4.4 million in 2010. In 2009 Perpetual leased out a portion of its undeveloped fee-simple acreage to third parties; a portion of the proceeds received were credited to lease rentals.



General and administrative expenses



|                               |        |        |        |        |        |       
|------------------------------ | ------ | ------ | ------ | ------ | ------ | ------
|                               | 2010   | 2009   | 2008  
|                               | $000s | $/Mcfe | $000s | $/Mcfe | $000s | $/Mcfe
|Cash general & administrative  | 34,380 | 0.62   | 32,134 | 0.56   | 31,955 | 0.48  
|Stock-based compensation(1)    | 1,870  | 0.03   | 7,481  | 0.13   | 5,671  | 0.09  
|Total general & administrative | 36,250 | 0.65   | 39,615 | 0.69   | 37,626 | 0.57  

(1)

Non-cash item



General and administrative expenses ("G&A") include costs incurred by Perpetual which are not directly associated with the production of oil and natural gas.  The largest components of G&A expenses are office staff compensation costs and information technology costs.  Field employee compensation costs are charged to operating expenses.





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Overhead recoveries resulting from the allocation of administrative costs to producing properties and capital projects are recorded as a reduction of G&A expenses, and are a function of capital and operating expenditures during the year, as well as the Corporations productive well base.



Cash G&A expenses, net of overhead recoveries on operated properties, increased to $34.4 million from $32.1 million in 2009. The increase is largely due to $1.5 million in additional costs related to the conversion from an energy trust to a corporation and the consolidation of Severo. The increase in cash G&A is also partially due to lower overhead recoveries as compared to 2009 due to the decrease in the number of producing wells due to the voluntary and ERCB-ordered shut-ins during the year, partially offset by higher capital spending in the current period. Cash G&A expenses increased on a unit-of-production basis from $0.56 per Mcfe in 2009 to $0.62 per Mcfe in 2010.



Share-based compensation decreased by $5.6 million ($0.10 per Mcfe) in 2010 from 2009 levels. Upon conversion to a corporation on June 30, 2010, Perpetual switched from using fair value accounting for incentive rights to using intrinsic value accounting for stock options. The Corporation also implemented a dividend bonus plan for option holders, which is settled in cash and is also accounted for using the intrinsic value method. The change in methodology and the decrease in the trading price of the Corporations common shares from June 30, 2010 to December 31, 2010 led to lower stock-based compensation expense for the second half of the year. 2009 compensation expense was also affected by a $2.1 million charge recorded for the cancellation of 2.5 million unit incentive rights.



Interest expense



Interest and other expense increased to $12.5 million in 2010 from $11.9 million in 2009 as a result of $0.6 million in non-cash interest expense recorded on the gas storage arrangement, initiated in 2010 to provide partial funding for construction of the WGSI Facility.



Interest on convertible debentures increased to $19.5 million in 2010 from $18.2 million in 2009, due to the amendment of the Corporations 6.25% convertible debentures in late 2009 to extend the maturity date and increase the interest rate, as well as the issuance of new 7.0% convertible debentures in May 2010, partially offset by the repayment of $55.3 million of 6.25% convertible debentures which matured on June 30, 2010.  Included in interest on convertible debentures for 2010 is $3.1 million of non-cash expenses related primarily to the amortization of debt issue costs (2009 - $3.2 million).



Funds flow



Higher realized prices combined with lower operating costs contributing to an increase of six percent in the Corporations funds flow netback from $4.02 per Mcfe in 2009 to $4.26 per Mcfe in 2010. Funds flow increased to $237.2 million ($1.69 per Common Share) for the year ended December 31, 2010 from $231.3 million ($1.96 per Common Share) in the 2009 period. The decrease in funds flow per Common Share in 2010 is due to additional shares issued in respect of the Edson Acquisition and participation in the Corporations Premium Dividend and Dividend Reinvestment Plan (the
"Premium DRIP").



Exploration expense



Exploration costs include lease rentals paid on undeveloped lands, seismic expenditures, amortization expense on undeveloped land and expired leases and are expensed by the Corporation in accordance with the successful efforts method of accounting for oil and gas assets, whereas they are typically capitalized by companies employing the full cost method of accounting. Exploration expenses totaled $19.2 million in 2010 as compared to $21.8 million in 2009, due to lower seismic expenditures in 2010 and lower land amortization expense in northeast Alberta.



Depletion, depreciation and accretion



Perpetuals 2010 depletion, depreciation and accretion ("DD&A") rate increased to $4.01 per Mcfe from $3.44 per Mcfe in 2009. In the fourth quarter of 2009, successful efforts accounting rules changed to require DD&A to be calculated based on
"average price" reserves, which are measured using the average commodity price on the first trading day of each month of the year. Prior to the change, reserves were evaluated using a constant price as of the last trading day of the year. For DD&A purposes, the Corporations 2009 year-end reserves were evaluated using an average natural gas price of $3.79 per Mcf. The low gas price resulted in lower reserve volumes than the forecast price reserves disclosed in the Corporations 2009 annual report, which increased the Corporations DD&A rate for 2010.





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|                                         |         |         |        
|---------------------------------------- | ------- | ------- | -------
|Depletion, depreciation and accretion    |         |         |        
|($ thousands except per Mcfe amounts)    | 2010    | 2009    | 2008   
|Depletion expense                        | 209,181 | 183,952 | 204,638
|Accretion of asset retirement obligation | 14,394  | 13,738  | 13,904 
|Total                                    | 223,575 | 197,690 | 218,542
|Per unit-of-production ($/Mcfe)          | 4.01    | 3.44    | 3.28   



At year-end 2010, property, plant and equipment costs include $111.2 million (2009 - $120.5 million) currently not subject to depletion
and $23.8 million (2009 - $73.4 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. The decrease in gas over bitumen costs is due to the sale of certain gas over bitumen assets in the fourth quarter of 2010.



Asset retirement obligation



Perpetual estimates its total future asset retirement obligation based on net ownership interest in all wells, facilities and pipelines, including estimated costs to abandon the wells, facilities and pipelines and reclaim the sites and the estimated timing of the costs to be incurred in future periods. Pursuant to this evaluation, the estimated undiscounted total value of Perpetuals future asset retirement obligations is $315 million as at December 31, 2010. As at December 31, 2010, the undiscounted net salvage value of the Corporations gas plants, compressors and facilities was estimated at $148 million. The McDaniel and GLJ Reports include an undiscounted amount of $83 million with respect to expected future well abandonment costs related specifically to proved and probable reserves and such amount is included in the values captioned
"Total proved and probable reserves" in the "NPV of reserves" table in this MD&A. The following table presents the estimated future asset retirement obligations and estimated net salvage values at various discount rates.



|                                                                                                   |              |      |      |                  
|-------------------------------------------------------------------------------------------------- | ------------ | ---- | ---- | -----------------
|Abandonment and Reclamation Costs                                                                  |              |      |      |                  
|($millions, net to Perpetual)                                                                      | Undiscounted | 5%   | 8%   | Discounted at 10%
|Well abandonment costs for developed reserves included in McDaniel and GLJ Reports                 | 56           | 35   | 27   | 23               
|Well abandonment costs for undeveloped reserves included in McDaniel and GLJ Reports               | 27           | 14   | 9    | 7                
|Well abandonment costs for Total Proved and Probable reserves included in McDaniel and GLJ Reports | 83           | 49   | 37   | 30               
|Estimate of other abandonment and reclamation costs not included in McDaniel or GLJ Reports        | 232          | 137  | 103  | 86               
|Total estimated future abandonment and reclamation costs                                           | 315          | 186  | 140  | 117              
|Salvage value                                                                                      | (148)        | (88) | (66) | (55)             
|Abandonment and reclamation costs, net of salvage                                                  | 167          | 98   | 74   | 62               
|Well abandonment costs for developed reserves included in McDaniel and GLJ Reports                 | (56)         | (35) | (28) | (24)             
|Estimate of additional future abandonment and reclamation costs, net of salvage(1)                 | 110          | 63   | 46   | 38               



(1)

Future abandonment and reclamation costs not included in the McDaniel and GLJ Reports, net of salvage value.



The asset retirement obligation presented in Perpetuals financial statements is discounted using an estimate of the timing of asset retirement expenditures and Perpetuals estimated credit-adjusted discount rate, which is reviewed and adjusted annually for changes in credit markets and other internal and external factors. These expenditures are currently expected to occur over the next 25 years with the majority of costs incurred between 2015 and 2020. Perpetuals discounted asset retirement obligation increased from $194.6 million at December 31, 2009 to $199.2 million at December 31, 2010 primarily due to abandonment liabilities acquired with the Edson Acquisition and accretion expense for the year, partially offset by non-core property dispositions.







Page 28



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Income taxes



As a result of the corporate conversion completed by Perpetual on June 30, 2010, the Corporation is subject to Canadian corporate federal and provincial income tax legislation, beginning on the conversion date. While distributions up to and including the June 2010 distribution paid July 15, 2010 were deductible in computing income for tax purposes of the Corporation, dividends declared by Perpetual after the conversion date are not deductible in determining taxable income of the Corporation. Perpetual has significant tax pools available to offset future taxable income.



Perpetual recorded future tax expense of $2.1 million for 2010 (2009  $0.4 million), related to timing differences between book and tax values of the Corporations gas storage assets. The tax values of the Corporations non-gas storage assets currently exceed the related book values. Future income tax is a non-cash item and does not affect the Corporations funds flows or its cash available for dividends.



Tax pools



|                                              |                        
|--------------------------------------------- | -----------------------
|Tax pool information ($ millions)             | As at December 31, 2010
|Canadian oil and gas property expense (COGPE) | 328                    
|Canadian development expense (CDE)            | 163                    
|Canadian exploration expense (CEE)            | 68                     
|Undepreciated capital cost (UCC)              | 229                    
|Share issue costs                             | 1                      
|Non-capital losses                            | 54                     
|Total                                         | 843                    



At December 31, 2010, the Corporations consolidated income tax pools are estimated to be $843 million.  Actual tax pool amounts may vary as tax returns are finalized and filed.



Net earnings



The Corporation recorded a net loss of $28.5 million or $0.20 per basic and diluted Common Share in 2010 as compared to net earnings of $13.6 million or $0.11 per basic and diluted Common Share in 2009, as a result of an unrealized loss on financial instruments of $63.2 million and higher DD&A charges, partially offset by gains on sale of property, plant and equipment of $37.7 million in the current year.



