|                                     |  |  |  |  | 
|------------------------------------ |  |  |  |  | 
|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, 2007.  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, 2007.  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 31, 2008.



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 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 on the 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 business and financial performance.  Moreover, the Trust operates in a very competitive and rapidly changing business 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 its 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 provide assurance 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 terms funds from operations and netback, which are non-GAAP terms.  The Trust uses these measures to help evaluate its performance.  The Trust considers funds from operations a key measure for the ability of the Trust to repay debt 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 performance.  The Trust considers netback a key measure for the ability of the Trust to analyze its operations.  The term should not be considered as an alternative to, or more meaningful than, net loss as determined in accordance with Canadian GAAP as an indicator of performance. Funds from operations and netback, 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 and of netback to net loss 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



Background



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 head office of the Trust is located in Calgary, Alberta and its United States office is located in Carney, Oklahoma.



The Trust portfolio of crude oil, natural gas liquids and natural gas interests is geographically diversified with producing properties located principally in Alberta, British Columbia, Saskatchewan and Oklahoma. Average production for 2007 of 12,428boe/day was comprised of approximately 62% natural gas and 38% crude oil and natural gas liquids.



Current Focus of the Trust



Circumstances in 2007 that have resulted in the current suspension of Trust distributions are also causing a review of the key strategies of Enterra.  A primary goal for 2008 is the reduction of debt with the long term goal to improve the balance sheet.  At the same time, select capital reinvestment projects thought to have the best performance on a near term basis are being pursued and to the extent possible, production rates and reserve values are being preserved.  It is not anticipated that production and reserves values can be held flat with the current capital budget of $30.0 million for 2008.  Cost reduction at operating and overhead levels will be important to achieving both debt reduction and capital reinvestment goals.



Distributions to Unitholders



For the first eight months of 2007, the Trust had a strategy to deliver monthly cash distributions to its unitholders of 60% to 70% of funds from operations.  However, in September 2007 the Trust suspended its monthly distributions in order to redirect its cash flow to the repayment of debt.  As required by the September 28, 2007 amended credit facilities, the distributions were to be suspended until at least March 31, 2008.  Subsequently in December 2007 the board of directors determined to further suspend distributions until at least November 20, 2008 and this suspension became a term of the further amended credit facility effective December 18, 2007.  The curtailment of distributions has and will allow the redirection of cash flow to debt reduction, while maintaining a conservative capital reinvestment program for 2008.



Management Turnover in 2007



The Trust experienced significant turnover in key management positions during the year.  In particular, Enterra replaced its Chief Financial Officer, Vic Roskey and its Chief Operating Officer Kim Booth for U.S. operations in Q4.  Also, President and Chief Executive Officer Keith Conrad retired in December 2007 and subsequently stepped down as a director in February 2008.  With the exception of replacing Mr. Conrad, all key positions have been filled.



In October 2007, Enterra experienced the resignation of two independent directors.  These positions were filled in December 2007 and February 2008.



These consolidated financial statements have been prepared on a going concern basis in accordance with Canadian generally accepted accounting standards.  The going concern basis of presentation assumes that the Trust will continue its operations for the foreseeable future and be able to realize its assets and discharge its liabilities and commitments in the normal course of business.







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The debt agreements of the Trust currently require that borrowings under the second-lien facility, which is currently at $29.1 million, (see note 8) be reduced to $28.0 million by June 30, 2008.  Furthermore, the Trust must make interest payments on its convertible debentures (see note 11) of approximately $4.9 million on June 30, 2008.  Per the relevant agreements, the Trust cannot use cash flow from operations to fund the required debt and interest repayments.  Therefore, the Trust must use proceeds from asset dispositions or the issuance of new equity or new borrowings to make the required payments.  If the Trust is not able to meet these commitments by June 30, 2008 then the going concern assumption may not be appropriate and adjustments to the carrying values of assets and liabilities, the reported revenue and expenses, and the balance sheet classifications used may be necessary.



Management believes that they have several options available to meet these commitments including; renegotiating these cash restrictions with the banking syndicate and funding the payments through cash flow or refinancing the entire bank syndicate debt with a debt facility with more flexible terms.  Management expects to have this issue resolved early in Q2 2008.



Business Strategy During 2007



The goal of Enterra has been to generate returns for its unitholders from steady and consistent increases in reserves, production and funds from operations per trust unit.  To achieve that goal the Trust has pursued a three-point strategy as follows:



Organic Growth

The Trust currently targets investment in the large portfolio of lower-risk development opportunities it has identified within its existing asset base.  The individual nature and number of opportunities varies across the 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 is generally within the control of the Trust.  As a method of countering natural production declines and potentially growing reserve values, the Trust believes that investing in such projects is in the long-term interest of unitholders.



Accretive Acquisitions

Corporate and property acquisitions can be an effective means of consolidating assets, improving efficiencies in existing core areas or adding new core areas.  The ability to make material accretive acquisitions is subject to the business environment prevailing at any particular time and the availability of capital beyond the internally generated cash flow of the Trust.



Strategic Partnerships

The Trust has actively sought 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.



In pursuing the strategies, Enterra has sought to manage the risk to unitholders by a geographically diversified production base, by maintaining a reasonable balance between liquids and gas production, operatorship and ownership of associated infrastructure, and maintaining a multi-year inventory of lower-risk development projects.



STRATEGIC ACQUISITION



On April 30, 2007, the Trust acquired all of the issued and outstanding shares of Trigger Resources Ltd. (Trigger Resources) for total consideration of $63.3 million.







