|                                     |  |  |  |  | 
|------------------------------------ |  |  |  |  | 
|ENTERRA ENERGY TRUST                 |  |  |  |  | 
|MANAGEMENTS DISCUSSION AND ANALYSIS |  |  | 



The following is Managements Discussion and Analysis (MD&A) of Enterra Energy Trust (the Trust or Enterra) for the year ended December 31, 2006.  This MD&A should be read in conjunction with the consolidated financial statements, together with the accompanying notes, of the Trust for the year ended December 31, 2006.  All amounts are stated in Canadian dollars and are prepared in accordance with Canadian Generally Accepted Accounting Principles (GAAP) except where otherwise indicated.  This MD&A was written as of March 23, 2007.



SPECIAL NOTE REGARDING FORWARD-LOOKING STATEMENTS



This MD&A includes forward-looking statements.  All statements other than statements of historical facts contained in this MD&A, including statements regarding the Trusts future financial position, business strategy and plans and objectives of management for future operations, are forward-looking statements.  The words believe, may, will, estimate, continue, anticipate, intend, should, plan, expect and similar expressions, as they relate to the Trust, are intended to identify forward-looking statements.  The Trust has based these forward-looking statements largely on the Trusts current expectations and projections about future events and financial trends that the Trust believes may affect its financial condition, results of operations, business strategy and financial needs.  These forward-looking statements are subject to a number of risks, uncertainties and assumptions as described elsewhere in this MD&A.



Other sections of this MD&A may include additional factors that could adversely affect the Trusts business and financial performance.  Moreover, the Trust operates in a very competitive and rapidly changing environment.  New risk factors emerge from time to time and it is not possible for management to predict all risk factors, nor can the Trust assess the impact of all factors on the Trusts business or the extent to which any factor, or combination of factors, may cause actual results to differ materially from those contained in any forward-looking statements.



The Trust undertakes no obligation, except as required by securities law, to update publicly or revise any forward-looking statements.  You should not rely upon forward-looking statements as predictions of future events or performance.  The Trust cannot assure you that the events and circumstances reflected in the forward-looking statements will be achieved or occur.  Although the Trust believes that the expectations reflected in the forward-looking statements are reasonable, the Trust cannot guarantee future results, levels of activity, performance or achievements.



SPECIAL NOTE REGARDING NON-GAAP TERMS



This document contains the term funds from operations, which is a non-GAAP term.  The Trust uses this measure to help evaluate its performance.  The Trust considers it a key measure for the ability of the Trust to repay debt, make distributions to unitholders and to fund future growth through capital investment.  The term should not be considered as an alternative to, or more meaningful than, cash provided by operating activities as determined in accordance with Canadian GAAP as an indicator of the Trusts performance.  Funds from operations, as determined by the Trust may not be comparable to that reported by other companies.  The reconciliation for funds from operations to cash provided by operating activities can be found in the non-GAAP financial measures section of this MD&A.





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CERTAIN FINANCIAL REPORTING MEASURES



Natural gas volumes recorded in thousand cubic feet (mcf) are converted to barrels of oil equivalent (boe) using the ratio of six (6) thousand cubic feet to one (1) barrel of oil (bbl).  Boes may be misleading, particularly if used in isolation.  A boe conversion ratio of 6 mcf:1 bbl is based on an energy equivalent conversion method primarily applicable at the burner tip and does not represent a value equivalent at the wellhead.



OVERVIEW AND STRATEGY



Enterra is a Canadian oil and gas trust with trust units listed on the Toronto Stock Exchange (ENT.UN) and the New York Stock Exchange (ENT).  The Trusts head office is located in Calgary, Alberta and its United States office is located in Carney, Oklahoma.



The Trusts portfolio of crude oil, natural gas liquids and natural gas interests is geographically diversified and is balanced between natural gas and liquids production.  The Trusts properties are located principally in Alberta, British Columbia and Oklahoma with average production for 2006 of 12,352 boe/day, which was comprised of approximately 59% natural gas and 41% crude oil and natural gas liquids.



In July 2006, the Trust announced that it would strive to make monthly cash distributions to its unitholders based on a target payout ratio range of 60% to 70% of funds from operations.  The Trusts distributions in 2006 were approximately 105% of funds from operations, exceeding that target payout range, in part due to a higher level of distributions paid in the first seven months of 2006 and in part due to a lower commodity price environment during the later part of the year.  Adjusting for the higher level of distributions paid in the first seven months of 2006 compared to those paid in August to December, the payout ratio would have been 82%.  While the Trust believes it is important to deliver sustainable and predictable distributions to its unitholders, all future distributions will be determined by the board of directors (Board) of Enterra Energy Corp., as administrator of the Trust, based on the circumstances as they exist at that time and will be subject to a number of factors, many of which are beyond the Trusts control.  These factors include unforeseen events which impact the Trusts production levels, the prices received for that production and the cost structure associated with the Trusts operations.  The Trust will continue to monitor its payout ratio to ensure that over the medium and long term, the ratio remains in the target range.



Enterra is structured as a trust rather than a corporation to provide a more tax-efficient means to distribute funds to its unitholders under current Canadian tax laws.  On October 31, 2006 the Canadian Minister of Finance announced certain proposed changes to the taxation of publicly traded trusts (see Implications of Recent Tax Proposals by Canadian Minister of Finance below). If enacted, the changes will result in the Trust being subject to taxation in a manner similar to corporations.



All of the entities shown above that are below "Enterra Energy Trust" are, direct or indirect, wholly-owned subsidiaries of the Trust.



ENTERRAS GOAL, BUSINESS STRATEGY AND OPERATING PRINCIPLES



Enterras goal is to generate returns for its unitholders through a combination of cash distributions that are predictable, sustainable and increase over time, and capital appreciation from steady and consistent increases in reserves, production and funds from operations per trust unit.  To achieve that goal the Trust has adopted a three-pronged strategy as follows.



Organic Growth



The Trust currently targets a distribution level of 60% to 70% of funds from operations to unitholders and to invest the balance in the development of the large portfolio of lower-risk opportunities it has identified within its existing asset base.  The individual nature and number of the opportunities varies across the Trusts properties, but in aggregate the Trust believes they offer a means of adding reserves and production on a basis that will be accretive to unitholders and at a pace that generally is within the Trusts control.  As a result, the Trust believes that investing in such projects is in the long-term interest of unitholders.









Accretive Acquisitions



Corporate and property acquisitions are an effective means of consolidating assets, improving efficiencies in existing core areas or adding new core areas.  The Trust intends to be pro-active, focused and disciplined in its approach to such acquisitions.  Generally, the Trust seeks to make acquisitions that:



·

are accretive to funds from operations per trust unit and accretive to at least one of reserves or production per trust unit;

·

add to the Trusts portfolio of infill and step-out drilling opportunities, which the Trust believes to be lower-risk in nature;

·

consolidate the Trusts position within an existing core area or create a new core area;

·

leverage the Trusts existing expertise;

·

have high working interests and operatorship; and

·

maintain a reasonable balance among oil and natural gas production, and geographic diversification.



Strategic Partnerships



The Trust actively seeks to align itself with industry partners that provide access to projects that otherwise may not be available due to the nature or degree of risk involved or due to the expertise required to properly capitalize on the opportunity.  The basis of the partnerships will vary, but may involve a farmout of existing assets or a joint acquisition with a partner followed by a farmout or joint venture.  The Trusts objectives in structuring these relationships include:



·

providing controlled exposure to higher-risk, higher-return opportunities;

·

aligning with management teams or individuals with specific experience, proven skills or a demonstrated competitive advantage;

·

adding reserves and production over an extended period of time at minimal cost and risk to Enterra and, as a result, providing a source of funds for future distributions; and

·

creating opportunities to purchase at an attractive cost, assets from a partner once the risk is better defined or once the necessary expertise to exploit the opportunity has been acquired by the Trust.



In pursuing the Trusts growth strategies Enterra seeks to manage the risk to unitholders by following a number of operating principles.  These principles are intended to maximize flexibility and ability to capitalize on opportunities, while reducing the volatility and increasing the predictability of distributions.  These operating principles include:



·

diversifying the source of production geographically so that Enterra is less dependent on one market for production or one area for future development;

·

maintaining a reasonable balance among crude oil production, natural gas liquids production and natural gas production, so that Enterra is less vulnerable to short term price fluctuations for any single commodity;

·

seeking high working interests, operatorship, and ownership of associated infrastructure, so that the Trust is better able to control the pace and timing of capital expenditures;

·

maintaining a multi-year inventory of lower-risk development projects, so that the Trust is able to support its strategy of reinvesting in organic growth opportunities;

·

moving towards a conservative balance sheet with a target ratio of total net debt (defined as bank indebtedness less current assets plus current liabilities) to funds from operations of 1:1, so that Enterra is positioned to capitalize on acquisition opportunities when they arise; and

·

hedging up to 50% of projected gross production up to 24 months in advance using price collars and avoiding fixed price sales, so that the Trust is less exposed to significant short-term swings in commodity prices, but has protected a base level of distributions and preserved a degree of upside.







ACQUISITION HIGHLIGHT



During the first six months of 2006, the Trust completed the acquisition of oil and natural gas producing assets located in Oklahoma (Oklahoma Assets).  The acquisition was completed in four tranches.  Volumes for each closing were based on production deliverability.  The first closing occurred on January 18, 2006 and represented approximately 1,300 boe/day of deliverability.  The second closing occurred on March 21, 2006 and represented approximately 3,700 boe/day of deliverability.  The final two closings occurred on April 4, 2006 and April 18, 2006 and represented in total approximately 1,300 boe/day of deliverability.  In the four week period following the fourth closing, production volumes were 5,703 boe/day.  The aggregate net purchase price of $307.6 million was paid for through the issuance of 5,685,028 trust units valued at $116.5 million, cash of $181.0 million, including $8.9 million that remains unpaid at December 31, 2006, and closing costs of $10.0 million.



IMPLICATIONS OF RECENT TAX PROPOSALS BY THE CANADIAN MINISTER OF FINANCE



On October 31, 2006 the Canadian Minister of Finance (the "Finance Minister") announced a proposal to apply a tax at the trust level on distributions of certain income from publicly-traded mutual fund trusts and other specified investment flow-through (SIFT) entities at rates of tax comparable to the combined federal and provincial corporate tax and to treat such distributions as dividends to the unitholders. The Finance Minister said existing trusts would have a four-year transition period and would not be subject to the new rules until 2011. However, the proposals also provide that, while there is no intention to prevent "normal growth" during the transitional period, any "undue expansion" could result in the transition period being "revisited", presumably with the loss of the benefit to the Trust of that transition period.  As a result, the adverse tax consequences resulting from the proposals could be realized sooner than 2011.  On December 15, 2006 the Finance Minister provided additional guidance clarifying what will be deemed to be normal growth. Specifically, the transition period will not be revisited for any SIFT whose equity capital grows as a result of issuances of new equity, in any certain intervening periods, by an amount that does not exceed the greater of $50 million and an objective safe harbour amount. The safe harbour amount will be measured by reference to a SIFTs market capitalization as of the end of trading on October 31, 2006 by measuring the value of the SIFTs issued and outstanding publicly-traded units and excluding options or other interests that were convertible into units of the SIFT.  For the period from November 1, 2006 to the end of 2007, a SIFTs safe harbour will be 40% of that October 31, 2007 benchmark. Thereafter, for each calendar year 2008 through 2010 the safe harbour will be 20% of that benchmark. The annual safe harbour limits are cumulative but the $50 million amounts are not. New equity for purposes of the safe harbour will include issuances of units and debt that is convertible into units, but will not include new equity raised to replace debt that was outstanding as of October 31, 2006, or units acquired through a right existing as of October 31, 2006.



As of October 31, 2006 the Trust had a benchmark market capitalization of approximately $408 million.  As a result, assuming the proposals are enacted as proposed, the safe harbour limit for the Trust from November 1, 2006 to the end of 2007 is 40% of the benchmark or approximately $163 million, and 20% of the benchmark or approximately $82 million for each calendar year 2008 through 2010.  On November 21, 2006 the Trust issued trust units and debentures for total gross proceeds of $178.3 million. The net proceeds of the issue combined with drawings under the Trusts Syndicated Credit Facilities were used to repay in full bridge loans that had been outstanding at October 31, 2006. As a result, it does not appear that the issuances will be considered new equity for purposes of the safe harbour amounts.



If the proposals are ultimately enacted, the implementation of such proposals is expected to result in adverse tax consequences to the Trust and certain of its unitholders (including most particularly investors that are tax exempt or non-residents of Canada) which could be material and may impact cash distributions from the Trust and the value of its units.  In the absence of legislation implementing the proposals, the implications of the proposals are difficult to evaluate and no assurance can be provided as to the extent and timing of their application to Enterra.  The Trust continues to research its position based on the proposed rules and is waiting for the final legislation.