LIQUIDITY, CAPITALIZATION AND FINANCIAL RESOURCES



|                                                           |                        |           |          
|---------------------------------------------------------- | ---------------------- | --------- | ---------
|Capitalization and financial resources                     | Year ended December 31
|($ thousands except per Common Shares and percent amounts) | 2010                   | 2009      | 2008     
|Long term bank debt                                        | 182,612                | 262,393   | 276,976  
|Convertible debentures, measured at principal amount       | 234,897                | 230,168   | 236,034  
|Working capital deficiency (surplus) (2)                   | 31,934                 | 8,450     | 7,859    
|Net debt                                                   | 449,443                | 501,011   | 520,869  
|Common Shares outstanding at end of period (thousands)     | 148,284                | 126,224   | 112,968  
|Market price at end of period                              | 3.93                   | 5.22      | 5.05     
|Market value of Common Shares                              | 582,756                | 658,889   | 570,488  
|Total capitalization (1)                                   | 1,032,199              | 1,159,900 | 1,091,357
|Net debt as a percentage of total capitalization (%)       | 43.5                   | 43.2      | 47.7     
|Annualized fourth quarter funds flow (1)                   | 282,036                | 157,636   | 246,052  
|Net debt to funds flow ratio (times) (1)                   | 1.6                    | 3.2       | 2.1      

(1)

These are non-GAAP measures; see
"Significant accounting policies and non-GAAP measures" in this MD&A.

(2)

Working capital deficiency (surplus) excludes short-term financial instrument assets and liabilities related to the Corporations hedging activities, the current portion of convertible debentures and the stock option plan liability.







Page 29



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Perpetual has a revolving credit facility with a syndicate of Canadian chartered banks (the
"Credit Facility"). The revolving nature of the facility expires on May 31, 2011 if not extended. The borrowing base on the Credit Facility is currently $300 million, with the next borrowing base review scheduled for April 2010. At current interest rates and applicable margins, the effective interest rate on the Corporations bank debt is approximately 4.2 percent. Collateral for the credit facility is provided by a floating-charge debenture covering all existing and acquired property of the Corporation as well as unconditional full liability guarantees from all subsidiaries in respect of amounts borrowed under the facility. Bank debt drawn on Perpetuals credit facility decreased $79.7 million or 30 percent from December 31, 2009, and net debt decreased by ten percent  or $51.6 million for the same period due to strong funds flows and proceeds received from non-core property dispositions, partially offset by expenditures related to exploration and development and the construction of the WGSI Facility, as well as the Edson Acquisition and the increased working capital deficiency at December 31, 2010.



Perpetual has a working capital deficiency of $31.9 million at December 31, 2010, as compared to a deficiency of $8.5 million at December 31, 2009. The increase in the working capital deficiency is primarily related to higher capital spending in the fourth quarter of 2010 as compared to 2009. The Corporations working capital deficiency will be funded from future sales revenues and by additional borrowings from Perpetuals credit facility, as required.



Net debt to annualized fourth quarter funds flow decreased to 1.6 times for the three months ended December 31, 2010 from 3.2 times for the three months ended December 31, 2009 due to higher funds flows as a result of higher realized gains on financial instruments and lower debt levels. A reconciliation of the change in net debt from December 31, 2009 to December 31, 2010 is as follows.



|                                                                          |        
|------------------------------------------------------------------------- | -------
|Reconciliation of net debt ($ millions)                                   |        
|Net debt, December 31, 2009                                               | 501.0  
|Capital expenditures (exploration and development, gas storage and other) | 173.5  
|Acquisitions, net of dispositions                                         | 50.7   
|Funds flow (1)                                                            | (237.2)
|Dividends                                                                 | 78.6   
|Expenditures on asset retirement obligations                              | 4.9    
|DRIP proceeds                                                             | (43.3) 
|Severo common share issue (2)                                             | (0.5)  
|Issue of common shares, net of issue costs                                | (54.6) 
|Issue and amendment costs on convertible debentures                       | 2.9    
|Unrealized loss on marketable securities                                  | 1.3    
|Proceeds from gas storage arrangement, net of issue costs                 | (31.2) 
|Gas over bitumen royalty adjustments not yet received                     | 3.3    
|Net debt, December 31, 2010                                               | 449.4  

(1)

These are non-GAAP measures; see
"Other non-GAAP measures" in this MD&A.

(2)

Severo raised a total of $0.5 million through a private share offering to existing shareholders in 2010. As Perpetual owns a controlling interest in Severo, its financial results are consolidated with those of the Corporation. Effective October 5, 2010 Perpetual purchased the remaining 11 percent interest in Severo and Severo became a wholly-owned subsidiary of the Corporation.



The Corporation expects that its dividends and capital expenditure program for 2011 will be funded by funds flow and drawings on the Credit Facility. However, changes in natural gas prices, cash netbacks and production levels can affect future capital spending plans and dividends.



Gas storage arrangement



As part of the Corporations semi-annual borrowing base redetermination in May 2010, Perpetuals gas reserves in the Warwick Glauconitic-Nisku A pool were removed from the assets dedicated to secure the syndicated banking facility. In order to provide non-bank funding for the majority of the WGSI Facility, Perpetual has entered into a gas sale and storage transaction which includes the forward sale of these reserves, currently in the storage reservoir, that provide the
"cushion" gas for the storage operation. In accordance with the storage arrangement funding, Perpetual received $31.6 million on June 30, 2010. An additional $10 million was held in escrow at December 31, 2010 pending satisfaction of certain conditions; $5 million of these funds have since been received. In exchange for the funds received, the Corporation has agreed to deliver 8 Bcf of natural gas to the counterparty during the first quarter of 2013. Perpetual has since extended the delivery term to the first quarter of 2014, and subsequent to year-end the obligation was extended to 2015. The gas storage liability on the balance sheet and the additional amount in escrow represent the estimated net present fair value of the future delivery obligation and as such, the liability will be accreted until its maturity, using the effective interest rate method. In the current year the Corporation recorded a financial instrument asset of $3.7 million related to the change in the forward price curves for natural gas and a corresponding unrealized gain on financial instruments on the statement of earnings.







Page 30



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



|                                     |                        |      |           |           |           
|------------------------------------ | ---------------------- | ---- | --------- | --------- | ----------
|                                     | Payments due by period
|Contractual obligations ($ millions) | Total                  | 2011 | 2012-2013 | 2014-2015 | Thereafter
|Bank and other debt (1)              | 182.6                  | -    | 182.6     | -         | -         
|Convertible debentures, principal    | 234.9                  | -    | 74.9      | 160.0     | -         
|Operating leases (3)                 | 15.2                   | 2.4  | 4.4       | 4.0       | 4.4       
|Pipeline commitments (2)             | 14.6                   | 6.7  | 6.2       | 1.3       | 0.4       
|Total contractual obligations        | 447.3                  | 9.1  | 268.1     | 165.3     | 4.8       

(1)

The revolving feature of Perpetuals credit facility expires on May 31, 2011 if not extended.  Upon expiry of the revolving feature of the facility, should it not be extended, amounts outstanding as of the expiry date will have a term to maturity date of one additional year.

(2)

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

(3)

Perpetual has office leases on its current office space, and on Profounds office space. Office lease commitments are shown net of related sublease recoveries.



Convertible debentures



As at December 31, 2010, the Corporation had 6.5 percent convertible debentures issued in June 2007 (6.50% Debentures), 7.25 percent convertible debentures issued in April 2006 and amended in 2009 (7.25% Debentures) and 7.0 percent convertible debentures issued in May 2010 (7.0% Debentures). The Corporations 6.25 percent convertible debentures, of which $55.3 million were outstanding, were repaid in cash on June 30, 2010. All series of debentures are repayable on the maturity date in cash or in common shares, at the option of Perpetual. Additional information on convertible debentures is as follows.

|                                                     |               |                  |                   | 
|---------------------------------------------------- | ------------- | ---------------- | ----------------- | 
|Convertible debentures                               | 6.50%         | 7.25%            | 7.00%             | 
|Principal issued ($ millions)                        | 75.0          | 100.0            | 60.0              | 
|Principal outstanding ($ millions)                   | 74.9          | 100.0            | 60.0              | 
|Trading symbol on the Toronto Stock Exchange ("TSX") | PMT.DB.C      | PMT.DB.D         | PMT.DB.E          | 
|Maturity date                                        | June 30, 2012 | January 31, 2015 | December 31, 2015 | 
|Conversion price ($ per Common Share)                | 14.20         | 7.50             | 7.00              | 
|Fair market value ($ millions)                       | 75.7          | 102.0            | 60.2              | 



Fair values of debentures are calculated by multiplying the number of debentures outstanding at December 31, 2010 by the quoted market price per debenture at that date. None of the debentures were converted into common shares during the year ended December 31, 2010.



On May 26, 2010, the Corporation issued $60.0 million of convertible unsecured junior subordinated debentures with an interest rate of 7.0 percent per annum, payable semi-annually on the last day of June and December commencing on December 31, 2010 (7.0% Debentures). The 7.0% Debentures will mature on December 31, 2015 and are subordinated to Perpetuals credit facility and all other outstanding convertible debentures. The Corporation incurred $2.8 million in fees in connection with the issuance, which has been netted against the carrying amount of the debentures on the balance sheet and will be amortized over the life of the debentures.



All series of debentures are redeemable by the Corporation at a premium to face value, pay interest semi-annually and are subordinated to substantially all other liabilities of Perpetual including the credit facility. The 7.0% Debentures are also subordinated to all other series of convertible debentures. The fair values of debentures are calculated by multiplying the number of debentures outstanding at December 31, 2010 by the quoted market price per debenture at that date.



Senior unsecured notes



On March 1, 2011 Perpetual announced its intention to issue $150 million of seven-year senior unsecured notes (the
"Senior Notes"). The Senior Notes will be direct senior unsecured obligations of Perpetual ranking pari passuwith all other present and future unsecured and unsubordinated indebtedness of the Corporation. The net proceeds from the Senior Notes offering will be used to repay existing indebtedness under Perpetual's existing credit facility. Additional benefits to Perpetual include significant extension of the term of a portion of its total debt and reduced exposure of its credit capacity to commodity prices, particularly near term weakness in natural gas prices. Pro forma for the Notes offering, Perpetual expects to be drawn approximately $70 million on its credit facility and approximately 70 percent of Perpetuals total outstanding debt will have a term extending beyond 2014. Closing is expected to occur on or about March 15, 2011 following a limited marketing process and determination of pricing.





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Shareholders equity



Perpetuals total capitalization was $1.0 billion at December 31, 2010 with the market value of the Common Shares at year-end of $3.93 per Common Share representing 56.5 percent of total capitalization.
During 2010, the closing market price of the Common Shares ranged from $3.78 to $5.47 with an average daily trading volume of 487,000 Common Shares.