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Trigger Resources was a private company with operations in heavy oil and gas exploration and development in western Saskatchewan.  The acquisition increased the critical mass and footprint in the region and has been accretive to production, cash flow and reserves per unit.  Trigger Resources production at the date of acquisition was approximately 2,400 boe/day consisting of 1,400 bbls/day of oil and 6,000 mcf/day of natural gas.  Its properties generally have 100% working interest with year round access and enjoy relatively low operating costs.  The acquisition also provided the Trust with an additional 66,000 net undeveloped acres with significant drilling and development potential.



In April 2007, the Trust issued $40 million of 8.25% convertible debentures that mature on June 30, 2012 and $29.2 million of trust units (4,945,000 trust units).  The net proceeds from the issuances were used to finance the acquisition of Trigger Resources.



OVERALL PERFORMANCE



Average production increased by 1% to 12,428 boe/day in 2007 from 12,352 boe/day in 2006.  The Trust exited the year with sales volumes of approximately 11,457 boe/day; 8% lower than the 2006 exit rate of 12,442 boe/day.



Overall, oil prices received by the Trust in 2007 were less than in 2006 despite the increase in oil prices in the fourth quarter.  Gas prices received were consistent with 2006.  The reduced prices received by the Trust combined with relatively flat production resulted in total revenues, prior to mark-to-market hedging adjustment decreasing 4% from 2006.  Operating expenses increased 28% in 2007 to $14.29/boe compared to $11.17/boe in 2006.  G&A expenses increased 20% in 2007 to an average of $5.41/boe from $4.52/boe in 2006.  Interest expenses declined in 2007, due to the combined effect of lower average borrowings and a lower average interest rate, decreasing 15% to $22.6 million in 2007 compared to $26.7 million in 2006. The overall impact was that funds from operations decreased by 18% to $70.5 million in 2007 from $86.1 million in 2006.



In January and February of 2008, the Trust disposed of certain Canadian oil and gas assets for net cash proceeds of $39.9 million.  The Trust anticipates further net proceeds of $1.3 million upon the closing of an additional property sale.  The majority of these proceeds were directed to debt repayment.



Proved and probable reserves decreased by 2% from the end of 2006 to the end of 2007 reflecting the acquisition of Trigger Resources and additional discoveries resulting from the 2007 drilling program and offset by reserves relating to properties that were held for sale at year end and 2007 production.



Over the course of 2007, the Trust paid distributions of $39.5 million to unitholders or US$0.60/unit, representing decreases of 56% and 67% respectively, compared to total distributions of $90.5 million or US $1.86/unit in 2006.  Distributions were suspended on September 17, 2007 and will remain suspended through at least November 2008 as part of the debt reduction strategy of the Trust.







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|                                                                                            |                                |           |             |            |          |       
|------------------------------------------------------------------------------------------- | ------------------------------ | --------- | ----------- | ---------- | -------- | ------
|Summary of Financial and Operating Results(in thousands except for volumes and percentages)
|                                                                                            | Three months ended
December 31 |           | Years ended |           
|2007                                                                                        | 2006                           | Change    | 2007        | 2006       | Change  
|Revenues (1)                                                                                | $44,470                        | $55,855   | (20%)       | $207,036   | $244,220 | (15%) 
|Average sales (boe/day)                                                                     | 12,174                         | 11,905    | 2%          | 12,428     | 12,352   | 1%    
|Exit sales rate (boe/day)                                                                   | 11,457                         | 12,442    | (8%)        | 11,457     | 12,442   | (8%)  
|Cash provided by operating activities                                                       | $2,215                         | $26,163   | (92%)       | $76,844    | $64,485  | 19%   
|Funds from operations (2)                                                                   | $12,110                        | $9,558    | 27%         | $70,463    | $86,117  | (18%) 
|Net loss                                                                                    | $(39,481)                      | $(69,189) | 43%         | $(142,036) | (64,239) | (121%)
|Net loss per trust unit - basic                                                             | $(0.64)                        | $(1.40)   | 54%         | $(2.38)    | $(1.46)  | (63%) 
|Weighted average number of trust units outstanding - basic                                  | 61,433                         | 49,415    | 24%         | 59,767     | 44,142   | 35%   
|Average price per barrel of oil                                                             | $64.23                         | $55.64    | 15%         | $61.09     | $62.13   | (2%)  
|Average price per mcf of natural gas                                                        | $6.20                          | $7.91     | (22%)       | $7.04      | $7.53    | (7%)  
|Operating expenses per boe                                                                  | $15.66                         | $16.04    | (2%)        | $14.29     | $11.17   | 28%   
|Netback (3) per boe                                                                         | $10.63                         | $9.46     | 12%         | $14.66     | $19.50   | (25%) 



(1)

Prior year restated to conform to presentation adopted in current year

(2)

Funds from operations are a non-GAAP financial measure.  See non-GAAP financial measures section of the MD&A for a reconciliation of this measure

(3)

Netback is 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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QUARTERLY FINANCIAL INFORMATION

|                                       |           |           |          |           |            |          |           |          |  | 
|-------------------------------------- | --------- | --------- | -------- | --------- | ---------- | -------- | --------- | -------- |  | 
|                                       | 2007      | 2006      |         
|                                       | Q4        | Q3        | Q2       | Q1        | Q4         | Q3       | Q2        | Q1       | 
|Revenues                               | $44,470   | $55,685   | $62,871  | $44,010   | $56,043    | $73,335  | $67,313   | $47,717  | 
|Loss before taxes and NCI              | $(55,618) | $(41,227) | $(8,173) | $(72,968) | $(101,242) | $(6,879) | $(10,579) | $(3,149) | 
|Net earnings (loss)                    | $(39,481) | $(47,681) | $7,878   | $(62,752) | $(69,189)  | $3,000   | $(296)    | $2,248   | 
|Net earnings (loss) per unit           |           |           |          |           |            |          |           |          | 
|basic and diluted                      | $(0.64)   | $(0.78)   | $0.13    | $(1.12)   | $(1.40)    | $0.07    | $(0.01)   | $0.06    | 
|Distributions declared per unit  (US$) | -         | $0.12     | $0.18    | $0.18     | $0.36      | $0.36    | $0.54     | $0.54    | 



The decreases in revenue in Q4 2007, Q3 2007, Q1 2007 and Q4 2006 were due to a combination of lower volumes, lower realized prices and reductions in the mark-to-market value of the derivatives of the Trust.  The decreases in distributions over the period reflect the changes in revenues as well as the decision by the Trust to reduce the level of its distributions to reduce debt.  The significant net losses in Q3 2007, Q1 2007 and Q4 2006 were due to ceiling test and goodwill impairment losses that were recorded in the periods.