OVERALL PERFORMANCE



Increased natural gas sales volumes, resulting from the acquisition of High Point Resources Inc. (High Point) effective August 17, 2005 and the inclusion of the acquisition of the Oklahoma Assets as of their respective closing dates during Q1 and Q2 2006, positively impacted the Trusts 2006 operating and financial results.



Average production increased by 60% to 12,352 boe/day in 2006 from 7,741 boe/day in 2005. The Trust exited the year with sales volumes of approximately 12,442 boe/day, 34% higher than the 2005 exit rate of 9,282 boe/day.



The positive impact of the year-over-year increase in production volumes was partially offset by a number of factors including lower natural gas prices, and higher G&A and interest expenses.  Cash G&A expenses increased by 12% in 2006 to an average of $3.80/boe from $3.40/boe in 2005.  Interest expenses were also up significantly, reflecting the high cost of the bridge loan facilities arranged to finance the purchase of the Oklahoma Assets, rising 467% to $26.7 million in 2006 compared to $4.7 million the prior year. As a result, funds from operations increased by 22% to $86.1 million in 2006 from $70.5 million in 2005.



Proved and probable reserves increased by 44% from the end of 2005 to the end of 2006 largely reflecting the acquisition of the Oklahoma Assets during the first half of 2006.  However, higher forecast operating costs, lower forecast commodity prices and to a lesser extent poorer than expected new well performance resulted in downward revision of earlier reserve estimates in both Canada and U.S.  As a result, an after-tax write-down of $44.5 million in the carrying value of property plant and equipment was necessary. The write-down represents a significant portion of the net loss for the year of $64.2 million compared to net earnings of $1.0 million in 2005. On a per unit basis, the Trust realized a net loss of $1.46/unit compared to net earnings of $0.03/unit in 2005.



Over the course of 2006, the Trust distributed a total of $90.5 million to unitholders or an average of US$1.86/unit, representing increases of 37% and nil% respectively compared to total distributions of $66.2 million and average distributions of US$1.86/unit in 2005.



|                                                                                                |                                 |           |                          |           |          |         
|----------------------------------------------------------------------------------------------- | ------------------------------- | --------- | ------------------------ | --------- | -------- | --------
|SUMMARIZED FINANCIAL AND OPERATIONAL DATA(in thousands except for volumes and per unit amounts)
|                                                                                                | Three months ended
December 31, |           | Years ended
December 31, |          
|2006                                                                                            | 2005                            | Change    | 2006                     | 2005      | Change  
|                                                                                                |                                
|Revenues                                                                                        | $56,043                         | $50,602   | 11%                      | $244,408  | $158,097 | 55%     
|Average sales (boe/day)                                                                         | 11,905                          | 9,883     | 20%                      | 12,352    | 7,741    | 60%     
|Exit sales rate (boe/day)                                                                       | 12,442                          | 9,282     | 34%                      | 12,442    | 9,282    | 34%     
|Cash provided by operating activities                                                           | $26,163                         | $19,575   | 34%                      | $64,485   | $68,120  | (5%)    
|Funds from operations (1)                                                                       | $9,558                          | $19,519   | (51%)                    | $86,117   | $70,545  | 22%     
|Net earnings (loss)                                                                             | $(69,189)                       | $(12,937) | 435%                     | $(64,239) | $970     | (6,723%)
|Net earnings (loss) per  unit - basic                                                           | $(1.40)                         | $(0.37)   | 278%                     | $(1.46)   | $0.03    | (4,967%)
|Weighted average number of  units outstanding  basic                                           | 49,415                          | 35,358    | 40%                      | 44,142    | 29,534   | 49%     
|Average price per barrel of oil                                                                 | $55.64                          | $56.83    | (2%)                     | $62.13    | $58.47   | 6%      
|Average price per mcf of natural gas                                                            | $7.91                           | $8.82     | (10%)                    | $7.53     | $8.40    | (10%)   
|Production expenses per boe                                                                     | $16.04                          | $12.26    | 31%                      | $11.17    | $11.55   | (3%)    

(1)Funds from operationsis a non-GAAP financial measure.  See non-GAAP financial measures section of the MD&A for a reconciliation of this measure.



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|                                                                   |           |          |          |         
|------------------------------------------------------------------ | --------- | -------- | -------- | --------
|SELECT FINANCIAL INFORMATION(in thousands except per unit amounts)
|                                                                   |           | 2006     | 2005     | 2004    
|Revenues                                                           |           | $244,408 | $158,097 | $108,293
|Net earnings (loss)                                                | $(64,239) | $970     | $14,027 
|Net earnings (loss) per unit                                       |           |          |         
|                                                                   | Basic     | $(1.46)  | $0.03    | $0.62   
|                                                                   | Diluted   | $(1.46)  | $0.03    | $0.62   
|Total assets                                                       |           | $795,366 | $611,543 | $221,128
|Total long term liabilities                                        | $147,761  | $126,322 | $39,544 
|Distributions declared                                             | $90,698   | $69,496  | $42,361 
|Distributions declared per unit (US$)                              | $1.80     | $1.90    | $1.66   



QUARTERLY FINANCIAL INFORMATION



|                                                                          |           |          |           |          |           |         |         |        
|------------------------------------------------------------------------- | --------- | -------- | --------- | -------- | --------- | ------- | ------- | -------
|Quarterly Financial Information(in thousands except for per unit amounts)
|                                                                          | 2006      | 2005    
|                                                                          | Q4        | Q3       | Q2        | Q1       | Q4        | Q3      | Q2      | Q1     
|Revenues                                                                  | $56,043   | $73,335  | $67,313   | $47,717  | $50,602   | $47,638 | $29,807 | $30,050
|Earnings (loss) before taxes and non-controlling interest                 | (101,242) | $(6,879) | $(10,579) | $(3,149) | $(28,526) | $ 7,530 | $947    | $3,757 
|Net earnings (loss)                                                       | (69,189)  | $3,000   | $(296)    | $2,248   | $(12,937) | $7,089  | $2,567  | $4,251 
|Net earnings (loss) per unit                                              |           |          |           |          |           |         |         |        
|Basic                                                                     | $(1.40)   | $0.07    | $(0.01)   | $0.06    | $(0.37)   | $0.23   | $0.10   | $0.16  
|Diluted                                                                   | $(1.40)   | $0.07    | $(0.01)   | $0.06    | $(0.37)   | $0.23   | $0.10   | $0.16  
|Distributions declared per unit  (US$)                                    | $0.36     | $0.36    | $0.54     | $0.54    | $0.52     | $0.49   | $0.46   | $0.43  



Over the last 8 quarters, the Trust has realized a steady growth of revenues.  This growth fell off slightly in Q4 2006 due to a combination of lower volumes and lower prices compared to the previous quarter.  While distributions grew steadily over the early quarters, they dropped in Q3 and Q4 2006 along with the Trusts 2006 strategy to pursue organic growth.



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RESULTS OF OPERATIONS



The Trusts average production for 2006 increased by 60% to 12,352 boe/day from 7,741 boe/day in 2005.  The increase largely reflects the acquisition of High Point in August 2005, the subsequent development of the properties, and the purchase of the Oklahoma Assets in Q1 and Q2 2006. The Trusts average production during 2006 consisted of 5,126 bbls/day of oil and natural gas liquids (NGL) and 43,358 mcf/day of natural gas, resulting in a mix of 41% oil and NGL and 59% natural gas.  As at December 31, 2006, the Trust had an exit rate of 12,442 boe/day.



Production for the fourth quarter of 2006 was also positively impacted by the acquisitions.  Volumes for the period averaged 11,905 boe/day up 20% compared to the average for Q4 2005 of 9,883 boe/day, but 9% below the average for Q3 2006 of 13,070 boe/day. Factors contributing to the reduction in Q4 versus Q3 included normal production declines, operational problems in the Desan area of North Eastern British Columbia, production declines related to increased water production in the Clair area of North Western Alberta, and operational problems in Oklahoma. The impact of the problems was mitigated by the startup late in Q4 of a deep gas well in the Ricinus area of Alberta and by some success in addressing the operational problems at Desan and in Oklahoma.  Production at the end of Q4 2006 was 5% above the average for the quarter at 12,442 boe/day.



In total in 2006, the Trust participated in the drilling of 45 (13.1 net) development wells; 28 (5.8 net) in Canada and 17 (7.3 net) in Oklahoma.  In addition, 20 (10.0 net) wells were drilled on lands that are prospective for coal bed methane owned by the Trust in Wyoming. 18 (4.3 net) of the wells in Canada and 12 (3.0 net) of the wells in Oklahoma were initiated and operated by our strategic partners under area farmout agreements that resulted in our partners paying 100% of the cost in exchange for 70% of the Trusts working interest.  Overall, the drilling in Canada and Oklahoma resulted in 34 (10.1 net) gas wells, 9 (1.5 net) oil wells, 2 (1.5 net) salt water disposal wells and an overall success rate of 100%.



Canadian Operations



Production in Canada for the year was relatively unchanged compared to 2005.  Volumes averaged 2% higher at 7,578 boe/day in 2006 compared to 7,398 boe/day in 2005.  However, the mix between commodities was more balanced reflecting the inclusion of High Point for the full year and the Trusts strategy of maintaining a reasonable balance among crude oil, natural gas liquids and natural gas production. Gas represented approximately 40% of total production in 2006 versus 25% in 2005.



Q4 2006 production in Canada was negatively impacted by operational issues at Desan and above normal production declines at Clair. Overall, volumes were down by 11% to 6,990 boe/day compared to the average for Q3 2006 of 7,491 boe/day and 24% lower than the average of 9,226 boe/day in Q4 2005. At Clair, an increase in the ratio of water to oil produced resulted in a drop in production of approximately 140 boe/day in Q4 versus Q3.  At Desan, production from several wells was reduced during the quarter due to minor and expected water production.  As a result, volumes from the area in Q4 were approximately 180 boe/day lower than in Q3. Remedial work to address the issue was undertaken in early 2007 and the production restored.  Mitigating the impact of lower production at Clair and Desan was the startup of a deep gas well at Ricinus during November.  The well has had a number of operational problems and has produced intermittently since it was completed in April 2006.  Most of those issues have now been addressed enabling the well to contribute average production during the quarter of approximately 300 boe/day. The 24% drop in Q4 2006 production compared to Q4 2005 is largely attributable to natural production declines and to several small assets dispositions that totaled approximately 250 boe/day. The 2006 exit rate for Canada was 7,287 boe/day.



Of the 28 (5.8 net) wells that were drilled in Canada during 2006, 17 (4.3 net) were drilled under the Trusts farmout to JED Oil Inc. (JED) whereby the JED paid 100% of the cost of the wells for a 70% interest.  Overall, including the wells not initiated by JED, the drilling resulted in 19 (4.3 net) gas wells and 9 (1.5 net) oil wells.





U.S. Operations



Production in the United States averaged a total of 4,774 boe/day during 2006, of which 86% was natural gas and approximately 95% was attributable to the Oklahoma Assets that were acquired during Q1 and early Q2 2006.



Q4 2006 production levels were below expectation, averaging 4,915 boe/day or 12% less than the average for Q3 2006.  The reduction in volumes reflected operational problems experienced in several project areas, including downtime due to pump failures and deferred well workovers. However, many of the problems were successfully addressed during the quarter which was reflected in the exit rate of  5,155 boe/day.