Weighted average Common Shares outstanding for 2010 totaled 140.6 million (2009  118.2 million). On December 31, 2010 there were 148.3 million Common Shares outstanding.



Dividends



Dividends are determined monthly by the Board of Directors of the Corporation taking into account Perpetuals forecasted production, capital spending and funds flow, forward commodity price curves and managements view of future commodity prices, the Corporations current hedging position, targeted debt levels and debt repayment obligations. Amongst other things, the following items are considered in arriving at cash dividends to Shareholders:

·

Exploration and development expenditures;

·

Projected production additions;

·

Debt repayments to the extent required or deemed appropriate by management to preserve balance sheet strength for future opportunities;

·

Base production forecasts;

·

Current financial and physical forward commodity sales contracts;

·

Forward market for commodities, particularly natural gas;

·

Site reclamation and abandonment expenditures; and

·

Working capital requirements.



Dividends for the year ended December 31, 2010 totaled $78.6 million or $0.56 per common share, as compared to $75.8 million or $0.64 per common share for 2009. In response to low gas prices and an increase in Perpetuals 2010 capital expenditure budget, monthly dividends were reduced to $0.03 per common share per month effective with the November dividend payable on December 15, 2010.  The Corporations payout ratio, which is the ratio of dividends to funds flow, was 33.1 percent in 2010 as compared to 32.8 percent for 2009. Perpetuals dividends are less than funds flow as the Corporation retains a portion of its funds flow to finance capital expenditures and debt repayments. The payout ratio in future periods will largely be determined by the Corporations capital spending plans and resulting production levels, royalty rates, operating costs and commodity prices, which have experienced significant volatility in 2010. From the inception of the Corporation through to the December 2010 dividend, Perpetual has paid over $1.1 billion in dividends to Shareholders, or $14.324 per Common Share.



Perpetual has in place a Premium DividendTM and Dividend Reinvestment Plan (the "Premium DRIP Plan") which allows eligible Shareholders to elect, under the dividend reinvestment component of the Premium DRIP Plan, to have their monthly cash dividends reinvested in additional common shares on the applicable dividend payment date.  Participants in the dividend reinvestment component of the Premium DRIP Plan will have the ability to purchase common shares with dividend proceeds at a price per common share equal to 95 percent of the Average Market Price (as defined in the Premium DRIP Plan). The Premium DRIP Plan also allows eligible Shareholders to otherwise elect, under the Premium Dividend component of the Premium DRIP Plan, to have these additional common shares delivered to the designated Plan Broker in exchange for a premium cash payment equal to 102 percent of the cash dividend such Shareholders would otherwise have received on the applicable dividend payment date.  In the event that eligible Shareholders elect to participate in the Premium Dividend component of the Premium DRIP Plan, the additional common shares delivered to the designated Plan Broker will be issued from treasury at a five percent discount to the Average Market Price.







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In 2010, a total of 9.3 million Common Shares were issued in respect of the Premium DRIP Plan for net proceeds of $43.3 million to the Corporation (2009  7.6 million common shares and $35.8 million). Beginning with the November 2010 dividend the availability of Common Shares under the Premium DRIP Plan was suspended until further notice.



|                                                                     |                        |         
|-------------------------------------------------------------------- | ---------------------- | --------
|                                                                     | Year ended December 31
|Dividends ($ thousands)                                              | 2010                   | 2009    
|Cash flows provided by operating activities                          | 240,126                | 228,352 
|Net earnings (loss)                                                  | (28,546)               | 13,554  
|Dividends                                                            | 78,628                 | 75,838  
|Excess of cash flows provided by operating activities over dividends | 161,498                | 152,514 
|Shortfall of net earnings (loss) over dividends                      | (107,174)              | (61,445)



Perpetual targets long-term sustainability of both its production base and dividends to Shareholders, and targets growth and net asset value creation through resource plays and new venture investments. As such, dividend rates are designed to result in an excess of cash flows provided by operating activities over dividends which will provide the majority of the funding for Perpetuals exploration and development expenditures for the respective periods. Acquisitions and special projects such as gas storage are typically funded through a combination of internally generated funds, equity offerings and debt financing. The excess of $161.5 million (2009 - $152.5 million) compares to exploration and development expenditures (excluding gas storage) per the Corporations statement of cash flows of $111.4 million for the year ended December 31, 2010 (2009 - $51.0 million).  In periods where the excess of cash flows provided by operating activities over dividends is less than exploration and development expenditures, the shortfall is funded by additional bank borrowings and external financing activities as appropriate.



Perpetual had an excess of dividends over net earnings in 2010 and 2009, and dividends are likely to continue to exceed net earnings in future periods. The Corporation does not typically compare dividends to earnings due to the impact of non-cash items on earnings such as unrealized gains and losses on financial instruments, asset impairment charges and DD&A, which have no impact on Perpetuals ability to pay dividends. Where dividends exceed net earnings, a portion of the cash dividends declared may represent an economic return of capital to the Corporations Shareholders.



Perpetual has elected to minimize its tax pool claims in 2010 and, as such, cash distributions received or receivable by a Canadian resident, outside of a registered pension or retirement plan in the 2010 taxation year, prior to the conversion to a corporation are 100 percent taxable. Dividends paid by Perpetual after the corporate conversion are taxed as a dividend received from a taxable Canadian corporation.



|                                                                            |              |          |      
|--------------------------------------------------------------------------- | ------------ | -------- | -----
|2010 dividends and distributions by month
($ per Trust Unit / Common Share) |              |          |      
|Payment Date                                                                | Distribution | Dividend | Total
|February 16, 2010                                                           | 0.05         | 0.00     | 0.05 
|March 15, 2010                                                              | 0.05         | 0.00     | 0.05 
|April 15, 2010                                                              | 0.05         | 0.00     | 0.05 
|May 17, 2010                                                                | 0.05         | 0.00     | 0.05 
|June 15, 2010                                                               | 0.05         | 0.00     | 0.05 
|July 15, 2010                                                               | 0.05         | 0.00     | 0.05 
|August 16, 2010                                                             | 0.00         | 0.05     | 0.05 
|September 15, 2010                                                          | 0.00         | 0.05     | 0.05 
|October 15, 2010                                                            | 0.00         | 0.05     | 0.05 
|November 15, 2010                                                           | 0.00         | 0.05     | 0.05 
|December 15, 2010                                                           | 0.00         | 0.03     | 0.03 
|January 17, 2011                                                            | 0.00         | 0.03     | 0.03 
|Total (1)                                                                   | 0.30         | 0.26     | 0.56 

(1)

Total is based upon cash dividends and distributions declared during 2010.







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SUMMARY OF QUARTERLY RESULTS



|                                         |                    |               |               |             
|---------------------------------------- | ------------------ | ------------- | ------------- | ------------
|                                         | Three months ended
|($ thousands except where noted)         | Dec 31, 2010       | Sept 30, 2010 | June 30, 2010 | Mar 31, 2010
|Oil and natural gas revenues (1)         | 61,718             | 61,254        | 64,108        | 73,139      
|Production (MMcfe/d)                     | 145.1              | 151.0         | 165.2         | 149.2       
|Funds flow (2)                           | 70,509             | 46,078        | 36,162        | 84,419      
|Per common share - basic                 | 0.48               | 0.32          | 0.25          | 0.66        
|Net earnings (loss)                      | (19,874)           | (1,710)       | (44,211)      | 37,250      
|Per common share - basic                 | (0.13)             | (0.01)        | (0.31)        | 0.29        
|- diluted                                | (0.13)             | (0.01)        | (0.31)        | 0.29        
|Realized price ($/Mcfe)(3)               | 7.83               | 6.18          | 5.54          | 9.78        
|Average AECO Monthly Index price ($/Mcf) | 4.13               | 3.72          | 3.86          | 5.36        



|                                                  |                    |               |               |             
|------------------------------------------------- | ------------------ | ------------- | ------------- | ------------
|                                                  | Three months ended
|($ thousands except where noted)                  | Dec 31, 2009       | Sept 30, 2009 | June 30, 2009 | Mar 31, 2009
|Oil and natural gas revenues before royalties (1) | 56,987             | 47,875        | 58,631        | 82,750      
|Production (MMcfe/d)                              | 145.9              | 152.4         | 165.5         | 167.1       
|Funds flow (2)                                    | 39,409             | 59,599        | 91,186        | 41,154      
|Per Trust Unit - basic                            | 0.32               | 0.49          | 0.81          | 0.36        
|Net earnings (loss)                               | (11,392)           | (44,679)      | (8,835)       | 78,460      
|Per Trust Unit - basic                            | (0.09)             | (0.36)        | (0.08)        | 0.70        
|- diluted                                         | (0.09)             | (0.36)        | (0.08)        | 0.69        
|Realized price ($/Mcfe)                           | 5.53               | 7.51          | 9.10          | 6.46        
|Average AECO Monthly Index price ($/Mcf)          | 4.23               | 3.02          | 3.66          | 5.63        

(1)

Excludes realized gains (losses) on financial instruments, but includes gas storage revenue.

(2)

These are non-GAAP measures; see
"Other non-GAAP measures" in this MD&A.

(3)

Realized natural gas price includes realized gains and losses on financial hedging and physical forward sales contracts, and oil and natural gas liquids revenues measured on a per Mcfe basis.



Oil and natural gas revenues are primarily a function of production levels and natural gas prices before hedging. Revenues were highest in the first quarters of 2009 and 2010 when AECO prices were highest, averaging $5.63 and $5.36 per Mcf respectively, and lowest in the third quarter of 2009, when the AECO Monthly Index price averaged $3.02 per Mcf. Perpetual uses financial instruments to mitigate the effect of volatility in AECO prices on funds flows, and therefore funds flows will trend with Perpetuals realized gas price and changes in production levels. Funds flows were highest in the second quarter of 2009 and the first quarter of 2010 as a result of realized gas prices of $9.10 and $9.78 per Mcfe, respectively. Funds flows are lowest in the second quarter of 2010 due to a reduction in realized hedging gains relative to previous quarters, leading to a realized gas price of $5.54 per Mcfe.



Net earnings are a function of funds flows and non-cash charges such as DD&A and unrealized gains (losses) on financial instruments. Due to the volatility of natural gas prices and the Corporations hedging position, net earnings (losses) will fluctuate with changes in AECO gas prices as of each balance sheet date. Net earnings were highest in the first quarter of 2009 as a result of unrealized gains on financial instruments of $95.1 million.  The net losses in the second and fourth quarters of 2010 and the third quarter of 2009 were due to unrealized losses of $34.4 million, $47.7 million and $45.8 million, respectively on the change in mark-to-market value of Perpetuals financial instruments during those periods.