RESULTS OF OPERATIONS



Average production for 2007 increased 1% to 12,428 boe/day from 12,352 boe/day in 2006.  Positive contributions to production during the year include the acquisition of Trigger Resources in Q2, start-up of a prolific Leduc well at Ricinus in late 2006, and production additions associated with our drilling programs in Oklahoma and Canada.  Offsetting these additions were natural declines, weather-related disruptions in Oklahoma due to record rainfalls for the year and a severe ice storm in December, drilling and production difficulties at our Primate field, and operational delays in tying in certain wells in Oklahoma due to equipment shortages.



Average production during 2007 consisted of 4,698 bbls/day of oil and natural gas liquids (NGL) and 46,378 mcf/day of natural gas, resulting in a mix of 38% oil and NGL and 62% natural gas.  At December 31, 2007 the Trust had an exit production rate of 11,457 boe/day.



Volumes for Q4 2007 averaged 12,174 boe/day up 2% compared to the average for Q4 2006 of 11,905 boe/day, but 5% below the average for Q3 2007 of 12,798 boe/day.  Production at the exit of Q4 2007 was 6% below the average for the quarter.  Factors contributing to the reduction in the 2007 exit rate included the sale in December of certain non-operated assets (166 boe/day) and weather-related issues in Oklahoma (350 boe/day) in addition to operational issues over year end at a prolific Leduc well in the Ricinus area (120 boe/day).  All of the operational issues have since been resolved.



In 2007, the Trust participated in the drilling of 32 (11.8 net) wells; 13 (7.5 net) in Canada and 19 (4.3 net) in Oklahoma.  All wells in Oklahoma were drilled by a joint venture partner under an area farmout agreement that resulted in the joint venture partner paying 100% of the drilling and completion costs in exchange for 70% working interest.  Overall, the drilling in Canada and Oklahoma resulted in 23 (5.4 net) gas wells, 8 (5.4 net) oil wells and one well (1.0 net) that was drilled and abandoned, resulting in a success rate of 97%.









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Canadian Operations



Production in Canada for the year was relatively unchanged compared to 2006.  Volumes averaged 3% lower at 7,387 boe/day in 2007 compared to 7,578 boe/day in 2006.  Gas represented approximately 45% of total production in 2007 versus 40% in 2006 on a boe basis.  For Q4 2007, volumes increased 7% to 7,512 boe/day compared to the average of 6,990 boe/day during Q4 2006.  The average for Q4 2007 is 4% lower than in Q3 2007 of 7,806 boe/day.  The 2007 exit rate for Canada was 7,167 boe/day.



The first quarter of 2007 marked the first wells drilled by the newly assembled technical and operations team at Enterra.  In February, a successful oil well was drilled at Halkirk and an existing well at Desan was re-entered as Enterra drilled a new lateral into a more prolific part of the reservoir.  The Desan well significantly contributed to our understanding of the Jean Marie play and sets the stage for future development plans in the area.  During Q2, the Trigger Resources acquisition added both heavy oil and natural gas production to the portfolio of assets and provided additional geographic diversification with significantly more production in Saskatchewan.  Additionally in Q2, Enterra executed a successful four well drilling program in the Primate area; all of which were on stream in Q3.  Drilling continued in the third quarter with another well in the Primate area.  Our technical team continues to refine, develop and prioritize our prospect inventory in Canada.



U.S. Operations



Production in the United States averaged a total of 5,041 boe/day during 2007, of which 87% was natural gas.Production increased by 6% from 4,774 boe/day in 2006.  Volumes in the fourth quarter of 2007 in the US averaged 4,663 boe/day or 5% less than Q4 2006 and 7% less than the average for Q3 2007.



Of the 19 (4.3 net) gas wells drilled in Oklahoma in 2007, 14 of the wells were on production at the end of 2007.  To the end of 2007, the joint venture partner of Enterra has drilled a total of 31 gas wells in the Oklahoma project area and had 3 drilling rigs operating continuously during the last half of 2007.  All of the wells drilled in the U.S. on behalf of the Trust during the year were successful.



|                                |                                |        |                          |        |        |      
|------------------------------- | ------------------------------ | ------ | ------------------------ | ------ | ------ | -----
|Production                     
|                                | Three Months ended
December 31 |        | Years  ended
December 31 |       
|2007                            | 2006                           | Change | 2007                     | 2006   | Change
|Daily sales volumes  average   |                                |        |                          |        |        |      
|Oil & NGL (bbls/day)            | 4,585                          | 4,774  | (4%)                     | 4,698  | 5,126  | (8%) 
|Natural gas (mcf/day)           | 45,538                         | 42,788 | 6%                       | 46,378 | 43,358 | 7%   
|Total (boe/day)                 | 12,174                         | 11,905 | 2%                       | 12,428 | 12,352 | 1%   
|                                |                                |        |                          |        |        |      
|Daily sales volumes - exit rate |                                |        |                          |        |        |      
|Oil & NGL (bbls/day)            | 3,952                          | 4,758  | (17%)                    | 3,952  | 4,758  | (17%)
|Natural gas (mcf/day)           | 45,031                         | 46,105 | (2%)                     | 45,031 | 46,105 | (2%) 
|Total (boe/day)                 | 11,457                         | 12,442 | (8%)                     | 11,457 | 12,442 | (8%) 
|                                |                                |        |                          |        |        |      
|Sales volumes mix by product    |                                |        |                          |        |        |      
|Oil & NGL                       | 38%                            | 40%    |                          | 38%    | 41%    |      
|Natural gas                     | 62%                            | 60%    |                          | 62%    | 59%    |      
|                                | 100%                           | 100%   |                          | 100%   | 100%   |      