In total, the Trust participated in the drilling of 37 (17.3 net) wells in the U.S. in 2006. Of those, 17 (7.3 net) were in Oklahoma and 20 (10 net) were wells to test the economic viability of a coal bed methane project in Wyoming.  Two (1.5 net) of the wells drilled in Oklahoma were salt water disposal wells drilled by the Trust in support of the on-going development drilling program of its strategic partner, Petroflow Energy Inc. (Petroflow). While the total cost of the Trusts share of the wells was paid by the Trust, ultimately 100% of the amount plus interest will be recovered from Petroflow over a three-year period.  To the end of 2006, Petroflow had drilled 12 gas wells, including five during Q4.  Seven of the 12 wells were on production at the end of 2006. All of the wells drilled in the U.S. by or on behalf of the Trust during the year were successful.





|                                                            |                                 |        |                          |        |        |      
|----------------------------------------------------------- | ------------------------------- | ------ | ------------------------ | ------ | ------ | -----
|Production(in thousands except for volumes and percentages)
|                                                            | Three months ended
December 31, |        | Years ended
December 31, |       
|2006                                                        | 2005                            | Change | 2006                     | 2005   | Change
|Daily Sales Volumes  Average                               |                                 |        |                          |        |        |      
|Oil & NGL (bbls/day)                                        | 4,774                           | 5,762  | (17%)                    | 5,126  | 5,453  | (6%) 
|Natural gas (mcf/day)                                       | 42,788                          | 24,727 | 73%                      | 43,358 | 13,729 | 216% 
|Total (boe/day)                                             | 11,905                          | 9,883  | 21%                      | 12,352 | 7,741  | 60%  
|                                                            |                                 |        |                          |        |        |      
|Daily Sales Volumes - Exit Rate                             |                                 |        |                          |        |        |      
|Oil & NGL (bbls/day)                                        | 4,758                           | 5,476  | (13%)                    | 4,758  | 5,476  | (13%)
|Natural gas (mcf/day)                                       | 46,105                          | 22,836 | 102%                     | 46,105 | 22,836 | 102% 
|Total (boe/day)                                             | 12,442                          | 9,282  | 34%                      | 12,442 | 9,282  | 34%  
|                                                            |                                 |        |                          |        |        |      
|Sales Volumes mix by product                                |                                 |        |                          |        |        |      
|Oil & NGL                                                   | 40%                             | 58%    |                          | 41%    | 70%    |      
|Natural gas                                                 | 60%                             | 42%    |                          | 59%    | 30%    |      
|                                                            | 100%                            | 100%   |                          | 100%   | 100%   |      





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|                                                                               |                                      |        |                               |        |        | 
|------------------------------------------------------------------------------ | ------------------------------------ | ------ | ----------------------------- | ------ | ------ | 
|Production by Geographic Area(in thousands except for volumes and percentages)
|                                                                               | Three months ended
December 31, 2006 |        | Years ended
December 31, 2006 |       
|Canada                                                                         | U.S.                                 |        | Canada                        | U.S.   |       
|Daily Sales Volumes  Average                                                  |                                      |        |                               |        |        | 
|Oil & NGL (bbls/day)                                                           | 4,064                                | 710    |                               | 4,511  | 614    | 
|Natural gas (mcf/day)                                                          | 17,556                               | 25,232 |                               | 18,401 | 24,956 | 
|Total (boe/day)                                                                | 6,990                                | 4,915  |                               | 7,578  | 4,774  | 
|                                                                               |                                      |        |                               |        |        | 
|Daily Sales Volumes - Exit Rate                                                |                                      |        |                               |        |        | 
|Oil & NGL (bbls/day)                                                           | 4,008                                | 750    |                               | 4,008  | 750    | 
|Natural gas (mcf/day)                                                          | 19,676                               | 26,429 |                               | 19,676 | 26,429 | 
|Total (boe/day)                                                                | 7,287                                | 5,155  |                               | 7,287  | 5,155  | 
|                                                                               |                                      |        |                               |        |        | 
|Sales Volumes mix by product                                                   |                                      |        |                               |        |        | 
|Oil & NGL                                                                      | 58%                                  | 14%    |                               | 60%    | 13%    | 
|Natural gas                                                                    | 42%                                  | 86%    |                               | 40%    | 87%    | 
|                                                                               | 100%                                 | 100%   |                               | 100%   | 100%   | 



COMMODITY PRICING



West Texas Intermediate (WTI) is a standard benchmark for the price of oil.  WTI is expressed in US dollars per barrel (bbl).  The Trust reports the price it receives for oil in Canadian dollars per bbl.  Alberta Spot prices, represented as AECO hub pricing (AECO), is a standard benchmark for the price of natural gas in Western Canada.  AECO prices are quoted in Canadian dollars per gigajoule (GJ).  New York Mercantile Exchange (Nymex) is a standard benchmark for the price of natural gas in the United States.  Nymex prices are expressed in US dollars per million British Thermal Units (mmbtu).  To simplify comparison, both an mmbtu and a GJ are approximately equal to a mcf of gas.



Natural gas prices on the Nymex decreased by US$1.30/mmbtu or 15%, from 2005, averaging US$7.26/mmbtu in 2006.  In Canada, AECO pricing was down $2.20/GJ, or 25%, from 2005 levels, averaging $6.53/GJ. Reasons why Alberta spot prices decreased by more than NYMEX prices include the continued appreciation of the Canadian dollar against the US dollar and widening basis differentials attributable to soft natural gas storage demand.



In the fourth quarter, prices on the NYMEX were down significantly from the fourth quarter of 2005.  Prices averaged US$6.62/mmbtu in Q4 2006 compared to US$12.85/mmbtu in Q4 2005.  AECO pricing was down by 39% to $6.91/GJ compared to $11.39/GJ in Q4 2005.  The decreases in gas prices over the prior year periods reflect the exceptionally high market prices realized during the later part of 2005 due to the unusually large number of hurricanes that adversely impacted onshore and offshore gas production in the Southern U.S.



World oil prices increased significantly in 2006 compared to 2005 reaching a high in July for WTI of US$74.47/bbl. Overall in 2006 WTI averaged US$66.22/bbl, up 17% from US$56.56/bbl in 2005.  However, the potential benefit to the Trust of the price increase was mitigated by the strengthening of the Canadian dollar which rose from an average of $0.83 against the US dollar in 2005 to an average of $0.88 in 2006.  In Q4 2006 WTI decreased 2% to US$68.64/bbl compared to US$70.24/bbl in Q4 of 2005.



Similar to the benchmark prices for both oil and gas, the average price received by the Trust for oil was up and for gas was down in 2006 compared to 2005.  The Trusts average oil price increased by 7% in 2006 to an average of $62.13/bbl from $58.11/bbl in 2005.  The average gas price decreased by 10% in 2006 to an average of $7.53/mcf compared to $8.40/mcf in 2005.





|                                                     |                                 |        |                          |        |        |      
|---------------------------------------------------- | ------------------------------- | ------ | ------------------------ | ------ | ------ | -----
|Pricing(in thousands except for volumes and pricing)
|                                                     | Three months ended
December 31, |        | Years ended
December 31, |       
|2006                                                 | 2005                            | Change | 2006                     | 2005   | Change
|Pricing Benchmarks                                   |                                 |        |                          |        |        |      
|WTI (US$/bbl)                                        | 60.21                           | 60.03  | -                        | 66.22  | 56.56  | 17%  
|Average exchange rate: US$1.00 to Cdn$               | 1.14                            | 1.17   | (3%)                     | 1.13   | 1.21   | (7%) 
|WTI (Cdn$/bbl)                                       | 68.64                           | 70.24  | (2%)                     | 74.83  | 68.44  | 9%   
|AECO monthly index (Cdn$/GJ)                         | 6.91                            | 11.39  | (39%)                    | 6.53   | 8.73   | (25%)
|Nymex (US$/mmbtu)                                    | 6.62                            | 12.85  | (48%)                    | 7.26   | 8.56   | (15%)
|Average Prices Received by the Trust                 |                                 |        |                          |        |        |      
|Oil  (Cdn$ per bbl)                                  | 55.64                           | 56.83  | (2%)                     | 62.54  | 58.11  | 8%   
|Natural gas (Cdn$ per mcf)                           | 7.12                            | 8.82   | (19%)                    | 6.70   | 8.40   | (20%)
|Oil hedging settlements (Cdn$ per bbl)               | -                               | -      | -                        | (0.41) | -      | -    
|Natural gas hedging settlements  (Cdn$ per mcf)      | 0.79                            | -      | -                        | 0.83   | -      | -    
|Combined Oil  (Cdn$ per bbl)                         | 55.64                           | 56.83  | (2%)                     | 62.13  | 58.11  | 7%   
|Combined Natural gas (Cdn$ per mcf)                  | 7.91                            | 8.82   | (1%)                     | 7.53   | 8.40   | (10%)
|Total (1) (Cdn$ per boe)                             | 50.48                           | 55.26  | (9%)                     | 51.82  | 55.83  | (7%) 



(1) Includes NGLs



The Trust has a policy of hedging up to 50% of projected gross production up to 24 months in advance using price collars and avoiding fixed price sales so that the Trust is less exposed to significant short-term swings in commodity prices. Gains from the risk management program resulted in added gas revenues of $13.1 million in 2006, including $1.7 million realized during Q4 2006.  Those gains resulted in approximately an 11% increase in the average gas price received by the Trust in 2006 and a 10% increase in Q4 2006, as compared to the price the Trust would have received before hedging.  The profits from the gas price hedges were offset by slight losses on oil price hedges totaling $0.7 million for the year or approximately $0.41 per bbl.



At December 31, 2006, the Trust had the following financial derivatives and fixed price contracts outstanding:



|                        |                 |                           |                  |                                    
|----------------------- | --------------- | ------------------------- | ---------------- | -----------------------------------
|Derivative Instrument   | Commodity       | Price                     | Volume (per day) | Period                             
|Collars                 | Gas             | 7.50 by 12.00
(Cdn$/GJ)   | 7,500 GJ         | January 1, 2007  March 31, 2007   
|Fixed                   | Gas             | 7.80
(Cdn$/GJ)            | 2,500 GJ         | January 1, 2007  March 31, 2007   
|Collars                 | Gas             | 7.50 by 9.00
(Cdn$/GJ)    | 10,000 GJ        | April 1, 2007  October 31, 2007   
|Collars                 | Gas             | 8.00 by 12.00
(Cdn$/GJ)   | 10,000 GJ        | November 1, 2007  March 31, 2008  
|Collars                 | Gas             | 8.00 by 15.70
(US$/mmbtu) | 12,000 mmbtu     | January 1, 2007  March 31, 2007   
|Collars                 | Gas             | 7.50 by 11.20
(US$/mmbtu) | 5,000 mmbtu      | April 1, 2007  October 31, 2007   
|Collars                 | Gas             | 7.50 by 11.10
(US$/mmbtu) | 5,000 mmbtu      | April 1, 2007  October 31, 2007   
|Collars                 | Gas             | 8.00 by 16.40
(US$/mmbtu) | 10,000 mmbtu     | November 1, 2007  March 31, 2008  
|                        |                 |                           |                  |                                    
|Collars                 | Oil             | 55.00 by 81.20
(US$/bbl)  | 1,000 bbl        | January 1, 2007  June 30, 2007    
|Collars                 | Oil             | 55.00 by 80.50
(US$/bbl)  | 1,000 bbl        | January 1, 2007  December 31, 2007
|Collars                 | Oil             | 55.00 by 80.50
(US$/bbl)  | 1,000 bbl        | July 1, 2007  December 31, 2007   
|Collars                 | Oil             | 55.00 by 78.60
(US$/bbl)  | 500 bbl          | January 1, 2007  December 31, 2007
|                        |                 |                           |                  |                                    
|Fixed purchase physical | Power
(Alberta) | 62.90
(Cdn$/Mwh)          | 72 Mwh           | January 1, 2007  December 31, 2009



Consistent with the Trusts price risk mitigation strategy, these hedging positions represent approximately 47% of the Trusts expected production before royalties on a boe/day basis for fiscal 2007.



As at December 31, 2006 the financial instruments above had a mark-to-market value of $10.8 million which was recorded as a component of revenue in the consolidated financial statements.



Subsequent to December 31, 2006 the Trust entered into the following additional transactions:

·

the Trust purchased US$11.20/mmbtu Nymex call options for 5,000 mmbtu/day for the April 1, 2007 to October 31, 2007 period to eliminate the ceiling on the $7.50 by $11.20 gas collar noted in the table above;

·

the Trust sold 5,000 mmbtu/day, under fixed price Nymex contracts at US$7.555/mmbtu beginning April 1, 2007 to October 31, 2007; and

·

the Trust entered into a costless collar covering 500 bbl/day of production for the period beginning January 1, 2008 to June 30, 2008 with a ceiling of US$75.25/bbl and a floor of US$55.00/bbl.