2011 OUTLOOK AND SENSITIVITIES



Perpetual is nearing completion of a $48 million capital spending program for the first quarter of 2011. Capital expenditures were directed principally toward the advancement of Perpetuals large-scope resource-style opportunities including:



·

The completion of two gross (1.5 net) horizontal wells and the drilling and completion of three gross (3.0 net) wells targeting the liquids-rich Wilrich sand in the Edson area of west central Alberta;

·

The drilling of four gross (3.0 net) horizontal wells targeting oil in the Cardium formation at Carrot Creek;

·

Tie-in operations for the Elmworth Montney play to establish production from the three Montney evaluation wells;

·

Drilling two (2.0 net) horizontal heavy oil wells at Mannville in eastern Alberta;

·

The drilling of seven oilsands evaluation wells, and two vertical and one horizontal wells to test potential cold flow heavy oil production, focusing on potential deposits in the Panny, Liege, Hoole and Clyde areas; and



·

Detailed core and fracture stimulation analysis for development of the Viking/Colorado shale pilot program in eastern Alberta scheduled for the fourth quarter of 2011.







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First quarter capital spending also incorporated four gross (4.0 net) drills and approximately 50 recompletions undertaken in various areas of Perpetuals conventional asset base, in addition to drilling one development well to increase working gas capacity at the WGSI Facility.



The Corporations Board of Directors has approved a capital spending budget of $42 million for the remainder of 2011 for an annual total capital expenditure budget of $90 million, including gas storage. Capital activity for the remainder of the year will continue to be focused on oil and liquids-rich projects including:



·

The drilling and completion of two additional gross (2.0 net) wells targeting the Wilrich in the Edson area;

·

The drilling and completion an additional 25-30 (25-30 met) horizontal heavy oil wells targeting the Lloyd and Sparky formation at Mannville in eastern Alberta; and

·

Completion of core work and commencement of the Viking/Colorado shale pilot program in eastern Alberta.



Incorporating production additions from these capital expenditures, the following table shows Perpetuals estimate of key measures for 2011 based on its current hedging portfolio and cost estimates under several different full year 2011 AECO gas price assumptions, an average realized price of $88 per bbl of oil and NGL sales, and incorporating a non-core property disposition closed in February 2011 for proceeds of $9 million and completion of the Corporations offering of $150 million of Senior Notes in March 2011.



|                                                     |                                                           |       |      
|---------------------------------------------------- | --------------------------------------------------------- | ----- | -----
|                                                     | Average full year AECO monthly index gas price ($/GJ) (3)
|Funds flow outlook                                   | $3.00                                                     | $4.00 | $5.00
|Natural gas production (MMcf/d)                      | 135                                                       | 135   | 135  
|Oil and NGL production (bbl/d)                       | 1,800                                                     | 1,800 | 1,800
|Realized price ($/Mcfe)                              | 4.13                                                      | 5.09  | 6.04 
|Funds flow (1)($ millions)                           | 56                                                        | 101   | 141  
|Per Common Share (1)($/Share/month)                  | 0.032                                                     | 0.057 | 0.079
|Payout ratio (1) (4)(%)                              | 95                                                        | 53    | 38   
|Ending net bank debt ($ millions)                    | 145                                                       | 100   | 60   
|Ending net bank debt to funds flow ratio (2)(times)  | 2.6                                                       | 1.0   | 0.4  
|Ending total net debt ($ millions)                   | 526                                                       | 482   | 442  
|Ending total net debt to funds flow ratio (2)(times) | 9.4                                                       | 4.8   | 3.1  

(1)

These are non-GAAP measures; see
"Significant accounting policies and non-GAAP measures" in managements discussion and analysis.

(2)

Calculated as long-term bank debt net of working capital (excluding financial instrument assets and liabilities) divided by annualized funds flow. Total net debt includes net bank debt, convertible debentures and medium term notes.

(3)

Average AECO settled and forward price for 2011 as at March 7, 2011was $3.44 per GJ.

(4)

Estimated payout ratio assumes a dividend rate of $0.03 per month per Common Share for January through December 2011.



Below is a table that shows sensitivities of Perpetuals 2011 estimated funds flow to operational changes and changes in the business environment:



|                                                     |                |                                       |        
|---------------------------------------------------- | -------------- | ------------------------------------- | -------
|                                                     |                | Impact on funds flow per Common Share
|Funds flow sensitivity analysis ($ per Common Share) | Change         | Annual                                | Monthly
|Business Environment                                 |                |                                       |        
|Natural gas price at AECO                            | $0.25 per Mcf  | 0.075                                 | 0.006  
|Interest rate on bank debt                           | 1%             | 0.008                                 | 0.001  
|Operational                                          |                |                                       |        
|Production volume                                    | 5 MMcf/d       | 0.043                                 | 0.004  
|Operating costs                                      | $0.10 per Mcfe | 0.036                                 | 0.003  
|Cash general and administrative expenses             | $0.10 per Mcfe | 0.036                                 | 0.003  



The Corporations outlook and sensitivities assume an average AECO price of $3.44 per Mcfe, operating costs of $1.70 per Mcfe, cash general and administrative expenses of $0.65 per Mcfe, an interest rate on bank debt of 3.8 percent and incorporate the Corporations financial and physical forward sales portfolio at March 7, 2011. Cash general and administrative expenses are equal to general and administrative expenses before stock-based compensation.







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OTHER SIGNIFICANT ACCOUNTING POLICIES AND NON-GAAP MEASURES



Payout ratio



Payout ratio refers to dividends measured as a percentage of funds flow for the period and is used by management to analyze funds flow available for development and acquisition opportunities as well as overall sustainability of dividends. Funds 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 funds flow netbacks



Operating and funds flow netbacks are used by management to analyze margin and funds flow on each Mcfe of oil and natural gas production. Operating and funds 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 funds flow netbacks should not be viewed as an alternative to funds flow from operations, net earnings per common share or other measures of financial performance calculated in accordance with GAAP.



Revenue, including realized gains (losses) on financial instruments



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



Net debt and net bank debt



Net bank debt is measured as bank debt including net working capital (deficiency) excluding short-term financial instrument assets and liabilities related to the Corporations hedging activities, the current portion of convertible debentures, restricted cash and liabilities related to Perpetuals stock option plan. Net debt includes convertible debentures, measured at principal amount. Net bank debt and net debt are used by management to analyze leverage. Net bank debt and net debt do not have any standardized meaning prescribed by Canadian GAAP and therefore these terms may not be comparable with the calculation of similar measures for other entities.



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 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 Corporation.



CRITICAL ACCOUNTING ESTIMATES



The MD&A is based on the Corporation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. Perpetual 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 Corporations consolidated financial statements and notes thereto.



Accounting for petroleum and natural gas operations



Under the successful efforts method of accounting, the Corporation 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.





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Reserve estimates



Estimates of the Corporations reserves included in its consolidated financial statements are prepared in accordance with guidelines established by the Canadian Securities Administrators. 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.



Perpetual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 Corporation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 Corporation records depletion increases thereby reducing net earnings. In addition, changes in reserve estimates may impact the outcome of Perpetuals assessment of its petroleum and natural gas properties for impairment.



Business combinations



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



Impairment of petroleum and natural gas properties



The Corporation reviews its proved properties for impairment on anoperational field basis.  For each property, an impairment provision is recorded whenever events or circumstances indicate that the carrying value of that property may not be recoverable. The impairment provision is based on the excess of carrying value over fair value. Fair value is defined as the present value of the future net revenues from the property as estimated by the Corporation 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 Corporation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.  Perpetual engages an independent environmental consulting firm to analyze and prepare an annual estimate of the Corporation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.







Page 37



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NEW ACCOUNTING STANDARDS



The Corporation has early adopted new accounting standards for business combinations effective January 1, 2010, as follows:



a) Section 1582  Business Combinations. The new standard replaces the previous business combinations standard and requires assets and liabilities acquired in a business combination, contingent consideration and certain acquired contingencies to be measured at their fair values as of the date of acquisition. Transaction costs are charged to earnings as opposed to being included in the cost of the acquisition.



b) Section 1601  Consolidated Financial Statements and Section 1602  Non-Controlling Interests. The new standards provide revised requirements for preparing consolidated financial statements. Section 1602 requires a non-controlling interest in a subsidiary to be classified as a separate component of equity, and requires that net earnings (losses) be attributed to both the parent and the non-controlling interest.



Adoption resulted in the Corporation presenting earnings before non-controlling interest in the statements of earnings with separate presentation of earnings attributable to non-controlling interests, and including non-controlling interest in the Shareholders equity section of the Corporations consolidated balance sheet.



INTERNATIONAL FINANCIAL REPORTING STANDARDS (
"IFRS")



Effective January 1, 2011 IFRS will replace GAAP in Canada for publicly accountable enterprises. Perpetuals first reporting period under IFRS will be interim financial statements for period ended March 31, 2011 and first IFRS annual financial statements for year ended December 31, 2011. The adoption date of January 1, 2011 will require the restatement, for comparative purposes, of amounts reported by Perpetual for the various reporting periods in 2010, including the opening IFRS balance sheet as of January 1, 2010.



IFRS project plan



The Corporation has identified key personnel with expertise to manage its transition to IFRS, and engaged an IFRS project coordinator. During 2009 and 2010, Perpetual staff were involved in external IFRS training and development by attending conferences, participating in special interest seminars, participating in peer group meetings, and attending training sessions put on by various accounting service firms.



Diagnostic phase



Perpetuals project plan consisted of a diagnostic phase in which the IFRS were reviewed in detail with emphasis on areas which could potentially affect Perpetuals financial statements. Among the standards covered by this review were those affecting Inventory, Property Plant and Equipment, Exploration and Evaluation Assets, Borrowing Costs, Impairment, Financial Instruments, Provisions including Asset Retirement Obligations, Government Assistance and Business Combinations. Also covered were IFRS on Revenue, Leases, and Earnings per Share. IFRS 1 covering transition to IFRS financial reporting and IFRS 34 covering Interim Consolidated Financial statements were also reviewed.



Solution development



For each of the areas identified above, an accounting policy document was created and reviewed by senior management. The policy document outlines potential differences between IFRS and GAAP, and Perpetuals proposed accounting policy if different from the current policy under GAAP. Significant differences have been communicated to the Audit Committee of the Board of Directors of the Corporation ("Audit Committee").



Implementation



Perpetuals new accounting policies will be communicated to all Accounting, Finance, Operations, Human Resources and Investor Relations staff affected by the changes. Existing accounting and reporting systems are also being evaluated to ensure any changes required to comply with IFRS are made prior to the initial reporting period.