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|                                |                                      |        |                              |        |        | 
|------------------------------- | ------------------------------------ | ------ | ---------------------------- | ------ | ------ | 
|Production by Geographic Area  
|                                | Three Months Ended
December 31, 2007 |        | Year Ended
December 31, 2007 |       
|Canada                          | U.S.                                 |        | Canada                       | U.S.   |       
|Daily sales volumes  average   |                                      |        |                              |        |        | 
|Oil & NGL (bbls/day)            | 4,080                                | 504    |                              | 4,064  | 634    | 
|Natural gas (mcf/day)           | 20,589                               | 24,951 |                              | 19,933 | 26,444 | 
|Total (boe/day)                 | 7,512                                | 4,663  |                              | 7,387  | 5,041  | 
|                                |                                      |        |                              |        |        | 
|Daily sales volumes - exit rate |                                      |        |                              |        |        | 
|Oil & NGL (bbls/day)            | 3,584                                | 368    |                              | 3,584  | 368    | 
|Natural gas (mcf/day)           | 21,501                               | 23,530 |                              | 21,501 | 23,530 | 
|Total (boe/day)                 | 7,167                                | 4,290  |                              | 7,167  | 4,290  | 
|                                |                                      |        |                              |        |        | 
|Sales volumes mix by product    |                                      |        |                              |        |        | 
|Oil & NGL                       | 54%                                  | 11%    |                              | 55%    | 13%    | 
|Natural gas                     | 46%                                  | 89%    |                              | 45%    | 87%    | 
|                                | 100%                                 | 100%   |                              | 100%   | 100%   | 



COMMODITY PRICING



West Texas Intermediate (WTI) is a standard benchmark for the price of oil and is expressed in U.S. dollars per barrel.  The price of natural gas in the United States is benchmarked on the New York Mercantile Exchange (NYMEX) and expressed in U.S. dollars per million British Thermal Units (mmbtu).  In Western Canada the benchmark is the price at the AECO hub and is priced in Canadian dollars per gigajoule (GJ).  For the purposes of financial reporting, the Trust expresses its realized prices for oil and gas in Canadian dollars.



Oil prices increased 9% from 2006, averaging US$72.34/bbl in 2007.  The effect of the increase was off-set by a 6% year over year weakening of the U.S. dollar against the Canadian dollar, with the exchange rate rising to an average of US$0.93 per Canadian dollar in 2007 from an average of US$0.88 in 2006.  In the fourth quarter of 2007 WTI increased 51% to US$90.68/bbl compared to US$60.21/bbl in Q4 of 2006. The price increase was off-set by the strengthening of the Canadian dollar.  The Canadian dollar rose from an average of $0.88 against the US dollar in Q4 of 2006 to an average of $1.02 in Q4 of 2007 which represents a 16% increase.



Natural gas prices on the NYMEX decreased US$0.34/mmbtu or 5%, from 2006, averaging US$6.92/mmbtu in 2007.  In Canada, AECO pricing was consistent with 2006 levels, averaging $6.55/GJ.



In Q4 2007, U.S. prices on the NYMEX were up from Q4 2006.  Prices averaged US$7.03/mmbtu in Q4 2007 compared to US$6.62 in Q4 2006.  AECO pricing was down by 11% in Q4 2007 to $6.14/mcf compared to $6.91/mcf in Q4 2006.



The 2007 average price received for oil, net of hedge settlements, was down 2% to $61.09/bbl from $62.13/bbl in 2006.  The 2007 average price received for natural gas, net of hedge settlements, was down 7% to $7.04/mcf from $7.53/mcf in 2006.



In Q4, while oil prices generally rose, the heavy oil to light oil price differential widened in the period and reduced the overall realization on oil production.







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|                                                           |                                |        |                         |        |        |      
|---------------------------------------------------------- | ------------------------------ | ------ | ----------------------- | ------ | ------ | -----
|Pricing                                                   
|                                                           | Three Months ended
December 31 |        | Years ended
December 31 |       
|2007                                                       | 2006                           | Change | 2007                    | 2006   | Change
|Pricing benchmarks                                         |                                |        |                         |        |        |      
|WTI (US$/bbl)                                              | 90.68                          | 60.21  | 51%                     | 72.34  | 66.22  | 9%   
|Average exchange rate: US$ to Cdn$1.00                     | 1.02                           | 0.88   | 16%                     | 0.93   | 0.88   | 6%   
|WTI (Cdn$/bbl)                                             | 88.90                          | 68.42  | 30%                     | 77.78  | 75.25  | 3%   
|AECO monthly index (Cdn$/GJ)                               | 6.14                           | 6.91   | (11%)                   | 6.55   | 6.53   | -    
|NYMEX (US$/mmbtu)                                          | 7.03                           | 6.62   | 6%                      | 6.92   | 7.26   | (5%) 
|Average prices received                                    |                                |        |                         |        |        |      
|Oil  (Cdn$ per bbl)                                        | 67.89                          | 55.64  | 22%                     | 61.84  | 62.54  | (1%) 
|Natural gas (Cdn$ per mcf)                                 | 5.88                           | 7.12   | (17%)                   | 6.60   | 6.70   | (2%) 
|Oil commodity contract settlements (Cdn$ per bbl)          | (3.66)                         | -      | -                       | (0.75) | (0.41) | (83%)
|Natural gas commodity contract settlements  (Cdn$ per mcf) | 0.32                           | 0.79   | (60%)                   | 0.44   | 0.83   | (47%)
|Combined oil and NGL  (Cdn$ per bbl)                       | 64.23                          | 55.64  | 15%                     | 61.09  | 62.13  | (2%) 
|Combined natural gas (Cdn$ per mcf)                        | 6.20                           | 7.91   | (22%)                   | 7.04   | 7.53   | (7%) 
|Total (1) (Cdn$ per boe)                                   | 47.36                          | 50.48  | (6%)                    | 49.34  | 51.82  | (5%) 

(1) Includes NGL



Management has a policy allowing hedging up to 50% of its 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 downward swings in commodity prices.