REVENUES



The positive impact on year-over-year revenues of the over two-fold increase in natural gas sales volumes in 2006 compared to 2005 was partially offset by the 10% decrease in the sales price of natural gas.  For oil and NGL, revenues were relatively unchanged as the 6% decrease in volumes was largely offset by a 5% increase in the average price received by the Trust.  Overall, in 2006 revenues increased by $86.3 million or 55% compared to 2005, with much of the increase attributable to the acquisition of the Oklahoma Assets during Q1 and early in Q2.



|                                                                             |                                 |         |                          |          |          |       
|---------------------------------------------------------------------------- | ------------------------------- | ------- | ------------------------ | -------- | -------- | ------
|Revenues(in thousands)                                                      
|                                                                             | Three months ended
December 31, |         | Years ended
December 31, |         
|2006                                                                         | 2005                            | Change  | 2006                     | 2005     | Change  
|Revenues                                                                     |                                 |         |                          |          |          |       
|Oil and NGL                                                                  | $24,140                         | $30,105 | (20%)                    | $114,481 | $115,645 | (1%)  
|Natural gas                                                                  | 31,156                          | 20,143  | 55%                      | 119,111  | 42,098   | 183%  
|Unrealized mark to market gains on oil and natural gas financial instruments | 559                             | 354     | 57%                      | 10,628   | 354      | 2,902%
|Other                                                                        | 188                             | -       | -                        | 188      | -        | -     
|Total                                                                        | $56,043                         | $50,602 | 11%                      | $244,408 | $158,097 | 55%   







---



|                                                                                    |                                      |          |                               |           |         | 
|----------------------------------------------------------------------------------- | ------------------------------------ | -------- | ----------------------------- | --------- | ------- | 
|Revenues by Geographic area(in thousands)                                          
|                                                                                    | Three months ended
December 31, 2006 |          | Years ended
December 31, 2006 |          
|Canada                                                                              | U.S.                                 |          | Canada                        | U.S.      |        
|Revenues                                                                            |                                      |          |                               |           |         | 
|Oil and NGL                                                                         | $19,642                              | $  4,498 |                               | $  97,690 | $16,791 | 
|Natural gas                                                                         | 13,072                               | 18,084   |                               | 54,564    | 64,547  | 
|Unrealized mark to market gains (loss) on oil and natural gas financial instruments | (1,286)                              | 1,845    |                               | 4,664     | 5,964   | 
|Other                                                                               | (59)                                 | 247      |                               | (59)      | 247     | 
|Total                                                                               | $31,369                              | $24,674  |                               | $156,859  | $87,549 | 



Revenue in Q4 2006 increased 11% to $56.0 million from $50.6 million in 2005.  Similar to the full year results, the increase in revenue was largely attributable to a 73% increase in natural gas volumes largely attributable to the acquisition of the Oklahoma Assets, tempered by a 9% drop in the overall price per boe received by the Trust and lower production in Canada.



ROYALTIES



Royalties, which include Crown, freehold and overriding royalties and wellhead taxes, less Alberta Royalty Tax Credits (ARTC), increased in 2006 compared to 2005 as a result of increased revenue in the period.  Royalties vary depending on the total volumes sold and the price received by the Trust for the sales.



Q4s overall royalty rate was significantly lower in 2006 as compared to 2005.  The difference is largely attributable to approximately $3.0 million in realized hedging gains included in revenue which do not attract a royalty, a reduction in royalty rates for the Desan properties, and deep gas royalty credits granted to certain wells in the Ferrier area of West Central Alberta.





|                                                                   |                                 |         |                          |         |         |      
|------------------------------------------------------------------ | ------------------------------- | ------- | ------------------------ | ------- | ------- | -----
|Royalties(in thousands except for percentages and per boe amounts)
|                                                                   | Three months ended
December 31, |         | Years ended
December 31, |        
|2006                                                               | 2005                            | Change  | 2006                     | 2005    | Change 
|Royalties                                                          | $11,196                         | $12,920 | (13%)                    | $48,288 | $36,079 | 34%  
|As a percentage of oil, NGL and natural gas revenue                | 20%                             | 26%     |                          | 21%     | 23%     |      
|Royalties per boe                                                  | $10.22                          | $14.21  | (28%)                    | $10.71  | $12.77  | (16%)



|                                                                                      |                                      |        |                               |         |         | 
|------------------------------------------------------------------------------------- | ------------------------------------ | ------ | ----------------------------- | ------- | ------- | 
|Royalties by Geographic Area(in thousands except for percentages and per boe amounts)
|                                                                                      | Three months ended
December 31, 2006 |        | Years ended
December 31, 2006 |        
|Canada                                                                                | U.S.                                 |        | Canada                        | U.S.    |        
|Royalties                                                                             | $5,712                               | $5,484 |                               | $28,253 | $20,035 | 
|As a percentage of oil, NGL and natural gas revenue                                   | 17%                                  | 24%    |                               | 19%     | 25%     | 
|Royalties per boe                                                                     | $8.88                                | $12.13 |                               | $10.21  | $11.50  | 





---

PRODUCTION EXPENSES



Despite an industry environment characterized by excessive demand for supplies and services, the Trusts average operating expense in 2006 fell by 3% to $11.17 per boe compared to $11.55 per boe the prior year in part reflecting the acquisition of the lower-cost Oklahoma Assets.  Consistent with that decrease, while production volumes increased by 60% in 2006 compared to 2005, total operating expenses only increased by 54% to $50.4 million from $32.6 million in 2005.



In Q4 2006, total and per unit operating costs increased over Q4 2005 due to temporary operating problems within Oklahoma, work-over expenses in Canada and the timing of the realization of certain operating costs within 2006.  These increased costs are amplified on a per boe basis by normal declines in Canada.  As a result, operating costs in Q4 were higher than the prior year, averaging $16.04 per boe or $17.6 million in total compared to $12.11 per boe or $11.0 million in total in Q4 2005.



Canadian Assets



In Canada in 2006, the average operating expense increased by 13% to $12.84 per boe versus $11.38 per boe in 2005 due largely to inflationary cost pressures and to a lesser extent due to normal production declines.  Total operating expenses increased at a slower pace, rising 16% in 2006 to $35.5 million from $30.7 million in 2005, reflecting the year-over-year decrease in production volumes.



Similar factors adversely impacted the average operating expense in Q4 2006 compared to the same period in 2005, and were further affected by the timing of certain 2006 operating costs that were realized in Q4 2006.  While total operating costs in Q4 2006 increased by a relatively modest 24% to $12.4 million from $10.0 million in Q4 2005, the average operating cost jumped by 64% to $19.28 per boe in the last quarter of 2006 from $11.74 per boe the prior year due to a 24% period-over-period decline in production volumes.



U.S. Assets



Operating expenses for the U.S. Assets for 2006 averaged $8.52 per boe.  For the Q4 2006, because of the deferred expenses, pump failures, electrical problems and pump sizing issues, the operating costs had increased to $11.43 per boe in comparison to $9.66 per boe for these assets during Q3.



Just prior to the acquisition of the Oklahoma Assets, the previous owners had begun a drilling program in a new project area.  Early results of this program were very encouraging.  As drilling continued into an area with less available data, start-up failures were experienced on many of the new wells.  The cause of this was two fold; these new wells were drilled in an area where productivity had not been tested and the fluid production was not easily predictable so pump sizing was difficult and many wells required multiple pump changes in order to maximize production. Secondly, there were some cases of early equipment failures which were a result of some unusual electrical issues and start up failures.  Hence, the inordinate number of workovers and repair operations that began during the third quarter and continued throughout the remainder of the year caused higher than expected operating costs.   To compound the increase in repair frequency, the costs of goods and services increased over the year and that increase was not taken into account in our projections.





---



|                                                                             |                                 |         |                          |         |         |     
|---------------------------------------------------------------------------- | ------------------------------- | ------- | ------------------------ | ------- | ------- | ----
|Production Expenses(in thousands except for percentages and per boe amounts)
|                                                                             | Three months ended
December 31, |         | Years ended
December 31, |        
|2006                                                                         | 2005                            | Change  | 2006                     | 2005    | Change 
|Production expenses                                                          | $17,570                         | $11,007 | 60%                      | $50,361 | $32,620 | 54% 
|Production expenses per boe                                                  | $16.04                          | $12.11  | 32%                      | $11.17  | $11.55  | (3%)



|                                                                                                |                                      |        |                               |         |         | 
|----------------------------------------------------------------------------------------------- | ------------------------------------ | ------ | ----------------------------- | ------- | ------- | 
|Production Expenses by Geographic Area(in thousands except for percentages and per boe amounts)
|                                                                                                | Three months ended
December 31, 2006 |        | Years ended
December 31, 2006 |        
|Canada                                                                                          | U.S.                                 |        | Canada                        | U.S.    |        
|Production expenses                                                                             | $12,399                              | $5,171 |                               | $35,513 | $14,848 | 
|Production expenses per boe                                                                     | $19.28                               | $11.43 |                               | $12.84  | $8.52   | 





GENERAL AND ADMINISTRATIVE EXPENSES



General and administrative expenses (G&A) increased by 97% to $20.4 million from $10.3 million in 2005.  The change is largely due to the increased asset base of the Trust and the associated increased personnel and administrative functions, including the expansion into the U.S., together with the need to comply with increasing regulation, such as the Sarbanes-Oxley Act.  G&A per boe increased by 23% to $4.52/boe in 2006 compared to $3.66/boe in 2005.   Within G&A, the non-cash unit based compensation increased to $3.2 million in 2006 from $0.7 million in 2005.  This non-cash unit based compensation includes expenses for both unit option plans and the recently implemented performance and restricted unit plans.



G&A expenses for Q4 2006 increased over the corresponding period in 2005 due to increased year end costs such as reserves analysis for the larger asset base, year end audit fees covering the expanded operations of the Trust, year end compensation for the larger employee base and expanded office space to accommodate the Trusts growth.  For 2007, these costs are expected to have a smaller impact as they will be realized over the entire year as opposed to a single quarter.





|                                                                                             |                                 |        |                          |         |         |     
|-------------------------------------------------------------------------------------------- | ------------------------------- | ------ | ------------------------ | ------- | ------- | ----
|General and Administrative Expenses(in thousands except for percentages and per boe amounts)
|                                                                                             | Three months ended
December 31, |        | Years ended
December 31, |        
|2006                                                                                         | 2005                            | Change | 2006                     | 2005    | Change 
|G&A expenses  cash                                                                          | $7,079                          | $2,727 | 160%                     | $17,145 | $9,600  | 79% 
|G&A expenses  non cash                                                                      | 529                             | 263    | 101%                     | 3,229   | 731     | 342%
|Total G&A expenses                                                                           | $7,608                          | $2,990 | 154%                     | $20,374 | $10,331 | 97% 
|G&A per boe  cash                                                                           | $6.47                           | $3.00  | 116%                     | $3.81   | $3.40   | 12% 
|G&A per boe  non cash                                                                       | $0.48                           | $0.29  | 66%                      | $0.71   | $0.26   | 173%
|Total G&A per boe                                                                            | $6.95                           | $3.29  | 111%                     | $4.52   | $3.66   | 23% 







---

INTEREST EXPENSE



Interest expense increased in 2006 mainly due to the financing of the acquisition of the Oklahoma Assets.  On March 21, 2006, the Trust entered into a $110.0 million bridge credit facility to replace its current operating facilities as well as a US$200.0 million bridge credit facility.  These facilities were partially replaced on November 21, 2006 with the issuance of $138.0 million of 8% unsecured subordinated convertible debentures and $40.3 million of trust units.  The remaining balance of bridge facilities was replaced with a $180.0 million extendible credit facility and a $20.0 million extendible operating credit facility.



Interest expense increased in Q4 2006 compared to Q4 2005 due to the bridge loan facilities that were outstanding until November 21, 2006, the higher average outstanding loan balances during the period and the interest on the convertible debentures that were issued during the fourth quarter of 2006.



The Trust expects interest expense to decrease significantly in 2007 due to the replacement of the bridge loan facilities in November 2006 with lower interest credit facilities, convertible debentures and equity.





|                                                                                                   |                                 |          |                          |          |          |     
|-------------------------------------------------------------------------------------------------- | ------------------------------- | -------- | ------------------------ | -------- | -------- | ----
|Interest Expense(in thousands except for percentages and per boe amounts)                         
|                                                                                                   | Three months ended
December 31, |          | Years ended
December 31, |         
|2006                                                                                               | 2005                            | Change   | 2006                     | 2005     | Change  
|Bank indebtedness, capital lease, and notes payable at end of period                               | $189,856                        | $102,101 | 86%                      | $189,856 | $102,101 | 86% 
|Convertible debentures                                                                             | 78,974                          | -        | -                        | 78,974   | -        | -   
|Total convertible debentures, bank indebtedness, capital lease, and notes payable at end of period | $268,830                        | $102,101 | 163%                     | $268,830 | $102,101 | 163%
|Interest expense on bank indebtedness, capital lease, and notes payable                            | $7,739                          | $2,000   | 287%                     | $25,898  | $4,715   | 449%
|Interest expense on convertible debentures                                                         | 819                             | -        | -                        | 819      | -        | -   
|Total interest expense                                                                             | $8,558                          | $2,000   | 328%                     | $26,717  | $4,715   | 467%
|Interest expense per boe on bank indebtedness, capital lease, and notes payable                    | $7.07                           | $2.20    | 221%                     | $5.74    | $1.67    | 244%
|Interest expense per boe on convertible debentures                                                 | 0.75                            | -        | -                        | 0.18     | -        | -   
|Total interest expense per boe                                                                     | $7.81                           | $2.20    | 255%                     | $5.93    | $1.67    | 255%





FINANCING FEES



Financing fees were incurred in 2006 related to the issuances and repayments of the bridge loan facilities, the issuance of equity, the issuance of convertible debentures and the new $200 million revolving credit facility.  Of these fees, $5.4 million were related to the retirement of the bridge loan facilities and were expensed as incurred; $11.7 million were amortized into earnings as deferred financing fees on the various credit facilities and convertible debentures; $4.7 million of financing costs related to the convertible debentures and the $200 million revolving credit facility remained on the balance at December 31, 2006 as deferred financing costs; and $6.2 million were charged against unitholders equity as unit issue costs.