The implementation phase is expected to be completed upon issuance of the Corporations 2011 audited annual financial statements.





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First-time adoption of IFRS



IFRS 1, "First-Adoption of International Financial Reporting Standards" ("IFRS 1"), sets out the procedures that an entity must follow when it adopts IFRS for the first time as the basis for preparing its general purpose financial statements. In addition, IFRS 1 provides entities adopting IFRS for the first time with a number of optional exemptions and mandatory exceptions in certain areas to the general requirement of full retrospective application of
IFRS. Perpetual continues to review the potential adjustments to the January 1, 2010 opening IFRS balance sheet ("IFRS Opening Balance Sheet") and the effects of transition to IFRS are subject to change. The most significant accounting
policies that have been identified and the key differences that may impact the Opening IFRS Balance Sheet are as follows:



Trust Unit classification  Under IFRS Trust Units outstanding prior to Perpetuals conversion to a corporation are recorded as long-term liabilities, whereas under GAAP Trust Units were classified as Unitholders equity. Perpetual anticipates that approximately $1 billion in Unitholders equity will be reclassified to Trust Unit liability for its Opening IFRS Balance Sheet.



Business combinations - IFRS 1 would allow Perpetual to adopt the IFRS policies for business combinations on a prospective basis rather than retrospectively restating all prior business combinations. Perpetual is expecting to use this IFRS 1 exemption and not restate any business combinations prior to the IFRS transition date of January 1, 2010. The IFRS standards for business combinations are converged with the new CICA Handbook section 1582 that Perpetual early adopted as at January 1, 2010 thus aligning GAAP with IFRS.



Accounting for exploration and evaluations ("E&E") expenditures  Upon transition to IFRS, Perpetual will reclassify approximately $120 million of E&E expenditures that are currently included in the property, plant and equipment balance on the Opening IFRS Balance Sheet. This will be comprised primarily of the book value of Perpetuals undeveloped land, but could also include exploratory wells or other capitalized expenditures that are outside of developed fields, and for which oil and gas reserves have not yet been assigned. E&E assets will not be depleted but must be assessed for impairment when there are indicators for possible impairment, such as allowing the mineral rights lease to expire or a decision to no longer pursue exploration and evaluation of a specific E&E asset.



Impairment of property, plant & equipment ("PP&E") assets  Perpetual is required to assess PP&E assets for potential indicators of impairment upon transition to IFRS. Under IFRS, impairment of PP&E must be assessed at the Cash Generating Unit ("CGU") level, using the greater of fair value less costs to sell or value in use. The Corporation currently assesses impairment on PP&E assets at a district level, and it is anticipated that the CGUs identified will not differ significantly from the Corporations existing districts. However, the cost recovery test current performed in accordance with successful efforts accounting involves measuring book values of PP&E compared to undiscounted reserve values, where IFRS will require testing PP&E against fair value or value in use, which may result in more frequent impairment charges being recorded. Unlike GAAP, impairment charges can be reversed in future periods under IFRS. Perpetual do not currently expect to record any impairment of oil and gas assets on transition to IFRS.



Impairment of goodwill Perpetual is required to assess goodwill for impairment upon transition to IFRS. Currently impairment of goodwill is assessed at a consolidated level under GAAP. Under IFRS, goodwill is identified with specific CGUs or group of CGUs to which the goodwill relates, and consequently impairment must be assessed at a more detailed level. The goodwill recorded on the Corporations balance sheet is partially related to the acquisition of natural gas assets in Saskatchewan which have since been sold, and as such Perpetual anticipates that a goodwill impairment charge of approximately $20 to $25 million will be recorded on transition to IFRS.



Borrowing costs  IFRS 23 requires the capitalization of interest on all qualifying projects with a substantial period of construction.  Under GAAP the Corporation had a choice of whether or not to capitalize interest on long-term projects. An entity may elect a date earlier than that of the transition date to IFRS per IFRS 1. Perpetual will elect to use August 1, 2009 rather than the transition date of January 1, 2010 in order to apply IFRS 23. Perpetual will capitalize approximately $1 million in interest on the Warwick gas storage project, which is the only qualifying project in 2009.



Compound financial instruments  Under IFRS 32 Financial Instruments: Presentation, Perpetual is required to separate its convertible debentures on its Opening IFRS Balance Sheet into two liability components, one representing the debenture liability and the second the conversion derivative. The conversion option, an equity item under GAAP, is a liability for IFRS due to liability classification of the Trust Units. However, in accordance with IFRS 1, a first-time adopter need not separate these two portions if the liability component is no longer outstanding at the date of transition to IFRS. The Corporation will elect to make use of this exemption for the 8% series of convertible debentures issued in 2004 and repaid in 2009.



With respect to Perpetuals other outstanding convertible debentures, a conversion option liability of $8 to 12 million will be recorded on transition to IFRS. The equity portion of convertible debentures will be eliminated from the Corporations Opening IFRS Balance Sheet. The conversion option liability will be revalued at each reporting period until the corporate conversion on June 30, 2010, at which time it will be reclassified to equity.



Provisions Under IFRS, contract liabilities and decommissioning obligations are classified as provisions. Decommissioning obligations, disclosed as asset retirement obligations under GAAP, will be calculated using a risk free discount rate under IFRS, which is currently estimated to be four percent. The net effect of using a risk free discount rate is an increase of approximately $50 to $70 million to decommissioning liabilities on transition to IFRS. A portion of the offsetting debit will be recorded to PP&E and a portion recorded to deficit, to represent the increased depletion expense on the higher PP&E balance.





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Share based compensation  Under IFRS Perpetuals share based compensation plan in existence while the Corporation was a trust, formerly accounted for as an equity based plan with the offset to compensation expense credited to contributed surplus, is considered to be a cash settled liability plan.  As such, Perpetual will record a stock option liability on its balance sheet of $5 to $8 million on transition to IFRS, and the liability must be fair valued every reporting date.



Subsequent to conversion to a corporation, Perpetual initiated certain changes to its stock option plan, including the implementation of a cash-settled dividend bonus arrangement for option-holders, that resulted in the plan being considered a liability settled plan and accounted for using intrinsic value accounting. Under IFRS Perpetuals stock option plan is considered to be equity-settled, while the dividend bonus arrangement is a liability-settled plan. As a result, stock-based compensation expenses and other activity related to the stock option plan will be recorded to contributed surplus, and a liability will be recorded for the dividend bonus arrangement.



Deferred (future) income taxes Under IFRS, deferred income taxes are calculated using the tax rate applicable to undistributed profits, which for income trusts in Alberta is 39 percent. Under GAAP Perpetual and the Trust had calculated future tax assets and liabilities using a tax rate of zero for periods where Perpetual was an income trust and average corporate tax rates for expected timing differences as of January 1, 2011, the date that trust distributions were no longer deductible in calculating income for tax purposes. Other differences identified under IFRS must also be tax-effected as part of the transition to IFRS. As Perpetual did have a future tax liability or asset on its consolidated balance sheet as of December 31, 2009, no adjustment on transition to IFRS is expected.



Management has not yet finalized its accounting policies and as such the key differences identified may change. In addition, due to potential changes to IFRS prior to Perpetuals adoption of IFRS, managements plan and accounting policy decisions are subject to change based on new facts and circumstances that arise after the date of this MD&A. The final decisions are subject to the approval of Perpetuals Audit Committee and Board of Directors and the concurrence of the Corporations auditors. Perpetual continues to monitor the IFRS adoption efforts of many of its peers and participates in related processes, as appropriate.



Effect of IFRS transition on internal controls and disclosure controls and procedures



Management is currently assessing the impact of the transition to IFRS and new accounting policies on its business processes and disclosure controls and procedures, and adding or modifying processes and controls where appropriate. Credit facility agreements and other third party contracts are being reviewed to ensure the transition to IFRS does not have a significant unintended consequence on these agreements or the Corporations compliance with any terms therein. Specific communications related to the nature of changes in the Corporations financial statements caused by the transition to IFRS will be developed for investors and other stakeholders in 2011.



RISK FACTORS



Perpetuals operations are affected by a number of underlying risks, both internal and external to the Corporation.  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 Corporations financial position, results of operations, and cash available for distribution to Shareholders are directly impacted by these factors.



Changes in tax legislation

Income tax laws, or other laws or government incentive programs relating to the natural gas industry such as resource taxation may be changed or interpreted in a manner that adversely affects us and our Shareholders.  Tax authorities having jurisdiction over us or our Shareholders may disagree with how we calculate our income for tax purposes or could change administrative practices to our detriment or to the detriment of Shareholders.



Shut in natural gas reserves as a result of gas over bitumen issues



Recent decisions by the AEUB have brought into question our ability to continue to produce natural gas from all of the Wabiskaw and McMurray formations in certain parts of the Athabasca Oil Sands Area in Northeast Alberta.  The AEUB has ordered shut-in of some of our production and reserves in this area.



The AEUB has also indicated that it believes there is a need to assess whether additional gas production should be curtailed in situations similar to those considered at hearings to-date and whether there is a need for a broad bitumen conservation strategy in all areas where natural gas production may interfere with eventual bitumen recovery. It is possible that such a strategy, when drafted and implemented by the ERCB (formerly AEUB), will affect future natural gas production from reservoirs owned by the Corporation and located within the gas over bitumen areas of concern as
gas production from a portion or all of these zones may be identified in the future as posing a potential concern with respect to communication with potentially recoverable bitumen resources.





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While we have no significant additional production recommended for shut-in by any party or the ERCB at this time and royalty adjustments are being received for most 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 our funds flows and earnings.



Solution gas ownership



A portion of Perpetual's natural gas production is from properties where third parties hold bitumen rights.  Certain of these third parties have suggested that "solution gas" exists within the bitumen and that therefore this solution gas is the property of the bitumen rights holder.  If this is proven to be correct, and if it is demonstrated that this solution gas has been or may continue to be produced in association with the recovery of Perpetual's conventional natural gas rights, these facts may give rise to a third party claim for compensation.  A successful claim in this regard may have a material adverse effect on the Corporation's business, financial condition and operations.



Exploration, development and production risks

Oil and natural gas operations involve many risks that even a combination of experience, knowledge and careful evaluation may not be able to overcome.  The long-term commercial success of the Corporation depends on its ability to find, acquire, develop and commercially produce oil and natural gas reserves.  Substantial capital expenditures are required for exploration, development and production of oil and natural gas reserves in the future.  Without the continual addition of new reserves, any existing reserves the Corporation may have at any particular time, and the production therefrom will decline over time as such existing reserves are exploited.  A future increase in the Corporation's reserves will depend not only on its ability to explore and develop any properties it may have from time to time, but also on its ability to select and acquire suitable producing properties or prospects.  No assurance can be given that the Corporation will be able to continue to locate satisfactory properties for acquisition or participation.  Moreover, if such acquisitions or participations are identified, management of the Corporation may determine that current markets, terms of acquisition and participation or pricing conditions make such acquisitions or participations uneconomic.  There is no assurance that further commercial quantities of oil and natural gas will be discovered or acquired by the Corporation.