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At December 31, 2007, the following financial derivatives and fixed price contracts were outstanding:



|                      |                 |                           |                  |                                  
|--------------------- | --------------- | ------------------------- | ---------------- | ---------------------------------
|Derivative Instrument | Commodity       | Price                     | Volume (per day) | Period                           
|Collar                | Gas             | 8.00 by 12.00
(Cdn$/GJ)   | 10,000 GJ        | November 1, 2007  March 31, 2008
|Floor                 | Gas             | 8.00
(US$/mmbtu)          | 10,000 mmbtu     | November 1, 2007  March 31, 2008
|Collar                | Gas             | 7.00 by 11.00
(US$/mmbtu) | 3,000 mmbtu      | November 1, 2007  March 31, 2008
|Fixed                 | Gas             | 7.95 (US$/mmbtu)          | 2,000 mmbtu      | April 1, 2008  October 31, 2008 
|Collar                | Gas             | 6.50 by 10.50
(US$/mmbtu) | 3,000 mmbtu      | April 1, 2008  October 31, 2008 
|                      |                 |                           |                  |                                  
|Collar                | Oil             | 55.00 by 75.25
(US$/bbl)  | 500 bbl          | January 1, 2008  June 30, 2008  
|Collar                | Oil             | 62.00 by 78.00
(US$/bbl)  | 500 bbl          | January 1, 2008  June 30, 2008  
|Collar                | Oil             | 62.00 by 75.50
(US$/bbl)  | 500 bbl          | January 1, 2008  March 31, 2008 
|Collar                | Oil             | 62.00 by 75.60
(US$/bbl)  | 500 bbl          | April 1, 2008  June 30, 2008    
|Collar                | Oil             | 62.00 by 80.50
(US$/bbl)  | 500 bbl          | July 1, 2008  December 31, 2008 
|Collar                | Oil             | 62.00 by 80.05
(US$/bbl)  | 500 bbl          | July 1, 2008  December 31, 2008 
|                      |                 |                           |                  |                                  
|Fixed purchase        | Power
(Alberta) | 62.90
(Cdn$/Mwh)          | 72 Mwh           | July 1, 2007  December 31, 2009 



As at December 31, 2007 the above commodity contracts had a net mark-to-market liability position of $5.2 million.  Subsequent to December 31, 2007, the following financial derivatives and fixed price contracts were entered into:



|                      |           |                                  |                  |                                    
|--------------------- | --------- | -------------------------------- | ---------------- | -----------------------------------
|Derivative Instrument | Commodity | Price                            | Volume (per day) | Period                             
|Collar                | Oil       | 72.00 by 91.50
(US$/bbl)         | 1,000 bbl        | January 1, 2009  December 31, 2009
|Remove Ceiling        | Oil       | 78.00
(US$/bbl)                  | 500 bbl          | February 1, 2008  June 30, 2008   
|Collar                | Gas       | 6.00 by 7.25 by 9.75
(US$/mmbtu) | 5,000 mmbtu      | April 1, 2008  October 31, 2008   
|Fixed                 | Gas       | 7.84 (Cdn$/GJ)                   | 2,000 GJ         | April 1, 2008  October 31, 2008   









---



REVENUES



Natural gas revenue was consistent with 2006 at $119.1 million.  Natural gas production volumes for 2007 increased by 1% however this was offset by a 7% decrease in the sales price of natural gas received for 2007.  For oil and NGL, the 8% revenue decrease from 2006 was consistent with an 8% decrease in production volumes from 2006, while the oil price received decreased slightly.  Overall, in 2007 revenues decreased by $37.2 million or 15% compared to 2006 with much of the decrease attributable to rising oil prices that resulted in an unrealized mark-to-market loss of $16.8 million at year-end compared to a mark-to-market gain at the end of 2006 of $10.6 million.



Revenue in Q4 2007 decreased 20% to $44.5 million from $55.9 million in 2006.  Similar to the full year results, the decrease in revenue was largely attributable to the unrealized mark-to-market loss on the financial instruments.



|                                                               |                                |         |                         |          |          |       
|-------------------------------------------------------------- | ------------------------------ | ------- | ----------------------- | -------- | -------- | ------
|Revenues(in thousands except for percentages)                 
|                                                               | Three Months ended
December 31 |         | Years ended December 31 |         
|2007                                                           | 2006                           | Change  | 2007                    | 2006     | Change  
|Revenues(1)                                                    |                                |         |                         |          |          |       
|Oil and NGL                                                    | $27,089                        | $24,140 | 12%                     | 104,753  | $114,481 | (8%)  
|Natural gas                                                    | 25,959                         | 31,156  | (17%)                   | 119,075  | 119,111  | -     
|                                                               | 53,048                         | 55,296  | (4%)                    | 223,828  | 233,592  | (4%)  
|Unrealized mark-to-market gain/(loss) on financial instruments | (8,578)                        | 559     | (1,635%)                | (16,792) | 10,628   | (258%)
|Oil and natural gas revenues                                   | 44,470                         | $55,855 | (20%)                   | 207,036  | $244,220 | (15%) 