---

DEPLETION, DEPRECIATION AND ACCRETION INCLUDING CEILING TEST IMPAIRMENTS (DD&A)



The Trust recorded an impairment on its property, plant and equipment in 2006 totaling $66.0 million.  Approximately 67% of this amount was due to a reduction in proven and probable reserves value due to a combination of forecast increased expenses, commodity prices and decreased reservoir performance (32%, 21% and 14% respectively).  The remaining 33% was due to a reduction of the carrying value of undeveloped lands.



DD&A expense excluding the ceiling test impairment increased by 98% in 2006 compared to 2005, primarily due to the addition of the oil and natural gas properties acquired in the High Point and Oklahoma Asset acquisition.  The DD&A expense per boe excluding the ceiling test impairment increased 24% in 2006 compared to 2005 due to the higher cost of reserves associated with the acquisitions.



In 2006 a provision of $17.2 million is included within DD&A due to a ceiling test write down in the United States cost center. Of this change, higher estimated future operating costs contribute to approximately 55% of the reduction and lower than expected performance of certain wells within the Oklahoma asset make up the remainder of the decrease in the net present value of the reserves to which the test is calculated.



In 2006 a provision of $48.8 million is included within DD&A due to a ceiling test write down in the Canada cost center.  Of this provision approximately 45% is due to a reduction in the value of the reserves in the December 31, 2006 reserve report.  The source of this decline in value is a reduction in forecast commodity prices (60% of reduction) and the remainder is due to increases in forecasted operating costs.  Finally, a provision was required due to a lower amount and value of undeveloped lands in Canada resulting from lands given up in a swap of properties with JED and lower expectations for other undeveloped lands in the Trusts Canadian undeveloped lands.



In 2005 a provision of $13.8 million is included within DD&A due to a ceiling test write down in the United States cost center.  The provision was required due to the expiration of certain undeveloped lands in Rocky Mountain Gas, Inc, which increased the cost base that the test is calculated on and a reduction of the reserves in the December 31, 2005 reserve report due to the results from the properties during 2005.





|                                                                                               |                                 |         |                          |          |         |     
|---------------------------------------------------------------------------------------------- | ------------------------------- | ------- | ------------------------ | -------- | ------- | ----
|Depletion, Depreciation and Accretion(in thousands except for percentages and per boe amounts)
|                                                                                               | Three Months Ended
December 31, |         | Years Ended
December 31, |         
|2006                                                                                           | 2005                            | Change  | 2006                     | 2005     | Change 
|DD&A  excluding write down                                                                    | $36,148                         | $27,812 | 30%                      | $135,429 | $68,229 | 98% 
|Ceiling test provisions                                                                        | 66,019                          | 13,844  | 377%                     | 66,019   | 13,844  | 377%
|DD&A                                                                                           | $102,167                        | $41,656 | 145%                     | $201,448 | $82,073 | 145%
|DD&A per boe  excluding impairment per boe                                                    | $33.00                          | $30.59  | 8%                       | $30.04   | $24.15  | 24% 
|Ceiling test impairment per boe                                                                | 60.28                           | 15.23   | 296%                     | 14.64    | 4.90    | 199%
|DD&A per boe                                                                                   | $93.28                          | $45.82  | 104%                     | $44.68   | $29.05  | 54% 



In the fourth quarter of 2006, DD&A expense excluding the ceiling test impairment increased by 30% compared to 2005, due to the cost of the properties acquired with the Oklahoma Asset acquisition.  The DD&A expense per boe excluding the ceiling test impairment increased 8% in the fourth quarter of 2006 compared to 2005 due to the higher cost of reserves associated with the acquisition.



GOODWILL IMPAIRMENT



In 2005, the Trust realized a $9.3 million impairment on the goodwill recorded in the United States reporting unit.  In 2006, the Trust performed a goodwill impairment test and determined that goodwill was not impaired at December 31, 2006.

TAXES



The Trust is subject to tax on its income or loss for each taxation year, computed as though it was a separate individual resident in Canada.  The taxation year of the Trust ends on December 31 of each year.  Under the Trust Indenture, the Trust is not subject to income taxes if all of its taxable income will be paid or made payable by way of cash distributions to the unitholders.



The corporate subsidiaries of the Trust are subject to tax if deductions are inadequate to reduce taxable income to zero.



|                             |                                 |                          |                 |               
|---------------------------- | ------------------------------- | ------------------------ | --------------- | --------------
|                             | Three Months Ended December 31, | Years Ended December 31,
|2006                         | 2005                            | 2006                     | 2005           
|Current tax expense          | $          643                  | $              354       | $         1,324 | $        1,456
|Future income tax (recovery) | (32,594)                        | (15,325)                 | (58,899)        | (18,689)      
|Total tax (recovery)         | $  (31,951)                     | $      (14,971)          | $    (57,575)   | $   (17,233)  



Current tax expense relates to income taxes of $1.0 million resulting from the High Point group of assets for the taxation period ended August 17, 2005.  The remainder of the $0.3 million relates to the underaccrual of capital taxes for the taxation years from 2003 to 2005.



Future income tax recovery of $58.9 million arises from several factors.  The major factor is the decreased accounting basis of the property, plant and equipment stemming from the impairment of US cost center of $17.2 million, giving a future income tax recovery of $6.9 million, as well as the impairment of the Canadian cost center of $48.8 million giving a future tax recovery of $14.4 million.  Depletion expense in Canada of $90.7 million accounts for another $27.2 million.  The remainder of the decrease stems from an adjustment in the tax rate applied to temporary differences from 34% in 2005 to 30% in 2006 giving rise to an income tax recovery of $6.7 million.



On October 31, 2006 the Canadian Minister of Finance announced certain proposed changes to the taxation of publicly traded trusts (see Implications of Recent Tax Proposals by Canadian Minister of Finance above). If enacted, the changes will result in the Trust being subject to a tax in a manner similar to corporations effective January 1, 2011. The Trust continues to research its position based on the proposed rules and is waiting for the final legislation.  As the tax proposals had not yet been substantially enacted as at December 31, 2006, the consolidated financial statements do not reflect the impact of proposed taxation.



NON-CONTROLLING INTEREST



The Trust's exchangeable shares are classified as non-controlling interest on the consolidated balance sheets.  Income after tax attributable to these exchangeable shares is deducted from net earnings of the Trust on the consolidated statements of earnings.



In 2006, 1,661,047 exchangeable shares were exchanged into trust units (2005  953,129).  The remainder of the exchangeable shares were converted into trust units by the end of January 2007.



NON-GAAP FINANCIAL MEASURES



The Trust provides financial measures in the MD&A that do not have a standardized meaning prescribed by GAAP.  These non-GAAP financial measures may not be comparable to similar measures presented by other entities.



The purpose of these financial measures and their reconciliation to GAAP financial measures are shown below.  All of the measures have been calculated consistent with previous disclosures by the Trust.





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Funds from Operations



Management uses funds from operations to analyze operating performance and leverage.  Funds from operations as presented is not intended to represent cash provided by operating activities nor should it be viewed as an alternative to net earnings or other measures of financial performance calculated in accordance with GAAP.  All references to funds from operations throughout this MD&A are based on cash provided by operating activities before changes in non-cash working capital as reconciled in the table below:

|                                          |                                 |                          |         |        
|----------------------------------------- | ------------------------------- | ------------------------ | ------- | -------
|                                          | Three months ended
December 31, | Years ended
December 31,
|2006                                      | 2005                            | 2006                     | 2005   
|Cash provided by operating activities     | $26,163                         | $20,575                  | $64,485 | $68,120
|Changes in non-cash working capital items | (16,605)                        | (1,056)                  | 21,632  | 2,425  
|Funds from operations                     | $9,558                          | $19,519                  | $86,117 | $70,545



In 2006, funds from operations increased by 22% over 2005.  This increase is mainly due to the increased funds generated by the acquisition of the Oklahoma Assets, tempered by increased interest expense associated with the interim financing arrangements, comparably lower prices for natural gas and increased general and administrative costs.



In Q4 2006, the benefit of higher production volumes due to the acquisition of the Oklahoma Assets was more than offset by the effects of lower commodity prices, higher operating expenses, general and administrative costs and interest expense.  As a result, funds from operations for the period declined by 51% to $9.6 million compared to $19.5 million in Q4 2005.



CASH DISTRIBUTIONS PAID TO UNITHOLDERS



The Trust pays monthly cash distributions in US dollars.  Cash distributions are paid on the 15th of the following month (e.g. the December 2006 distribution was paid on January 15, 2007).  These distributions are determined each month by the Board of Enterra Energy Corp., as administrator of the Trust, after review of a number of factors potentially impacting the Trust including its available prospects and opportunities, the outlook for commodity prices and other macro-economic factors, and the Trusts financial position and commitments.



On July 18, 2006, the Trust announced a change to its target payout ratio, reducing it from 90% to 100% of funds from operations to a range of 60% to 70%.  The effect was a decrease in the monthly distribution to US$0.12 per unit compared to US$0.18 per unit in June 2006.



On January 19, 2007, due to significantly weaker commodity prices, capital market uncertainty resulting from the recent tax changes proposed by the Canadian government, and early conversion of debentures to trust units, the Trust decreased its monthly distribution to US$0.06 per unit from US$0.12.



The Trust continues to monitor the payout ratio to ensure that over the medium and long term, the ratio remains in the target range.





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The monthly cash distributions per trust unit since the inception of the Trust are as follows:



|                                                            |                                 |              |                          |               |             |            
|----------------------------------------------------------- | ------------------------------- | ------------ | ------------------------ | ------------- | ----------- | -----------
|US$                                                         |                                 | 2007         | 2006                     | 2005          | 2004        | 2003       
|January                                                     |                                 | $       0.06 | $      0.18              | $        0.14 | $      0.10 |            
|February                                                    |                                 | $       0.06 | $      0.18              | $        0.14 | $      0.10 |            
|March                                                       |                                 | $       0.06 | $      0.18              | $        0.15 | $      0.11 |            
|April                                                       |                                 |              | $      0.18              | $        0.15 | $      0.11 |            
|May                                                         |                                 |              | $      0.18              | $        0.15 | $      0.11 |            
|June                                                        |                                 |              | $      0.18              | $        0.16 | $      0.12 |            
|July                                                        |                                 |              | $      0.12              | $        0.16 | $      0.12 |            
|August                                                      |                                 |              | $      0.12              | $        0.16 | $      0.12 |            
|September                                                   |                                 |              | $      0.12              | $        0.17 | $      0.13 |            
|October                                                     |                                 |              | $      0.12              | $        0.17 | $      0.13 |            
|November                                                    |                                 |              | $      0.12              | $        0.17 | $      0.13 |            
|December                                                    |                                 |              | $      0.12              | $        0.18 | $      0.14 | $      0.10
|                                                            |                                 |              |                          |               |             |            
|                                                            | Three months ended
December 31, |              | Years ended
December 31, |              
|2006                                                        | 2005                            | Change       | 2006                     | 2005          | Change     
|Cash distributions to unitholders                           | $19,574                         | $21,067      | (7%)                     | $90,487       | $66,195     | 37%        
|Funds from operations                                       | $9,558                          | $19,519      | (51%)                    | $86,117       | $70,545     | 22%        
|Cash distributions as a percentage of funds from operations | 205%                            | 108%         |                          | 105%          | 94%         |            



The payout ratio in 2006 was 105%, exceeding the target payout ratio of 60% to 70% of funds from operations, in part due to the higher level of distributions from January 2006 to July 2006 (June 2006 distribution of US$ 0.18 was paid in July 2006).  In July 2006, the Trust reduced its monthly distribution, payable in August 2006, from US$0.18 per unit to US$0.12 per unit.  Had the Trust paid a monthly distribution of US$0.12 for all of 2006 instead of the US$0.18 for January to August, the cash distributed to unitholders would have been $70.9 million, or 82% of funds from operations.



The payout ratio in Q4 2006 was 205%.  In January 2007, the Trust reduced its monthly distribution, payable in February 2006, from US$0.12 per unit to US$0.06 per unit.  Had the Trust paid a monthly distribution of US$0.06 per unit in Q4 2006 instead of US$0.12 per unit, the cash distributed to unitholders would have been $9.8 million, or 102% of funds from operations.  While that level of distributions is above the target payout range of the Trust, as noted above, general and administrative costs and interest expense are considered to have been unusually high in the period and are expected to decrease in 2007.