Future oil and natural gas exploration may involve unprofitable efforts, not only from dry wells, but also from wells that are productive but do not produce sufficient petroleum substances to return a profit after drilling, operating and other costs.  Completion of a well does not assure a profit on the investment or recovery of drilling, completion and operating costs.  In addition, drilling hazards or environmental damage could greatly increase the cost of operations, and various field operating conditions may adversely affect the production from successful wells.  These conditions include delays in obtaining governmental approvals or consents, shut-ins of connected wells resulting from extreme weather conditions, insufficient storage or transportation capacity or other geological and mechanical conditions.  While diligent well supervision and effective maintenance operations can contribute to maximizing production rates over time, production delays and declines from normal field operating conditions cannot be eliminated and can be expected to adversely affect revenue and cash flow levels to varying degrees.



Oil and natural gas exploration, development and production operations are subject to all the risks and hazards typically associated with such operations, including hazards such as fire, explosion, blowouts, cratering, sour gas releases and spills, each of which could result in substantial damage to oil and natural gas wells, production facilities, other property and the environment or personal injury.  In particular, the Corporation may explore for and produce sour natural gas in certain areas.  An unintentional leak of sour natural gas could result in personal injury, loss of life or damage to property and may necessitate an evacuation of populated areas, all of which could result in liability to the Corporation.  In accordance with industry practice, the Corporation is not fully insured against all of these risks, nor are all such risks insurable.  Although the Corporation maintains liability insurance in an amount that it considers consistent with industry practice, the nature of these risks is such that liabilities could exceed policy limits, in which event the Corporation could incur significant costs.  Oil and natural gas production operations are also subject to all the risks typically associated with such operations, including encountering unexpected formations or pressures, premature decline of reservoirs and the invasion of water into producing formations.  Losses resulting from the occurrence of any of these risks may have a material adverse effect on the Corporation's business, financial condition, results of operations and prospects.



Prices, markets and marketing

The marketability and price of oil and natural gas that may be acquired or discovered by the Corporation is and will continue to be affected by numerous factors beyond its control.  The Corporation's ability to market its oil and natural
gas may depend upon its ability to acquire space on pipelines that deliver natural gas to commercial markets.  The Corporation may also be affected by deliverability uncertainties related to the proximity of its reserves to pipelines and processing and storage facilities and operational problems affecting such pipelines and facilities as well as extensive government regulation relating to price, taxes, royalties, land tenure, allowable production, the export of oil and natural gas and many other aspects of the oil and natural gas business.





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The prices of oil and natural gas prices may be volatile and subject to fluctuation.  Any material decline in prices could result in a reduction of the Corporation's net production revenue.  The economics of producing from some wells may change as a result of lower prices, which could result in reduced production of oil or gas and a reduction in the volumes of the Corporation's reserves.  The Corporation might also elect not to produce from certain wells at lower prices.  All of these factors could result in a material decrease in the Corporation's expected net production revenue and a reduction in its oil and gas acquisition, development and exploration activities.  Prices for oil and gas are subject to large fluctuations in response to relatively minor changes in the supply of and demand for oil and gas, market uncertainty and a variety of additional factors beyond the control of the Corporation.  These factors include economic conditions, in the United States and Canada, the actions of OPEC, governmental regulation, political stability in the Middle East and elsewhere, the foreign supply of oil and gas, risks of supply disruption, the price of foreign imports and the availability of alternative fuel sources.  Any substantial and extended decline in the price of oil and gas would have an adverse effect on the Corporation's carrying value of its reserves, borrowing capacity, revenues, profitability and cash flows from operations and may have a material adverse effect on the Corporation's business, financial condition, results of operations and prospects.



Petroleum prices are expected to remain volatile for the near future as a result of market uncertainties over the supply and the demand of these commodities due to the current state of the world economies, OPEC actions and the ongoing credit and liquidity concerns.  Volatile oil and gas prices make it difficult to estimate the value of producing properties for acquisition and often cause disruption in the market for oil and gas producing properties, as buyers and sellers have difficulty agreeing on such value.  Price volatility also makes it difficult to budget for and project the return on acquisitions and development and exploitation projects.



In addition, bank borrowings available to the Corporation may, in part, be determined by the Corporation's borrowing base.  A sustained material decline in prices from historical average prices could reduce the Corporation's borrowing base, therefore reducing the bank credit available to the Corporation which could require that a portion, or all, of the Corporation's bank debt be repaid.



The Corporation manages commodity price uncertainty through financial hedges and physical forward sale arrangements. There is a credit risk associated with counterparties with which the Corporation may contract.



Failure to realize anticipated benefits of acquisitions and dispositions

The Corporation makes acquisitions and dispositions of businesses and assets in the ordinary course of business.  Achieving the benefits of acquisitions depends in part on successfully consolidating functions and integrating operations and procedures in a timely and efficient manner as well as the Corporation's ability to realize the anticipated growth opportunities and synergies from combining the acquired businesses and operations with those of the Corporation.  The integration of acquired business may require substantial management effort, time and resources and may divert management's focus from other strategic opportunities and operational matters.  Management continually assesses the value and contribution of services provided and assets required to provide such services.  In this regard, non-core assets are periodically disposed of, so that the Corporation can focus its efforts and resources more efficiently.  Depending on the state of the market for such non-core assets, certain non-core assets of the Corporation, if disposed of, could be expected to realize less than their carrying value on the financial statements of the Corporation.



Operational dependence

Other companies operate some of the assets in which the Corporation has an interest.  As a result, the Corporation has limited ability to exercise influence over the operation of those assets or their associated costs, which could adversely affect the Corporation's financial performance.  The Corporation's return on assets operated by others therefore depends upon a number of factors that may be outside of the Corporation's control, including the timing and amount of capital expenditures, the operator's expertise and financial resources, the approval of other participants, the selection of technology and risk management practices.





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Project risks

The Corporation manages a variety of small and large projects in the conduct of its business.  Project delays may delay expected revenues from operations.  Project cost over-runs could make a project uneconomic.  The Corporation's ability
to execute projects and market oil and natural gas depends upon numerous factors beyond the Corporation's control, including:



·

the availability of processing capacity;

·

the availability and proximity of pipeline capacity;

·

the availability of storage capacity;

·

the supply of and demand for oil and natural gas;

·

the availability of alternative fuel sources;

·

the effects of inclement weather;

·

the availability of d­rilling and related equipment;

·

unexpected cost increases;

·

accidental events;

·

currency fluctuations;

·

changes in regulations;

·

the availability and productivity of skilled labour; and

·

the regulation of the oil and natural gas industry by various levels of government and governmental agencies.

Because of these factors, the Corporation could be unable to execute projects on time, on budget or at all, and may not be able to effectively market the oil and natural gas that it produces.



Competition

The petroleum industry is competitive in all its phases.  The Corporation competes with numerous other organizations in the search for, and the acquisition of, oil and natural gas properties and in the marketing of oil and natural gas.  The Corporation also competes with other companies for all of its business inputs including exploitation and development prospects, access to commodity markets, property and corporate acquisitions, and available capital.  The Corporation endeavours to be competitive by maintaining a strong financial condition through attracting and retaining technically competent and accountable staff, by refining and enhancing business processes on an ongoing basis and by utilizing current technologies to enhance exploitation, development and operational activities.  The Corporation's competitors include oil and natural gas companies that have substantially greater financial resources, staff and facilities than those of the Corporation.  The Corporation's ability to increase its reserves in the future will depend not only on its ability to explore and develop its present properties, but also on its ability to select and acquire other suitable producing properties or prospects for exploratory drilling.  Competitive factors in the distribution and marketing of oil and natural gas include price and methods and reliability of delivery and storage.  Competition may also be presented by alternate fuel sources.



Regulatory

Oil and natural gas operations (exploration, production, pricing, marketing and transportation) are subject to extensive controls and regulations imposed by various levels of government, which may be amended from time to time.  Governments may regulate or intervene with respect to price, taxes, royalties and the exportation of oil and natural gas.  Such regulations may be changed from time to time in response to economic or political conditions.  The implementation of new regulations or the modification of existing regulations affecting the oil and natural gas industry could reduce demand for natural gas and crude oil and increase the Corporation's costs, any of which may have a material adverse effect on the Corporation's business, financial condition, results of operations and prospects.  In order to conduct oil and gas operations, the Corporation will require licenses from various governmental authorities.  There can be no assurance that the Corporation will be able to obtain all of the licenses and permits that may be required to conduct operations which it may wish to undertake.



Environmental

All phases of the oil and natural gas business present environmental risks and hazards and are subject to environmental regulation pursuant to a variety of federal, provincial and local laws and regulations.  Environmental legislation provides for, among other things, restrictions and prohibitions on spills, releases or emissions of various substances produced in association with oil and natural gas operations.  The legislation also requires that wells and facility sites be operated, maintained, abandoned and reclaimed to the satisfaction of applicable regulatory authorities.  Compliance with such legislation can require additionalexpenditures and a breach of applicable environmental legislation may result in the imposition of fines and penalties, some of which may be material.  Environmental legislation is evolving in a manner expected to result in stricter standards and enforcement, larger fines and liability and potentially increased capital expenditures and operating costs.  The discharge of oil, natural gas or other pollutants into the air, soil or water may give rise to liabilities to governments and third parties and may require the Corporation to incur costs to remedy such discharge.  Although the Corporation believes that it will be in material compliance with current applicable
environmental regulations no assurance can be given that environmental laws will not result in a curtailment of production or a material increase in the costs of production, development or exploration activities or otherwise have a material adverse effect on the Corporation's business, financial condition, results of operations and prospects.





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Climate change

Canada is a signatory to the United Nations Framework Convention on Climate Change and has ratified the Kyoto Protocol established thereunder to set legally binding targets to reduce nationwide emissions of carbon dioxide, methane, nitrous oxide and other so-called "greenhouse gases".