(1)  Prior year restated to conform to presentation adopted in current year









|                                                                |                                      |         |                              |          |         | 
|--------------------------------------------------------------- | ------------------------------------ | ------- | ---------------------------- | -------- | ------- | 
|Revenues by Geographic area(in thousands)                      
|                                                                | Three Months ended
December 31, 2007 |         | Year ended
December 31, 2007 |         
|Canada                                                          | U.S.                                 |         | Canada                       | U.S.     |        
|Revenues                                                        |                                      |         |                              |          |         | 
|Oil and NGL                                                     | $22,985                              | $4,104  |                              | $87,454  | $17,299 | 
|Natural gas                                                     | 12,046                               | 13,913  |                              | 51,390   | 67,685  | 
|                                                                | 35,031                               | 18,017  |                              | 138,844  | 84,984  | 
|Unrealized mark-to-market gains (loss) on financial instruments | (6,245)                              | (2,333) |                              | (10,439) | (6,353) | 
|Oil and natural gas revenues                                    | $28,786                              | $15,683 |                              | $128,405 | $78,631 | 



ROYALTIES



Royalties, which include Crown, freehold and overriding royalties and wellhead taxes, less Alberta Royalty Tax Credits (ARTC), vary depending on the jurisdiction, the volumes produced, total volumes sold and the price received for the sales. Overall, royalties decreased in 2007 compared to 2006 as a result of royalty rebates realized in the U.S.  The U.S. operations applied for, and received, a royalty rebate for its horizontal wells in the state of Oklahoma.  Enterra realized rebates of $3.2 million in 2007 for royalties paid in 2006 and 2007.  Enterra expects to receive the 6% rebate for all new horizontal wells drilled in Oklahoma for a time period of 48 months after each well is drilled.



In late October 2007, the Alberta provincial government announced a new oil and gas royalty regime to take effect January 1, 2009.  The government has provided some details of the proposed royalty regime, however discussions with industry are ongoing and legislation is still pending. The Trust will assess the net economic impact on its future financial performance and reserve values when the scheme is confirmed, however the overall impact is expected to be modest given preliminary estimates generated by the independent engineers of the Trust.  Overall at the end of December 2007, approximately 38% of Enterras production came from Alberta.







---



|                                                                   |                                |         |                         |         |         |     
|------------------------------------------------------------------ | ------------------------------ | ------- | ----------------------- | ------- | ------- | ----
|Royalties(in thousands except for percentages and per boe amounts)
|                                                                   | Three Months ended
December 31 |         | Years ended
December 31 |        
|2007                                                               | 2006                           | Change  | 2007                    | 2006    | Change 
|Royalties                                                          | $10,860                        | $11,196 | (3%)                    | $45,365 | $48,288 | (6%)
|As a percentage of revenues                                        | 20%                            | 20%     |                         | 20%     | 21%     |     
|Royalties per boe                                                  | $9.70                          | $10.22  | (5%)                    | $10.00  | $10.71  | (7%)



|                                                                                      |                                      |        |                              |         |         | 
|------------------------------------------------------------------------------------- | ------------------------------------ | ------ | ---------------------------- | ------- | ------- | 
|Royalties by Geographic Area(in thousands except for percentages and per boe amounts)
|                                                                                      | Three Months ended
December 31, 2007 |        | Year ended
December 31, 2007 |        
|Canada                                                                                | U.S.                                 |        | Canada                       | U.S.    |        
|Royalties                                                                             | $6,966                               | $3,894 |                              | $27,497 | $17,868 | 
|As a percentage of revenues                                                           | 20%                                  | 22%    |                              | 20%     | 21%     | 
|Royalties per boe                                                                     | $10.08                               | $9.08  |                              | $10.20  | $9.71   | 



OPERATING EXPENSES



In 2007, operating costs increased 28% to $14.29 per boe compared to $11.17 per boe in 2006.  In Q4 2007, operating costs decreased to $15.66/boe from $16.04/boe in Q4 2006.



Canadian operations experienced increased costs associated with regulatory compliance, increased well workover costs, and repair and environmental expenses associated with three pipeline failures in Canada.  Severe weather conditions increased costs and reduced production in Oklahoma as record spring and summer rain, were followed by a destructive ice storm in December.  U.S. operating costs expressed in Canadian dollars decreased in Q4 of 2006 primarily due to a gain in the U.S./Cdn$ exchange rate.



Canadian Assets



In Canada, 2007 average operating expense increased by 32% to $16.91 per boe versus $12.84 per boe in 2006.  Total operating expenses increased 28% in 2007 to $45.6 million from $35.5 million in 2006.  The Trigger Resources acquisition increased operating expenses by $3.8 million.  In Q4 2007, operating costs increased slightly to $19.45 per boe compared to $19.28 per boe in Q4 2006.



U.S. Assets



Operating expenses for the U.S. assets in 2007 increased to $10.45 per boe from a 2006 average of $8.52 per boe.  Q4 2007 operating expense decreased by 16% to $9.57 per boe from $11.43 per boe in Q4 2006 and decreased by 7% compared to Q3 2007 operating costs of $10.32 per boe.