To the extent that the Trust uses cash to finance acquisitions, development costs and other significant expenditures, the net cash that the Trust receives that is available for distribution to unitholders will be reduced.  Hence, the timing and amount of capital expenditures may affect the amount of net cash flow received by the Trust and, as a consequence, the amount of cash available to distribute to unitholders.  Therefore, distributions may be reduced, or even eliminated, at times when significant capital or other expenditures are made with the use of available cash.



The Trust currently minimizes cash income taxes in corporate subsidiaries by maximizing deductions, however in future periods there may be cash income taxes if deductions in the corporate entities are not sufficient to eliminate taxable income.  Taxability of the Trust is currently passed on to unitholders in the form of taxable distributions.  If the proposed Trust taxation legislation is enacted, the Trust anticipates that the resulting tax commencing in 2011 at the Trust level would decrease cash flow and thus reduce cash distributions to unitholders.



The Board of Enterra Energy Corp., as administrator of the Trust has the discretion to determine the extent to which cash provided by operating activities will be allocated to the payment of debt service charges as well as the repayment of outstanding debt.  As a consequence, the amount of cash retained to pay debt service charges or reduce debt will reduce the amount of cash available for distribution to unitholders during those periods in which funds are so retained.



For Canadian tax purposes, cash distributions are comprised of a return of capital portion, which is tax deferred, and return on capital portion, which is taxable income.  The return of capital portion reduces the cost base of the trust units held.  The cost base is required in the calculation of a capital gain or loss upon the disposition of the trust units.  For 2006, the cash distributions declared for 2006 are approximately 80% return on capital (taxable) and 20% return of capital (tax deferred).   For tax information for non-resident unitholders, please visit our website at www.enterraenergy.com.



CAPITAL EXPENDITURES



A component of the Trusts business strategy is to invest available funds not distributed to unitholders in lower-risk projects within core areas of its asset base.  As well, the Trust continually seeks accretive acquisitions of oil and gas assets that will create new core areas with investment potential or will consolidate an existing core area.  Any such purchases are financed with cash flows from operations, issuing new trust units or incurring new debt, or any combination thereof.



During the first and second quarters of 2006, the Trust acquired oil and natural gas properties located in Oklahoma.  The Oklahoma Assets provide the Trust with a sizeable presence in the United States and a large portfolio of development drilling opportunities.  The Trust acquired the assets in four stages.



Prior to closing the acquisition, the Trust acquired $49.7 million of notes payable by the primary vendors of the Oklahoma Assets.  $11.2 million of these notes was assumed by the Trust as consideration on the closing of the first stage of the acquisition.  The remaining notes were repaid, by the vendors, to the Trust upon the second closing of the acquisition.  The acquisition of the notes, by the Trust, was financed with a US$50.0 million senior bridge credit facility.



On January 18, 2006, the Trust closed the first stage of the acquisition of the Oklahoma Assets.  The results of the operations of the assets acquired are included in the Trusts consolidated financial statements as of January 18, 2006.



On March 21, 2006, the Trust closed the second stage of the acquisition of the Oklahoma Assets.  Along with the second stage, the Trust acquired the operating company of the Oklahoma Assets.  The results of operations of the assets acquired and the operating company are included in the Trusts consolidated financial statements as of March 21, 2006.



On April 4, 2006, the Trust closed the third stage of the acquisition of the Oklahoma Assets.  The results of operations of the assets acquired are included in the Trusts consolidated financial statements as of April 4, 2006.



On April 18, 2006, the Trust closed the fourth stage of the acquisition of the Oklahoma Assets.  The results of operations of the assets acquired are included in the Trusts consolidated financial statements as of April 18, 2006.



The total consideration paid for the acquisition was $307.6 million (5,685,028 units valued at $116.5 million and $181.0 million of cash, including $8.9 million that remained unpaid at December 31, 2006, and transaction costs of $10.0 million).



On September 28, 2006, the Trust closed a property swap agreement with JED whereby the Trust swapped certain of its interests in properties in the Ferrier area of Alberta, valued at $44.0 million for interests of JED in common with the Trust in East Central Alberta, the Desan area of North Eastern British Columbia and the Ricinus area of Alberta, valued at $30.9 million.  The swap was based on independent third party engineering evaluations.  The transaction also resulted in the termination of the Agreement of Business Principles between the Trust and JED whereby the Trust had a right of first refusal on properties that JED owned and JED had the ability to farm-in on the Trusts undeveloped lands.  Concurrent with the swap, the Trust settled all amounts owing to JED.



The following table represents the Trust's capital expenditures that were paid for with cash.  The source of this cash was through private placements of trust units and excess funds from the bridge financing.  The table excludes certain capital expenditures, such as the portion of the Oklahoma Asset acquisition, which were paid for with non-cash consideration such as trust units.



|                                                                         |                                 |        |                          |          |         |     
|------------------------------------------------------------------------ | ------------------------------- | ------ | ------------------------ | -------- | ------- | ----
|Capital Expenditures Paid with Cash(in thousands except for percentages)
|                                                                         | Three months ended
December 31, |        | Years ended
December 31, |         
|2006                                                                     | 2005                            | Change | 2006                     | 2005     | Change 
|Capital expenditures                                                     | $5,144                          | $9,181 | 44%                      | $213,101 | $33,617 | 534%



Capital additions, including non-cash additions, for the year ended December 31, 2006 were $420.0 million (2005 - $419.7 million).  In addition to the acquisition of the Oklahoma Assets of $353.0 million (of which $8.9 million was unpaid at December 31, 2006), the assets acquired through the JED swap, including post closing adjustments, of $32.4 million, property, plant and equipment additions of $30.9 million, $3.3 million of net asset retirement obligations (ARO) and $0.4 million related to minority interest accounting as per EIC-151 were charged to property, plant and equipment.  Total dispositions for the year ended December 31, 2006 were $50.8 million (2005 - $nil).



The Trust accounts for its investment in its U.S. operations as a self sustaining operation, which means the capital assets associated with the U.S. operations (as well as all other balance sheet accounts for the U.S. operations) are subject to revaluation to the current exchange rate at each balance sheet date.  The result of this revaluation is a change in the carrying value of the U.S. assets, which is not a result of capital additions or disposals.



In 2006, the Trust participated in the drilling of 45 (13.9 net) development wells; 28 (5.8 net) in Canada and 17 (8.1 net) in Oklahoma.  In addition, 20 (10 net) wells were drilled on lands that are prospective for coal bed methane owned by the Trust in Wyoming.



In 2006 in Canada, the Trust spent $15.5 million in capital expenditures; $4.5 million related to drilling and completions operations, $4.4 million  for the construction of facilities and pipelines, $2.3 million for other plant and equipment and $1.6 million for the completion equipping and tie-in of the deep gas well at Ricinus.



In Oklahoma in 2006, the Trust initiated an aggressive land acquisition program.  During the year approximately US$4.5 million was spent to acquire lands for future development.   In addition, during Q4 2006 the Trust drilled two salt water disposal wells at a total cost of approximately US$4.8 million.  On occasion and as required, the Trust will drill further water disposal wells and make additions to existing facilities to support the dewatering efforts of the new wells being drilled under the farmout. During 2006 the trust also spent approximately US$1.5 million for infrastructure additions to support the locations being drilled. The capital cost of the disposal wells and infrastructure additions is recovered by the Trust over a 3 year period once the partner begins to fully utilize the facilities.



For 2007, the Trust plans to continue its capital additions through a combination of acquisitions and development activities.  In Oklahoma, the Trusts undeveloped lands will continue to be developed under the existing farmout agreement allowing the Trust to minimize its capital expenditures while increasing the production base.  In Canada, the Trust will continue to develop its existing land base as well as seek new areas for development







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RESERVES AND PRESENT VALUE SUMMARY



The Trust complies with the National Instrument 51-101, issued by the Canadian Securities Administrators, in all its reserves related disclosures.



Proved reserves (P90) - For reported reserves this means there must be at least a 90 percent probability that the quantities actually recovered will equal or exceed the estimated proved reserves.



Proved plus Probable (P50) - For reported reserves there must be at least a 50 percent probability that the quantities actually recovered will equal or exceed the sum of the proved plus probable reserves.  The probable reserves will no longer be risked by 50 percent as they are implicitly risked due to the nature of the new definition of reserves.



The purpose of NI 51-101 is to enhance the quality, consistency, timeliness and comparability of oil and gas activities by reporting issuers and elevate reserves reporting to a higher level of accountability.



Reserve volumes and values at December 31, 2005 are based on the Trust's interest in its total proved and probable reserves prior to royalties as defined in NI 51-101.  Reserve volumes and values for years prior to 2003 are based on "established" (proved plus 50% probable) reserves prior to deduction of royalties.  Under those definitions, probable reserves were discounted by an arbitrary risk factor of 50% in reporting established reserves.  Under NI 51-101 reserves definitions, estimates are prepared such that the full proved and probable reserves are estimated to be recoverable (proved plus probable reserves are effectively a "most likely case").  As such, the probable reserves reported are already "risked".



The Trust has its reserves evaluated by independent engineers each year.  McDaniel and Associates Consultants Ltd. ("McDaniel") independently evaluated the 2006 Canadian reserves of the Trust,  MHA Petroleum Consultants, Inc (MHA) independently evaluated the Trusts affiliate Rocky Mountain Gas 2006 reserves and HAAS Petroleum Engineering Services, Inc evaluated the trusts Oklahoma reserves as at December 31, 2006.



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|                                                          |         |          |        
|--------------------------------------------------------- | ------- | -------- | -------
|Reserve Continuity                                       
|Oil and Gas (mboe)                                       
|                                                          | Proved  | Probable | Total  
|December 31, 2004                                         | 7,385   | 2,024    | 9,409  
|Discoveries and extensions                                | 47      | 14       | 61     
|Purchases (including East Central Properties acquisition) | 9,784   | 5,020    | 14,804 
|Dispositions                                              | -       | -        | -      
|Production                                                | (2,825) | -        | (2,825)
|Revision of prior estimates                               | (96)    | (2,321)  | (2,417)
|December 31, 2005                                         | 14,295  | 4,737    | 19,032 
|Discoveries and extensions                                | 536     | 549      | 1,085  
|Purchases                                                 | 15,041  | 1,961    | 17,002 
|Dispositions                                              | (1,491) | (614)    | (2,105)
|Production                                                | (4,508) | -        | (4,508)
|Revision of prior estimates                               | (2,655) | (494)    | (3,149)
|December 31, 2006                                         | 21,218  | 6,139    | 27,357 
|                                                         



Proved plus probable reserves increased 44% from the end of 2005 to the end of 2006 primarily due to the Oklahoma Asset acquisition and ongoing development there and in Canada.  Proved reserves increased 48% from 14,295 mboe to 21,218 mboe and probable reserves increased 30% from 4,737 mboe to 6,139 mboe.  Total proved reserves represent 78% of total reserves versus 75% in 2005.



Discoveries and extensions of 1,085 mboe are primarily in Oklahoma.  Revisions were both in Canada and the United States assets due to poorer than expected performance of new wells, changes in commodity price forecasts and increased operating expenditures due to increased cost of services.  Divesting of non core assets in Canada resulted in 2,105 mboe reduction in proved plus probable reserves



Finding costs incurred over the last three years are highlighted below, along with the recycle ratios for each year.  Management uses the recycle ratio to measure performance.  It is calculated by dividing the netback per boe of production by the cost of per boe of finding and developing reserves. A recycle ratio of one is a break even point, indicating that the cash flow from a unit of production is equal to the cost of finding and developing a unit of reserves.



Under NI 51-101, the methodology to be used to calculate finding, development and acquisition costs (FD&A), costs include incorporating changes in future development costs (FDC) required to bring the proved undeveloped and probable reserves to production.  For continuity the Trust has presented FD&A costs calculated both excluding and including FDC.



The aggregate of the exploration and development costs incurred in the most recent financial year and the change during that year in estimated future development costs generally will not reflect total finding and development costs related to reserves additions for that year.