There has been much public debate with respect to Canada's ability to meet these targets and the Government's strategy or alternative strategies with respect to climate change and the control of greenhouse gases.  Recently, representatives from approximately 170 countries met in Copenhagen, Denmark to attempt to negotiate a successor to the Kyoto Protocol.  The result of such meeting was the Copenhagen Accord, a non-binding political consensus rather than a binding international treaty such as the Kyoto Protocol.  The Corporation's exploration and production facilities and other operations and activities emit greenhouse gases and require the Corporation to comply with Alberta's greenhouse gas emissions legislation contained in the Climate Change and Emissions Management Act and the Specified Gas Emitters Regulation.  The Corporation will also be required comply with the regulatory scheme for greenhouse gas emissions ultimately adopted by the federal government, which are now expected to be consistent with the regulatory scheme for greenhouse gas emissions adopted by the United States.  The direct or indirect costs of these regulations may have a material adverse effect on the Corporation's business, financial condition, results of operations and prospects.  The future implementation or modification of greenhouse gases regulations, whether to meet the limits required by the Kyoto Protocol, the Copenhagen Accord or as otherwise determined, could have a material impact on the nature of oil and natural gas operations, including those of the Corporation.  Given the evolving nature of the debate related to climate change and the control of greenhouse gases and resulting requirements, it is not possible to predict the impact on the Corporation and its operations and financial condition.



The direct or indirect costs of these regulations may have a material adverse effect on the Corporation's business, financial condition, results of operations and prospects.



Variations in foreign exchange rates and interest rates

World oil and gas prices are quoted in United States dollars and the price received by Canadian producers is therefore affected by the Canadian/U.S. dollar exchange rate, which will fluctuate over time.  In recent years, the Canadian dollar has increased materially in value against the United States dollar.  Material increases in the value of the Canadian dollar negatively impact the Corporation's production revenues. Future Canadian/United States exchange rates could accordingly impact the future value of the Corporation's reserves as determined by independent evaluators.



To the extent that the Corporation engages in risk management activities related to foreign exchange rates, there is a credit risk associated with counterparties with which the Corporation may contract.



An increase in interest rates could result in a increase in the amount the Corporation pays to service debt, which could negatively impact the market price of the Common Shares.



Additional funding requirements

The Corporation's cash flow from its reserves may not be sufficient to fund its ongoing activities at all times.  From time to time, the Corporation may require additional financing in order to carry out its oil and gas acquisition, exploration and development activities.  Failure to obtain such financing on a timely basis could cause the Corporation to forfeit its interest in certain properties, miss certain acquisition opportunities and reduce or terminate its operations.  If the Corporation's revenues from its reserves decrease as a result of lower oil and natural gas prices or otherwise, it will affect the Corporation's ability to expend the necessary capital to replace its reserves or to maintain its production.  If the Corporation's cash flow from operations is not sufficient to satisfy its capital expenditure requirements, there can be no assurance that additional debt or equity financing will be available to meet these requirements or, if available, on terms acceptable to the Corporation.  Continued uncertainty in domestic and international credit markets could materially affect the Corporation's ability to access sufficient capital for its capital expenditures and acquisitions, and as a result, may have a material adverse effect on the Corporation's ability to execute its business strategy and on its business, financial condition, results of operations and prospects.



Issuance of debt

From time to time the Corporation may enter into transactions to acquire assets or the shares of other organizations.  These transactions may be financed in whole or in part with debt, which may increase the Corporation's debt levels
above industry standards for oil and natural gas companies of similar size.  Depending on future exploration and development plans, the Corporation may require additional equity and/or debt financing that may not be available or, if available, may not be available on favourable terms.  Neither the Corporation's articles nor its by-laws limit the amount of indebtedness that the Corporation may incur.  The level of the Corporation's indebtedness from time to time, could impair the Corporation's ability to obtain additional financing on a timely basis to take advantage of business opportunities that may arise.





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Availability of drilling equipment and access

Oil and natural gas exploration and development activities are dependent on the availability of drilling and related equipment (typically leased from third parties) in the particular areas where such activities will be conducted.  Demand for such limited equipment or access restrictions may affect the availability of such equipment to the Corporation and may delay exploration and development activities.



Title to assets

Although title reviews may be conducted prior to the purchase of oil and natural gas producing properties or the commencement of drilling wells, such reviews do not guarantee or certify that an unforeseen defect in the chain of title will not arise to defeat the Corporation's claim which may have a material adverse effect on the Corporation's business, financial condition, results of operations and prospects.



Reserve estimates

There are numerous uncertainties inherent in estimating quantities of oil, natural gas and natural gas liquids reserves and the future cash flows attributed to such reserves.  The reserve and associated cash flow information set forth herein are estimates only.  In general, estimates of economically recoverable oil and natural gas reserves and the future net cash flows therefrom are based upon a number of variable factors and assumptions, such as historical production from the properties, production rates, ultimate reserve recovery, timing and amount of capital expenditures, marketability of oil and gas, royalty rates, the assumed effects of regulation by governmental agencies and future operating costs, all of which may vary materially from actual results.  For those reasons, estimates of the economically recoverable oil and natural gas reserves attributable to any particular group of properties, classification of such reserves based on risk of recovery and estimates of future net revenues associated with reserves prepared by different engineers, or by the same engineers at different times, may vary.  The Corporation's actual production, revenues, taxes and development and operating expenditures with respect to its reserves will vary from estimates thereof and such variations could be material.



Estimates of proved reserves that may be developed and produced in the future are often based upon volumetric calculations and upon analogy to similar types of reserves rather than actual production history.  Recovery factors and drainage areas were estimated by experience and analogy to similar producing pools.  Estimates based on these methods are generally less reliable than those based on actual production history.  Subsequent evaluation of the same reserves based upon production history and production practices will result in variations in the estimated reserves and such variations could be material.



In accordance with applicable securities laws, the Corporation's independent reserves evaluator has used forecast prices and costs in estimating the reserves and future net cash flows as summarized herein.  Actual future net cash flows will be affected by other factors, such as actual production levels, supply and demand for oil and natural gas, curtailments or increases in consumption by oil and natural gas purchasers, changes in governmental regulation or taxation and the impact of inflation on costs.



Actual production and cash flows derived from the Corporation's oil and gas reserves will vary from the estimates contained in the reserve evaluation, and such variations could be material.  The reserve evaluation is based in part on the assumed success of activities the Corporation intends to undertake in future years.  The reserves and estimated cash flows to be derived therefrom contained in the reserve evaluation will be reduced to the extent that such activities do not achieve the level of success assumed in the reserve evaluation.  The reserve evaluation is effective as of a specific effective date, and has not been updated and thus does not reflect changes in the Corporation's reserves since that date.



Insurance

The Corporation's involvement in the exploration for and development of oil and natural gas properties may result in the Corporation becoming subject to liability for pollution, blow outs, leaks of sour natural gas, property damage, personal injury or other hazards.  Although the Corporation maintains insurance in accordance with industry standards to address certain of these risks, such insurance has limitations on liability and may not be sufficient to cover the full extent of such liabilities.  In addition, such risks are not, in all circumstances, insurable or, in certain circumstances, the
Corporation may elect not to obtain insurance to deal with specific risks due to the high premiums associated with such insurance or other reasons.  The payment of any uninsured liabilities would reduce the funds available to the Corporation.  The occurrence of a significant event that the Corporation is not fully insured against, or the insolvency of the insurer of such event, may have a material adverse effect on the Corporation's business, financial condition, results of operations and prospects.





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Geo-political risks

The marketability and price of oil and natural gas that may be acquired or discovered by the Corporation is and will continue to be affected by political events throughout the world that cause disruptions in the supply of oil and natural gas.  Conflicts, or conversely peaceful developments, arising in the Middle-East, and other areas of the world, have an impact on the price of oil and natural gas.  Any particular event could result in a material decline in prices and therefore result in a reduction of the Corporation's net production revenue.



In addition, the Corporation's oil and natural gas properties, wells and facilities could be subject to a terrorist attack.  If any of the Corporation's properties, wells or facilities are the subject of terrorist attack it may have a material adverse effect on the Corporation's business, financial condition, results of operations and prospects.  The Corporation will not have insurance to protect against the risk from terrorism.



Management of growth

The Corporation may be subject to growth-related risks including capacity constraints and pressure on its internal systems and controls.  The ability of the Corporation to manage growth effectively will require it to continue to implement and improve its operational and financial systems and to expand, train and manage its employee base.  The inability of the Corporation to deal with this growth may have a material adverse effect on the Corporation's business, financial condition, results of operations and prospects.



Expiration of licenses and leases

The Corporation's properties are held in the form of licences and leases and working interests in licences and leases.  If the Corporation or the holder of the licence or lease fails to meet the specific requirement of a licence or lease, the licence or lease may terminate or expire.  There can be no assurance that any of the obligations required to maintain each licence or lease will be met.  The termination or expiration of the Corporation's licences or leases or the working interests relating to a licence or lease may have a material adverse effect on the Corporation's business, financial condition, results of operations and prospects.



Cyclical and seasonal impact on industry

The Corporation'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 Corporation's financial condition.



The level of activity in the Canadian oil and gas industry is influenced by seasonal weather patterns.  Wet weather and spring thaw may make the ground unstable.  Consequently, municipalities and provincial transportation departments enforce road bans that restrict the movement of rigs and other heavy equipment, thereby reducing activity levels.  Also, certain oil and gas producing areas are located in areas that are inaccessible other than during the winter months because the ground surrounding the sites in these areas consists of swampy terrain.  Seasonal factors and unexpected weather patterns may lead to declines in exploration and production activity which could impact the production and future revenues of the Corporation. In addition high demand for equipment in winter months for areas limited to winter access could result in increased costs and the inability to execute the Corporation's desired exploration and development programs.



Third party credit risk

The Corporation may be exposed to third party credit risk through its contractual arrangements with its current or future joint venture partners, marketers of its petroleum and natural gas production, commodity price and currency hedge contract counterparties, and other parties.  In the event such entities fail to meet their contractual obligations to the Corporation, such failures may have a material adverse effect on the Corporation's business, financial condition, results of operations and prospects.  In addition, poor credit conditions in the industry and of joint venture partners may impact a joint venture partner's willingness to participate in the Corporation's ongoing capital program, potentially delaying the program and the results of such program until the Corporation finds a suitable alternative partner.







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Conflicts of interest

Certain directors of the Corporation are also directors of other oil and gas companies and as such may, in certain circumstances, have a conflict of interest requiring them to abstain from certain decisions.  Conflicts, if any, will be subject to the procedures and remedies of the Alberta Business Corporations Act.



Reliance on key personnel

The Corporation's success depends in large measure on certain key personnel.  The loss of the services of such key personnel may have a material adverse effect on the Corporation's business, financial condition, results of operations and prospects.  The contributions of the existing management team to the immediate and near term operations of the Corporation are likely to be of central importance.  In addition, the competition for qualified personnel in the oil and natural gas industry is intense and there can be no assurance that the Corporation will be able to continue to attract and retain all personnel necessary for the development and operation of its business.  Investors must rely upon the ability, expertise, judgment, discretion, integrity and good faith of the management of the Administrator.