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|                                                                            |                                |         |                         |         |         |    
|--------------------------------------------------------------------------- | ------------------------------ | ------- | ----------------------- | ------- | ------- | ---
|Operating Expenses(in thousands except for percentages and per boe amounts)
|                                                                            | Three months ended
December 31 |         | Years ended
December 31 |        
|2007                                                                        | 2006                           | Change  | 2007                    | 2006    | Change 
|Operating expenses                                                          | $17,545                        | $17,570 | -                       | $64,823 | $50,361 | 29%
|Operating expenses per boe                                                  | $15.66                         | $16.04  | (2%)                    | $14.29  | $11.17  | 28%





|                                                                                               |                                      |        |                              |         |         | 
|---------------------------------------------------------------------------------------------- | ------------------------------------ | ------ | ---------------------------- | ------- | ------- | 
|Operating Expenses by Geographic Area(in thousands except for percentages and per boe amounts)
|                                                                                               | Three months ended
December 31, 2007 |        | Year ended
December 31, 2007 |        
|Canada                                                                                         | U.S.                                 |        | Canada                       | U.S.    |        
|Operating expenses                                                                             | $13,440                              | $4,105 |                              | $45,600 | $19,223 | 
|Operating expenses per boe                                                                     | $19.45                               | $9.57  |                              | $16.91  | $10.45  | 



GENERAL AND ADMINISTRATIVE EXPENSES



General and administrative expenses (G&A) increased 20% in 2007 to $24.5 million from $20.4 million in 2006.   G&A per boe increased by 20% to $5.41 per boe in 2007 compared to $4.52 per boe in 2006.  The increase in general and administrative costs related primarily to an increase in personnel in 2007 from 2006 and increased consulting costs in Q3 and Q4 2007 related to the turnover of management and employees.  Of the $24.5 million, $0.4 million related directly to financing fees on the credit facilities amendments in Q4 2007.

Financing fees of $5.4 million were incurred in Q4 2006 on the settlement of the bridge loans and financial advisors related to the 2006 credit facilities which were separately disclosed.



|                                                                                             |                                |        |                          |         |         |    
|-------------------------------------------------------------------------------------------- | ------------------------------ | ------ | ------------------------ | ------- | ------- | ---
|General and Administrative Expenses(in thousands except for percentages and per boe amounts)
|                                                                                             | Three Months ended
December 31 |        | Years ended
 December 31 |        
|2007                                                                                         | 2006                           | Change | 2007                     | 2006    | Change 
|G&A expenses                                                                                 | $7,111                         | $7,608 | (7%)                     | $24,542 | $20,374 | 20%
|G&A per boe                                                                                  | $6.35                          | $6.95  | (9%)                     | $5.41   | $4.52   | 20%



INTEREST EXPENSE



Total interest expense decreased in 2007 by 15% to $22.6 million compared to the 2006 amount of $26.7 million. This is a combination of lower interest rates in 2007 from 2006 and a lower average debt balance offset by a full year of interest on the $80.3 million convertible debentures issued in late 2006 and the $40.0 million of convertible debentures issued in April 2007.



Enterra began 2007 with a bank indebtedness of $187.7 million which bore interest at bankers acceptance (BA) rates, Canadian or U.S. prime rates, or LIBOR plus applicable margins of nil to 1.65%.  Enterra issued convertible debentures of 138.0 million bearing interest at 8.00% on November 21, 2006 with a maturity date of December 31, 2011.  $80.3 million remained unconverted as at December 31, 2007.  $40.0 million of convertible debentures bearing interest at 8.25% were issued on April 28, 2007 with a maturity date of June 30, 2012.



For the majority of 2006, the debt balance ranged from $160.0 million to $350.0 million, making up a significant portion of the $25.9 million of interest expense on bank indebtedness, capital leases and notes payable for the year ended 2006.  This was comprised of a $110.0 million bridge loan bearing an average interest rate of 8% until November 2006 and US$200.0 million at an average interest rate of 10.0%.  The loans were mainly to fund the acquisition of the Oklahoma assets.  At November 21, 2006, these were replaced by credit facilities with the current bank syndicate, convertible debentures and trust units.







---





Interest expense of about $10.0 million on the convertible debentures reflects a full year of interest on the remaining unconverted balance of $80.3 million at 8% plus the $40.0 million of convertible debentures issued in April 2007 bearing interest at 8.25% to fund the purchase of Trigger Resources.  Total indebtedness including convertible debentures at the end of 2007 had a face value of $292.3 million compared to $268.5 million at the end of 2006.



Interest expense for convertible debentures in Q4 2007 increased by $2.0 million compared to Q4 2006.



|                                                                                |                                |        |                         |         |         |       
|------------------------------------------------------------------------------- | ------------------------------ | ------ | ----------------------- | ------- | ------- | ------
|Interest Expense(in thousands except for percentages and per boe amounts)      
|                                                                                | Three months ended
December 31 |        | Years ended
December 31 |        
|2007                                                                            | 2006                           | Change | 2007                    | 2006    | Change 
|Interest expense on bank indebtedness, capital lease, and notes payable         | $2,806                         | $7,739 | (64%)                   | $12,619 | $25,898 | (51%) 
|Interest expense on convertible debentures                                      | 2,823                          | 819    | 245%                    | 9,963   | 819     | 1,116%
|Interest expense                                                                | $5,629                         | $8,558 | (34%)                   | $22,582 | $26,717 | (15%) 
|Interest expense per boe on bank indebtedness, capital lease, and notes payable | $2.51                          | $7.07  | (65%)                   | $2.78   | $5.74   | (52%) 
|Interest expense per boe on convertible debentures                              | 2.52                           | 0.75   | 236%                    | 2.20    | 0.18    | 1,120%
|Interest expense per boe                                                        | $5.03                          | $7.81  | (36%)                   | $4.98   | $5.92   | (16%) 



DEPLETION, DEPRECIATION AND ACCRETION (DD&A)



DD&A expense decreased by 8% in 2007 to $124.4 million compared to $135.4 million in 2006 due to the lower property, plant and equipment values in relation to the reserve values.



At December 31, 2006, Enterra recorded a ceiling test impairment on its Canada and U.S. cost centers in the amount of $66.0 million.  At the end of Q1 2007 an additional provision of $2.1 million was necessary due to a ceiling test write down in the Canada cost center.  This charge was taken due to a reduction in the value of certain undeveloped lands and the incurrence of facility upgrade costs which did not result in additional reserve volumes.  In Q4 2007, an impairment of $24.2 million was required due to an additional ceiling test write down in the Canadian cost center.   This charge was the result of the fair value of the assets sold subsequent to year end being greater than the book value of those properties.