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|                                                                                                        |          |          |         |         
|------------------------------------------------------------------------------------------------------- | -------- | -------- | ------- | --------
|FD&A and recycle ratio(in $/boe, except for capital expenditures which are in thousands)               
|                                                                                                        | 2006     | 2005     | 2004    | 3-year  
|Average                                                                                                
|Capital expenditures (excluding ARO)                                                                    | $416,649 | $419,679 | $66,416 | $300,522
|Future Development Costs
Proved                                                                         | $10,101  | $6,973   | $589    | 5,888   
|Proved Plus Probable                                                                                    | $15,002  | $7,448   | $589    | $7,680  
|Reserves(1)                                                                                             |          |          |         |         
|Proved reserves added in the year (in mboe)                                                             | 12,922   | 9,735    | 3,822   | 8,826   
|Probable reserves added in the year (in mboe)                                                           | 2,016    | 2,713    | (266)   | 1,488   
|Proved plus probable reserves added in the year  (in mboe)                                              | 14,938   | 12,448   | 3,556   | 10,314  
|                                                                                                        |          |          |         |         
|FD&A costs (excluding FDC)                                                                              |          |          |         |         
|Proved reserves ($/boe)                                                                                 | 32.24    | 43.11    | 17.38   | 34.05   
|Proved plus probable reserves ($/boe)                                                                   | 27.89    | 33.71    | 18.68   | 29.14   
|                                                                                                        |          |          |         |         
|FD&A costs (including FDC)                                                                              |          |          |         |         
|Proved reserves ($/boe)                                                                                 | 33.03    | 43.83    | 17.53   | 34.72   
|Proved plus probable reserves ($/boe)                                                                   | 28.90    | 34.31    | 18.84   | 29.88   
|Corporate Netbacks ($/boe)(2)                                                                           | 19.49    | 25.98    | 21.06   | 22.18   
|Corporate recycle ratio (based on proved plus probable finding costs excluding FDCs)                   | 0.70     | 0.77     | 1.13    | 0.87    
|Operating netbacks ($/boe) (3)                                                                          | 29.93    | 31.31    | 23.67   | 28.30   
|Operating recycle ratio (based on proved plus probable reserves excluding FDCs))                       | 1.07     | 0.93     | 1.27    | 1.09    
|(1) Includes revisions and acquisitions                                                                
|(2) Corporate netbacks are production revenue less royalties, operating costs, G&A and interest expense
|(3) Operating netbacks are production revenue less royalties and operating costs                       



Finding costs and recycle ratios are non-GAAP financial measures that may not be comparable to similar measures presented by other entities.



The Trust reduced its proved plus probable FD&A excluding FDC costs from $33.71/boe to $27.89/boe. This was due to the acquisition of the Oklahoma Assets at lower metrics than the 2005 acquisitions.







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Enterra Energy Trust - Estimated Petroleum and Natural Gas Reserves and Net Present Value

(December 31, 2006) (NPV in millions)

|                                                                                                                                    |        |        |         |        |        |                       |     |    
|----------------------------------------------------------------------------------------------------------------------------------- | ------ | ------ | ------- | ------ | ------ | --------------------- | --- | ---
|                                                                                                                                    | Light/ |        |         |        |        | Net Present Value    
|                                                                                                                                    | Medium | Heavy  | Natural |        |        | Before Income Tax ($)
|                                                                                                                                    | Oil    | Oil    | Gas     | NGLs  | Total  |                       |     |    
|                                                                                                                                    | (MBBL) | (MBBL) | (MMCF)  | (MBBL) | (MBOE) | 0%                    | 10% | 15%
|Canadian Assets                                                                                                                     |        |        |         |        |        |                       |     |    
|                                                                                                                                   
|McDaniel report                                                                                                                    
|Proved Producing                                                                                                                    | 2,928  | 1,070  | 28,380  | 672    | 9,400  | 226                   | 175 | 158
|Proved Non-Producing                                                                                                                | 27     | -      | 1,405   | 41     | 302    | 2                     | 1   | -  
|Proved Undeveloped                                                                                                                  | 111    | -      | 2,171   | 30     | 502    | 8                     | 4   | 3  
|Total Proved                                                                                                                        | 3,066  | 1,070  | 31,956  | 742    | 10,204 | 236                   | 180 | 162
|Total Probable                                                                                                                      | 1,092  | 313    | 14,114  | 269    | 4,026  | 114                   | 60  | 47 
|Total Proved &
Probable                                                                                                             | 4,157  | 1,383  | 46,070  | 1,011  | 14,230 | 350                   | 240 | 209
|                                                                                                                                    |        |        |         |        |        |                       |     |    
|United States Assets                                                                                                                |        |        |         |        |        |                       |     |    
|                                                                                                                                   
|Haas and MHA reports                                                                                                               
|Proved Producing                                                                                                                    | 1,423  | -      | 43,602  | -      | 8,690  | 215                   | 158 | 139
|Proved Non-Producing                                                                                                                | 55     | -      | 2,364   | -      | 449    | 11                    | 8   | 7  
|Proved Undeveloped                                                                                                                  | 319    | -      | 9,337   | -      | 1,875  | 68                    | 44  | 37 
|Total Proved                                                                                                                        | 1,797  | -      | 55,303  | -      | 11,014 | 294                   | 210 | 183
|Total Probable                                                                                                                      | 202    | -      | 11,470  | -      | 2,114  | 58                    | 40  | 34 
|Total Proved &
Probable                                                                                                             | 1,999  | -      | 66,773  | -      | 13,128 | 353                   | 250 | 217
|Consolidated Assets                                                                                                                 |        |        |         |        |        |                       |     |    
|                                                                                                                                    |        |        |         |        |        |                       |     |    
|Proved Producing                                                                                                                    | 4,351  | 1,070  | 71,983  | 672    | 18,090 | 441                   | 332 | 297
|Proved Non-Producing                                                                                                                | 82     | -      | 3,769   | 41     | 751    | 13                    | 9   | 8  
|Proved Undeveloped                                                                                                                  | 430    | -      | 11,508  | 30     | 2,377  | 76                    | 48  | 40 
|Total Proved                                                                                                                        | 4,863  | 1,070  | 87,259  | 742    | 21,218 | 530                   | 390 | 345
|Total Probable                                                                                                                      | 1,294  | 313    | 25,584  | 269    | 6,139  | 172                   | 100 | 81 
|Total Proved &
Probable                                                                                                             | 6,156  | 1,383  | 112,843 | 1,011  | 27,358 | 703                   | 489 | 426
|(1) The Haas and MHA reports were converted to Canadian dollars by the Trust using an exchange rate of US$0.87 per Canadian dollar. |       



LIQUIDITY & CAPITAL RESOURCES



The Trusts strategy is to both develop its own reserves and undeveloped land as well as have other companies spend the capital to develop its properties in exchange for a working interest.  As well, the Trust continually seeks accretive acquisitions of oil and gas assets that will create new core areas with investment potential or will consolidate an existing core area.  Any such capital expenditures or purchases by the Trust will be financed from cash flow, by issuing new equity and/or with debt.



In March 2006, the Trust closed a $110.0 million senior secured bridge facility.  This reducing non-revolving credit facility was used to repay $100.0 million in existing credit facilities of the Trust with the excess being added to the working capital.  The bridge facility bore interest at 2.5% above bank prime lending rates.  $2.0 million of the facility was repaid on June 30, 2006 with the remaining $108.0 million repaid on November 21, 2006.  The facility was secured by a first charge over all Canadian assets of the Trust and a second charge over all US assets.



Also in March 2006, the Trust closed a US$200.0 million senior secured bridge credit facility to partially fund the acquisition of the Oklahoma Assets, repay US$50.0 million bridge credit facility and provide working capital to the Trust.  This non-revolving facility originally bore interest at 4.5% above London Interbank Offering Rate and matured September 20, 2006.  The Trust exercised a one-time option to extend the facility to December 20, 2006.  As a result of this extension, the interest rate margin increased by 1% per month.  The facility was repaid in full on November 21, 2006.  The facility was secured by a first charge over all US assets and a second charge over all Canadian assets.  The terms of the credit facility restricted the Trusts ability to withdraw more than US$1.5 million per month from the US segment.



On November 21, 2006, the Trust closed a $180.0 million revolving extendible credit facility and a $20.0 million revolving extendible operating credit facility.  The $180.0 million and $20.0 million facilities are 364 day extendible facilities that are secured with a first priority charge over the Trusts assets.  Borrowings under these facilities bear interest at bankers acceptance rates, Canadian or US prime rates, or LIBOR plus applicable margins ranging from nil to 1.65% depending on the form of borrowing and the Trusts debt to cash flow ratio. The current margin is 0.25% on prime rate borrowings and 1.4% on bankers acceptance rates or LIBOR borrowing.  Should the lenders decline to extend the facilities at the end of the 364 day period, the facilities convert into one year term loans.



The facility requires the Trust to maintain certain financial covenants.  As at December 31, 2006, the Trust is uncertain about its ability to meet certain of its covenant requirements for the first quarter of 2007, specifically the requirement that total distributions over the previous four quarters shall not exceed 100% of available cash flow over the period.  As at March 31, 2007, the Trusts percentage of available cash flow distributed for the previous four quarters will remain high due to the US$0.18/unit distribution paid from April to July 2006 and the US$0.12/unit distribution paid from August 2006 to January 2007. As the current US$0.06/unit distribution continues, the Trusts ratio will improve.  Should the Trust not meet the covenant at March 31, 2007, or subsequent periods, nor be able to obtain waivers from the lenders, the lenders could restrict distributions by the Trust and the facilities could become due and payable immediately.



The lenders are currently conducting their semi-annual review of the Trusts oil and gas reserves and borrowing base.  Upwards or downwards adjustments to the size of the credit facility may arise from their review.



Also on November 21, 2006 the Trust issued $138.0 million of 8.0% unsecured subordinated debentures convertible into units at a price of $9.25 and $40.3 million of trust units at a price of $8.10.  Proceeds from this issuance, together with drawings under the new revolving credit facilities, were used to repay the US$200.0 million senior secured bridge credit facility and the $110.0 million senior secured bridge facility.



On February 1, 2007, the $180.0 million revolving extendible credit facility was amended to be a $140.0 million revolving extendible credit facility with the same terms as the $180.0 million facility and a $40.0 million non-revolving credit facility.  The $40.0 million facility is a second-lien credit facility that matures on November 20, 2007.  Borrowings under the facility bear interest at Canadian or US prime rates plus a margin of 1.5%, or Canadian bankers acceptance rates or US LIBOR plus 2.5%.  It is expected that the facility will not be repaid from internally generated cash flows or asset dispositions; therefore additional financing through the issuance of debt or equity will be required.



|                                            |                   |                  
|------------------------------------------- | ----------------- | -----------------
|Working Capital(in thousands)               | December 31, 2006 | December 31, 2005
|Working capital (deficiency)                | $(188,683)        | $(112,397)       
|Working capital (deficiency) excluding debt | $(529)            | $(16,947)        



The working capital deficiencies mainly related to the classification of the  bank indebtedness as current liabilities even though there is no expectation that the revolving lines of credit will be called by the bank.



The continued benefit of the cash flow from the Oklahoma Assets together with excess cash generated though the lowering of the target payout ratio in July 2006, effective with the payment of the August 2006 distribution, to between 60% and 70% are expected to provide strong cash flows for the Trust to fund its working capital requirements and capital expenditures



CONTRACTUAL OBLIGATIONS



The Trust has two ongoing commitments over the next five years, one related to the capital lease and the other related to the rental payments for our office space.  These commitments are outlined below:



|                                                                                            |                                   |                  |            |             |                   | 
|------------------------------------------------------------------------------------------- | --------------------------------- | ---------------- | ---------- | ----------- | ----------------- | 
|                                                                                            | Payments due by period (in 000s)
|Contractual Obligations                                                                     | Total                             | Less than 1 year | 1- 3 years | 3  5 years | More than 5 years
|Debt Obligations(1)                                                                         | $188,154                          | $40,000          | $147,797   | $-          | $357             
|Interest on above debt (2)                                                                  | 20,555                            | 12,019           | 8,422      | -           | 114              
|Convertible debentures                                                                      | 80,331                            | -                | -          | 80,331      | -                
|Interest on convertible debentures (3)                                                      | 32,132                            | 6,426            | 19,279     | 6,427       | -                
|Capital (Finance) Lease Obligations                                                         | 1,702                             | 1,702            | -          | -           | -                
|Operating Lease Obligations                                                                 | 6,848                             | 1,162            | 2,173      | 2,342       | 1,171            
|Purchase Obligations                                                                        | -                                 | -                | -          | -           | -                
|Other Long-Term Liabilities Reflected on the Registrant's Balance Sheet under Canadian GAAP | 28,447                            | 2,000            | -          | -           | 26,447           
|Total                                                                                       | $358,169                          | $63,309          | $177,671   | $89,100     | $28,089          

(1)

The bank debt is assumed to be repaid on November 20, 2008

(2)

using the December 31, 2006 loan balance and its interest rate of 6.40%

(3)

using the December 31, 2006 balance and its interest rate of 8.0%



At December 31, 2006 a claim in the amount of approximately US$3.9 million has been filed against the Trust related to its U.S. operations.  The result of this claim is not determinable by the Trust.  The Trust has also filed claims against the claimant.