Operations in other jurisdictions and other business activities

Our operations and the expertise of our management are currently focused on conventional shallow and unconventional tight gas production and development in the Western Canadian Sedimentary Basin.  In the future, we may acquire oil and gas properties outside this geographic area.  In addition, the Articles of Incorporation does not limit the activities of the Corporation to oil and gas production and development, and the Corporation 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, increase the exposure to one or more of the present risk factors, which may result in future operational and financial conditions of the Corporation being adversely affected.  In either case, our future operational and financial conditions could be materially adversely affected.



Lender limitations on dividends on common shares

Under the terms of the credit facility with our lenders, if the lenders determine that our borrowing base under the facility has been exceeded by the amount loaned and assuming there is not a demand for repayment we will be precluded from paying dividends until our borrowing base no longer is in a shortfall position.  Our lenders may also restrict our ability to pay dividends when we are in breach or default of agreements with the lenders.



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



Dilution

To maintain or expand our natural gas reserves we will need to finance capital expenditures and property acquisitions.  Consequently, you may suffer dilution as a result of any future offering of common shares or securities convertible into common shares.



Generally accepted accounting principles ("GAAP")

GAAP requires that management apply certain accounting policies and make certain estimates and assumptions that affect reported amounts in our consolidated financial statements.  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 unfavourably by the market and result in an inability to borrow funds and/or may result in a decline in the trading price of the Corporations common shares.  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.



Permitted investments



We may invest in certain permitted investments of which the market value may fluctuate.  For example, the prices of Canadian government securities, bankers' acceptances and commercial paper react to economic developments and changes in interest rates.  Commercial paper is also subject to issuer credit risk.  Other permitted investments in energy-related entities will be subject to the general risks of investing in equity securities.  These include the risks that the financial condition of issuers may become impaired or that the energy sector may suffer a market downturn.  Securities markets in general are affected by a variety of factors including: governmental, environmental and regulatory policies;
inflation and interest rates; economic cycles; and global, regional and national events.  The value of the Common Shares could be affected by adverse changes in the market values of permitted investments.





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Changes in dividends

The board of directors of the Corporation assess the dividend on a monthly basis based on cash flow projections which incorporate Perpetual's base production forecasts, current hedges and physical forward natural gas sales, the forward market for natural gas prices, and the Corporation's capital spending program and projected production additions. Future dividends are subject to change as dictated by changes in commodity price markets, operations and future business development opportunities and may vary materially from previous dividends.



Operational matters

The Corporation'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 Corporation'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.  Perpetual 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 therefrom, is largely dependent upon economic variables and the ability of the operator of the property.  Operating costs on most properties have increased 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 Corporation to certain properties.  A reduction in dividends on Common Shares could result in such circumstances.



Expansion of operations

The operations and expertise of management of the Corporation are currently focused on natural gas production and development in the Western Canadian Sedimentary Basin.  In the future, the Corporation may acquire oil and gas properties outside this geographic area.  In addition, the Articles of Incorporation does not limit the activities of the Corporation to oil and gas production and development, and the Corporation 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, increase the exposure to one or more of the present risk factors, which may result in future operational and financial conditions of the Corporation being adversely affected.



Acquisitions

The price paid for asset acquisitions is based on the Corporation's internal assessment of the reserves and future production potential adjusted for risk. These assessments include a number of material assumptions regarding such factors as recoverability and marketability of oil and natural gas, future prices of oil and natural gas, and operating costs, future capital expenditures and royalties and other government levies which will be imposed over the producing life of the reserves.  Many of these factors are subject to change and are beyond the control of the operators of the working interests, management and the Corporation.  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 dividends and as such the value of the Common Shares.  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 funds flows and dividends to Shareholders.







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Net asset value

The net asset value of the assets of the Corporation 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 Common Shares from time to time are also determined by a number of factors that are beyond the control of management and such trading prices may vary from the net asset value of the Corporations assets.



Financial instruments

The nature of Perpetual's operations results in exposure to fluctuations in commodity prices.  The Corporation will monitor and, when appropriate, utilize derivative financial instruments and physical delivery contracts to mitigate its exposure to these risks.  Perpetual 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 Corporation may enter into risk management 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 Corporation will receive a minimum price for natural gas production;

·

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

·

selling call options to third parties, giving them the right to purchase natural gas from the Corporation at a specified price in future periods in exchange for an upfront cash payment to Perpetual;

·

entering into fixed price contract for natural gas production; and

·

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



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



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



·

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

·

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

·

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



Renegotiation or termination of contracts

As at the date hereof, the Corporation 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.



Environmental considerations

Compliance with health, safety and environmental laws and regulations could materially increase the Corporation's costs.  Perpetual 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 Corporations products or wastes will be handled or disposed.



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





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In addition, increasingly strict environmental requirements may affect product specifications and operational practices.  Future expenditures to meet such specifications could have a material adverse effect on the Corporation's operations or financial condition.  Any abandonment costs Perpetual incurs will reduce cash available for dividends to Shareholders and other uses.



The Corporation 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 Corporation believes in well abandonment and site restoration in a timely manner to ensure minimal damage to the environment and lower overall costs to the Corporation.



FORWARD-LOOKING INFORMATION



Certain statements contained in this MD&A constitute forward-looking information and statements within the meaning of applicable securities laws.  This information and these statements relate to future events or to our future performance.  All statements other than statements of historical fact may be forward-looking statements.  The use of any of the words
"anticipate", "continue", "estimate", "expect", "may", "will", "project", "should",
"believe", "outlook", "guidance", "objective", "plans", "intends", "targeting", "could",
"potential", "outlook", "strategy" and any similar expressions are intended to identify forward-looking information and statements.



In particular, but without limiting the foregoing, this MD&A contains forward-looking information and statements pertaining to the following: the quantity and recoverability of Perpetuals reserves; the timing and amount of future production; future prices as well as supply and demand for natural gas and oil; the existence, operations and strategy of the commodity price risk management program; the approximate amount of forward sales and hedging to be employed, and the value of financial forward natural gas contracts; funds flow sensitivities to commodity price, production, foreign exchange and interest rate changes; operating, G&A, and other expenses; cash dividends, and the funding and tax treatment thereof; the costs and timing of future abandonment and reclamation, asset retirement and environmental obligations; the use of exploration and development activity, prudent asset management, and acquisitions to sustain, replace or add to reserves and production or expand the Corporationss asset base; expected costs relating to the Corporations gas storage project; anticipated future capacity of the Corporations gas storage facility; the timing of receipt of escrowed funds; the Corporations acquisition strategy and the existence of acquisition opportunities, the criteria to be considered in connection therewith and the benefits to be derived therefrom; Perpetuals ability to benefit from the combination of growth opportunities and the ability to grow through the capital markets; expected book value and related tax value of the Corporations assets and prospect inventory and estimates of net asset value; funds flow; ability to fund dividends and exploration and development; our corporate strategy; expectations regarding Perpetuals access to  capital to fund its acquisition, exploration and development activities; the transition to IFRS and its impact on the Corporations financial results; expected realization of gas over bitumen royalty adjustments; future income tax and its effect on funds flow and dividends; intentions with respect to preservation of tax pools of and taxes payable by the Corporation; funding of and anticipated results from capital expenditure programs; renewal of and borrowing costs associated with the credit facility; future debt levels, financial capacity, liquidity and capital resources; future contractual commitments; drilling, completion, facilities and construction plans, and the effect thereof; the impact of Canadian federal and provincial governmental regulation on the Corporation relative to other issuers; Crown royalty rates; Perpetuals treatment under governmental regulatory regimes; business strategies and plans of management, including future changes in the structure of business operations; and the reliance on third parties in the industry to develop and expand Perpetuals assets and operations.



The forward-looking information and statements contained in this MD&A reflect several material factors and expectations and assumptions of the Corporation including, without limitation, that Perpetual will conduct its operations in a manner consistent with its expectations and, where applicable, consistent with past practice; the general continuance of current or, where applicable, assumed industry conditions; the continuance of existing, and in certain circumstances, the implementation of proposed tax, royalty and regulatory regimes; the ability of Perpetual to obtain equipment, services, and supplies in a timely manner to carry out its activities; the accuracy of the estimates of Perpetuals reserve and resource volumes; the timely receipt of required regulatory approvals; certain commodity price and other cost assumptions; the timing and costs of storage facility and pipeline construction and expansion and the ability to secure adequate product transportation; the continued availability of adequate debt and/or equity financing and funds flow to fund the Corporations capital and operating requirements as needed; and the extent of Perpetuals liabilities.



The Corporation believes the material factors, expectations and assumptions reflected in the forward-looking information and statements are reasonable but no assurance can be given that these factors, expectations and assumptions will prove to be correct. The forward-looking information and statements included in this MD&A are not guarantees of future performance and should not be unduly relied upon. Such information and statements involve known and unknown risks, uncertainties and other factors that may cause actual results or events to differ materially from those anticipated in such forward-looking information or statements including, without limitation: volatility in market prices for oil and natural gas products; supply and demand regarding the Perpetuals products; risks inherent in
Perpetuals operations, such as production declines, unexpected results, geological, technical, or drilling and process problems; unanticipated operating events that can reduce production or cause production to be shut-in or delayed; changes in exploration or development plans by Perpetual or by third party operators of Perpetuals properties; reliance on industry partners; uncertainties or inaccuracies associated with estimating reserves volumes; competition for, among other things; capital, acquisitions of reserves, undeveloped lands, skilled personnel, equipment for drilling, completions, facilities and pipeline construction and maintenance; increased costs; incorrect assessments of the value of acquisitions; increased debt levels or debt service requirements; industry conditions including fluctuations in the price of natural gas and related commodities; royalties payable in respect of Perpetuals production; governmental regulation of the oil and gas industry, including environmental regulation; fluctuation in foreign exchange or interest rates; the need to obtain required approvals from regulatory authorities; changes in laws applicable to the Corporation, royalty rates, or other regulatory matters; general economic conditions in Canada, the United States and globally; stock market volatility and market valuations; limited, unfavourable, or a lack of access to capital markets, and certain other risks detailed from time to time in Perpetuals public disclosure documents.  The foregoing list of risk factors should not be considered exhaustive.



The forward-looking information and statements contained in this MD&A speak only as of the date of this MD&A, and none of the Corporation or its subsidiaries assumes any obligation to publicly update or revise them to reflect new events or circumstances, unless expressly required to do so by applicable securities laws.



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





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