Certain claims have been brought against the Trust in the ordinary course of business.  In the opinion of management, all such claims, except as noted above, are adequately covered by insurance, or if not so covered, are not expected to materially affect the Trusts financial position.



RELATIONSHIP WITH JED



On January 1, 2006, the Trust terminated the Technical Services Agreement with JED under which JED provided certain administrative, management and technical services to the Trust.  The Trust now manages its own management, development, exploitation, operations and general and administrative activities.



On February 1, 2006, the Trust repaid $8.0 million in unsecured notes payable to JED that had been outstanding at December 31, 2005.



On September 28, 2006, the Trust closed a property swap agreement with JED whereby the Trust swapped certain of its interests in properties in the Ferrier area of Alberta for interests of JED in common with the Trust in East Central Alberta, the Desan area of Northeast British Columbia and the Ricinus area of Alberta.  The swap was based on independent third party engineering evaluations and was effective July 1, 2006.  The transaction also resulted in the termination of the existing farmout, joint services agreements and the Agreement of Business Principles between the Trust and JED whereby the Trust had a right of first refusal on properties that JED owned and JED had the ability to farm-in on the Trusts undeveloped lands.  Concurrent with the swap, the Trust settled all amounts owing to JED.





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SUBSEQUENT EVENTS AND PROPOSED TRANSACTIONS



On February 21, 2007, the Trust entered into a purchase and sale agreement to purchase oil and natural gas properties from Petroflow for consideration of US$7.0 million.  The purchase is subject to the fulfillment of certain conditions.



RELATED PARTY TRANSACTIONS



During 2006 the Trust paid $813,000 (2005 - $350,000) to Macon Resources Ltd. (Macon), a company 100% owned by the Chief Executive Officer of the Trust, for management services provided by the Chief Executive Officer and the previous Chief Financial Officer.  The amounts have been recorded at the amounts agreed to by the related parties.  At December 31, 2006 $nil (December 31, 2005 - $84,000) was payable by the Trust to Macon.  During 2005, the Trust issued 400,000 trust unit options to Macon; the options have an exercise price of $23.96 per trust unit.  The options have a 5-year life and vest over a 3-year period.



During 2006 the Trust entered into a farmout agreement with Petroflow, a public oil and gas company, to fund 100% of the drilling and completion costs of the Oklahoma Assets undeveloped lands.  The Chief Executive Officer of the Trust owns, directly and indirectly, approximately 14% of the outstanding shares of Petroflow.  As at December 31, 2006, the Trust had US$1.5 million of receivables from Petroflow including $47,000 (US$ $40,000) related to processing fees charged to Petroflow.  The receivables relate to costs incurred by the Trust as a result of the operations of the properties.  The balances due are expected to be settled as part of the asset purchase discussed in note 22.



A director and an officer of the Trust have working interests in certain of the Oklahoma Assets.  As a result balances will be payable or receivable from these individuals as a result of the operations of these properties.  At December 31, 2006 no amounts were payable or receivable from the officer.  During 2006, an adjustment period on the Oklahoma Asset acquisition concluded.  As a result of the adjustment payment and the receivable balance related to the working interests, as noted above, the Trust owes the director $744,000 (US$638,000).



OFF BALANCE SHEET ARRANGEMENTS



There were no off balance sheet arrangements in 2006 or 2005 other than the operating leases discussed elsewhere in the MD&A.



TRUST UNIT INFORMATION



The Trust is capitalized through a combination of trust units and exchangeable shares of certain of its subsidiaries.  The Trust also has a unit option plan, restricted unit plan, performance unit plan and warrants to purchase trust units outstanding.  The following table outlines outstanding equity instruments:





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|                                              |  |                |                   |                  
|--------------------------------------------- |  | -------------- | ----------------- | -----------------
|Outstanding unit data(units / shares)         |  |               
|As at                                         |  | March 20, 2007 | December 31, 2006 | December 31, 2005
|Trust units                                   |  | 56,327,173     | 56,097,875        | 36,504,416       
|Exchangeable shares                           |  |                |                   |                  
|EEC exchangeable shares                       |  | -              | 16,337            | 348,146          
|RMG exchangeable shares                       |  | -              | -                 | 736,842          
|RMAC Series B exchangeable shares             |  | -              | 66,720            | 659,116          
|Trust unit options                            |  | 1,481,000      | 1,481,000         | 1,431,405        
|Restricted units                              |  | 407,125        | 423,855           | -                
|Performance units                             |  | 213,790        | 212,948           | -                
|Warrants                                      |  | 301,000        | 301,000           | 301,000          
|Convertible debentures ($1,000 per debenture) |  | 80,331         | 80,331            | -                



SENSITIVITIES



The Trust is exposed to the normal risks inherent within the oil and gas sector, including commodity price risk, foreign-currency rate risk, interest rate risk and credit risk.  The Trust manages its operations in a manner intended to minimize exposure, as described in note 15 to the consolidated financial statements.



Credit Risk

Credit risk is the risk of loss resulting from non-performance of contractual obligations by a customer or joint venture partner.  A substantial portion of the Trusts accounts receivable are with customers in the energy industry and are subject to normal industry credit risk.  The Trust assesses the financial strength of its customers and joint venture partners through regular credit reviews in order to reduce the risk of non-payment.



Foreign Exchange Risk

The Trust is exposed to market risk from changes in the exchange rate between U.S. and Canadian dollars.  For the Trusts Canadian operations, the price we receive for oil and natural gas production is based on a benchmark expressed in U.S. dollars, which is the standard for the oil and natural gas industry worldwide.  However, operating expenses, drilling expenses and general overhead expenses are paid in Canadian dollars.  The Trusts US operations receive revenue in U.S. dollars as well as pay the operating expenses, drilling expenses and general overhead expenses in U.S. dollars. Monthly distributions are paid on a value expressed in U.S. dollars.  Within the Trusts bank indebtedness balance, $78.1 million (US$ 67.0 million) is denominated in U.S. dollars.



Changes to the exchange rate between U.S. and Canadian dollars can adversely affect the Trust.  When the value of the U.S. dollar increases, the Trust receives higher revenue and when the value of the U.S. dollar declines, the Trust receives lower revenue on the same amount of production sold at the same prices.  A change of $0.01 in the U.S. to Canadian dollar would impact the Trusts earnings by approximately $1.3 million and our cash provided by operating activities by $2.8 million.



Commodity Price Risk

The Trusts financial condition, results of operations and capital resources are highly dependent upon the prevailing market prices of oil and natural gas.  These commodity prices are subject to wide fluctuations and market uncertainties due to a variety of factors that are beyond the Trusts control.  Factors influencing oil and natural gas prices include the level of global demand for crude oil, the foreign supply of oil and natural gas, the establishment of and compliance with production quotas by oil exporting countries, weather conditions which determine the demand for natural gas, the price and availability of alternative fuels and overall economic conditions.  It is impossible to predict future oil and natural gas prices with any degree of certainty.  Sustained weakness in oil and natural gas prices may adversely affect the Trusts financial condition and results of operations, and may also reduce the amount of oil and natural gas reserves that the Trust can produce economically.  Any reduction in the Trusts oil and natural gas reserves, including reductions due to price fluctuations, can have an adverse affect on the Trusts ability to obtain capital for our development activities.  Similarly, any improvements in oil and natural gas prices can have a favorable impact on the Trusts financial condition, results of operations and capital resources.  If the WTI oil price were to change by US$1.00 per bbl, the impact on earnings would be approximately $1.3 million and the impact on cash flow would be approximately $2.0 million.  If natural gas prices were to change by US$0.50 per mcf, the impact on earnings would be approximately $6.0 million and the impact on cash provided by operating activities would be approximately $9.2 million.



The Trust uses financial derivatives and physical sales contracts to mitigate a portion of oil and natural gas price risk.  While the use of these derivative arrangements limits the downside risk of price declines, such use may also limit any benefits that may be derived from price increases.



Interest Rate Risk

Interest rate risk exists principally with respect to indebtedness that bears interest at floating rates.  At December 31, 2006, the Trust had $187.7 million of indebtedness bearing interest at floating rates.  If interest rate were to change by one full percentage point, the net impact on earnings would be approximately $1.2 million and the net impact on our cash provided by operating activities would be approximately $1.9 million.



Summarized below are the Trusts sensitivities to various risks, based on its 2006 operations:



|                                                           |                                   |          
|---------------------------------------------------------- | --------------------------------- | ---------
|Sensitivity                                                | Estimated 2006 Impact On: (000s)
|                                                           | Net Earnings                      | Cash Flow
|Crude oil  US$1.00/bbl change in WTI                      | $1,291                            | $1,970   
|Natural gas  US$0.50/mcf change                           | $6,040                            | $9,222   
|Foreign exchange - $0.01 change in U.S. to Canadian dollar | $1,311                            | $2,829   
|Interest rate  1% change                                  | $1,229                            | $1,877   



MANAGEMENTS EVALUATION OF DISCLOSURE CONTROLS AND PROCEDURES



Disclosure Controls and Procedures



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



Internal Controls over Financial Reporting



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



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



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



Changes to Internal Controls and Procedures for Financial Reporting



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



CRITICAL ACCOUNTING ESTIMATES



The Trust continues to evolve and document its management and internal reporting systems to provide assurance that accurate, timely internal and external information is gathered and disseminated.  The Trusts financial and operating results incorporate certain estimates including:

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

b) estimated capital expenditures on projects that are in progress;

c) estimated depletion, depreciation and accretion that are based on estimates of oil and gas reserves, which the Trust expects to recover in the future;

d) estimated value of asset retirement obligations that are dependent upon estimates of future costs and timing of expenditures; and

e) estimated future recoverable value of property, plant and equipment and goodwill.



NEW ACCOUNTING PRONOUNCEMENTS



In 2005, the CICA issued Handbook section 1530  Comprehensive Income, 3855  Financial Instruments: Recognition and Measurement, 3861  Financial Instruments: Disclosure and Presentation and 3865 -Hedges which are effective for fiscal years beginning on or after October 1, 2006.  These sections will be effective for the Trust commencing January 1, 2007.  Under these new standards all financial assets are measured at fair value with the exception of loans, receivables and investments that are intended to be held until maturity.  All financial liabilities are measured at fair value when they are either derivative or held for trading.  Gains and losses on financial instruments measured at fair value will be recognized in earnings periods in which they occur, with the exception of gains and losses related to financial assets available for sale and financial instruments for which hedge accounting is applied.  Unrealized gains and losses on qualified hedging instruments and financial assets available for sale are recorded to other comprehensive income and reclassified to earnings when ultimately realized.  Other comprehensive income and its components will be required disclosures under the new sections.



The Trust believes that under the new standards fixed-price commodity contracts will be recognized as non-financial derivatives with the fair value included in the balance sheet and the difference in fair values being recorded in net earnings.  The fair value determined will be recorded as a financial asset or liability on the balance sheet on January 1, 2007.  The Trust is currently assessing other potential impacts of implementing these new sections.







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ADDITIONAL INFORMATION



Additional information relating to Enterra Energy Trust, including our Annual Information Forms and Annual Reports, can be found on SEDAR at www.sedar.com, on EDGAR at www.sec.gov/edgar.shtml, as well as on the Trust's website at www.enterraenergy.com.



|              |                                                       |                            
|------------- | ----------------------------------------------------- | ---------------------------
|ABBREVIATIONS |                                                      
|bbl           | barrel of oil                                        
|bbls/day      | barrels of oil per day                               
|mcf           | thousand cubic feet of natural gas                   
|mcf/day       | thousands of cubic feet of natural gas per day       
|NGL           | natural gas liquids                                  
|boe           | barrels of oil equivalent                            
|              |                                                       | (6 mcf equivalent to 1 bbl)
|mboe          | thousands of barrels of oil equivalent               
|boe/day       | barrels of oil equivalent per day                    
|GJ            | Gigajoule                                            
|mmbtu         | millions of British Thermal Units                    
|CICA          | Canadian Institute of Chartered Accountants          
|GAAP          | Canadian Generally Accepted Accounting Principles    
|Cdn$          | Canadian dollars                                     
|US$           | United States dollars                                
|WTI           | West Texas Intermediate (Oil reference price)        
|AECO          | Natural gas reference price in Alberta               
|Nymex         | New York Mercantile Exchange                         
|Q1            | first quarter of the year - January 1 to March 31    
|Q2            | second quarter of the year - April 1 to June 30      
|Q3            | third quarter of the year - July 1 to September 30   
|Q4            | fourth quarter of the year - October 1 to December 31
|mbbl          | thousand barrels of oil                              
|mmcf          | millions of cubic feet of natural gas per day        
|mmbtu/day     | millions of British Thermal Units per day            
|Mwh           | megawatt-hour