In the fourth quarter of 2007, DD&A expense excluding impairment decreased 10% to $32.5 million from $36.1 million in Q4 2006 due in part to the disposition of assets in Q4 2007 in the Princess area.



Ceiling test



Under Canadian GAAP, a ceiling test is applied to the carrying value of the property, plant and equipment and other assets. The carrying value is assessed to be recoverable when the sum of the undiscounted cash flows expected from the production of proved reserves, the lower of cost and market of unproved properties, and the cost of major development projects exceeds the carrying value. When the carrying value is not assessed to be recoverable, an impairment loss is recognized to the extent that the carrying value of assets exceeds the sum of the discounted cash flows expected from the production of proved and probable reserves, the lower of cost and market of unproved properties, and the cost of major development projects. When required the cash flows are estimated using expected future product prices and costs and are discounted using a risk-free interest rate.







---



|                                                                                               |                                |          |                         |          |          |      
|---------------------------------------------------------------------------------------------- | ------------------------------ | -------- | ----------------------- | -------- | -------- | -----
|Depletion, Depreciation and Accretion(in thousands except for percentages and per boe amounts)
|                                                                                               | Three Months ended
December 31 |          | Years ended
December 31 |         
|2007                                                                                           | 2006                           | Change   | 2007                    | 2006     | Change  
|DD&A  excluding impairment/loss                                                               | $32,458                        | $36,148  | (10%)                   | $124,447 | $135,429 | (8%) 
|Impairment                                                                                     | 24,143                         | 66,019   | (63%)                   | 26,254   | 66,019   | (60%)
|DD&A                                                                                           | $56,601                        | $102,167 | (45%)                   | $150,701 | $201,448 | (25%)
|DD&A per boe  excluding impairment/loss                                                       | $28.98                         | $33.00   | (12%)                   | $27.43   | $30.04   | (9%) 
|Impairment per boe                                                                             | 21.56                          | 60.28    | (64%)                   | 5.79     | 14.64    | (60%)
|DD&A per boe                                                                                   | $50.54                         | $93.28   | (46%)                   | $33.22   | $44.68   | (26%)



GOODWILL IMPAIRMENT



During Q1 2007 and Q3 2007 the Trust recorded $49.3 million and $27.1 million impairment expense respectively, on the carrying balance of goodwill in the Canadian reporting unit.  No goodwill remains at December 31, 2007.



TAXES



Future income tax reduction of $36.1 million arose mainly due to the reduction in book basis due to the impairment on property, plant and equipment in 2007.  The increase in non-capital losses gave rise to $4.9 million in future income tax reduction.  Depletion expense, which includes impairment of property, plant and equipment accounted for another $31.5 million.  The reduction in 2006 of $58.9 million is higher than in 2007 due to the adjustment in tax rate from 34.5% in 2005 to 32.1% giving rise to an income tax reduction of $6.7 million in 2006.



The acquisition of Trigger Resources resulted in the recognition of a future income tax liability of $15.6 million representing the difference between the tax basis and the fair value assigned to the acquired assets.



In determining its taxable income, Enterra Energy Corp., a wholly owned subsidiary of the Trust ("the Corporation) deducts interest payments made to the Trust, effectively transferring the income tax liability to unitholders thus reducing the Corporations taxable income to nil.  Under the Corporations policy, at the discretion of the board of directors, funds can be withheld from distributions to fund future capital expenditures, repay debt or other purposes.  In the event withholdings increase sufficiently, the Corporation could become subject to taxation on a portion of its income in the future.  This can be mitigated through options including the issuance of additional trust units, increased tax pools from additional capital spending, modifications to the distribution policy or potential changes to the corporate structure.  The corporate subsidiaries of the Trust are subject to tax if deductions are inadequate to reduce taxable income to zero.



On October 31, 2006 the Canadian Minister of Finance announced certain changes to the taxation of publicly traded trusts (Bill C-52). Bill C-52, the Budget Implementation Act 2007 received its third reading and was substantively enacted on June 12, 2007.  Bill C-52 applies to a specified investment flow-through (SIFT) trust and will apply a tax at the trust level on distributions of certain income from such SIFT trusts at a rate of tax comparable to the combined federal and provincial corporate tax rate.  These distributions will be treated as dividends to the trust unitholders.  The Trust constitutes a SIFT and as a result, the Trust and its unitholders will be subject to Bill C-52.



Bill C-52 commences January 1, 2007 for all SIFTs that began to be publicly traded after October 31, 2006 and commencing January 1, 2011 for all SIFTs that were publicly traded on or before October 31, 2006.  It is expected that the Trust will not be subject to the taxation requirements of Bill C-52 until January 1, 2011.







---

Commencing January 1, 2011, the Trust will not be able to deduct certain of its distributed income.  The Trust will become subject to a distribution tax of 28 percent on distributions of income, but this tax will not apply to returns of capital.  Enterra will consider the options and alternative structures with legal and business advisors to determine if any potential restructuring available to maximize value is in the best interest of unitholders.



The federal component of the proposed tax on SIFT is expected to be 15 percent in 2012 (28 percent total) and thereafter.  The Trust is required to recognize, on a prospective basis, future income taxes on temporary differences in the Trust.  In Q2 2007, a $9.9 million reduction of the future income tax liability was recorded for temporary difference. Subsequent to Q2 2007, the Trust suspended its distributions which caused this temporary difference to no longer meet the criteria for future income tax asset recognition.  Overall, there was nil impact in 2007 due to the proposed tax on SIFT.



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 on a basis that is consistent with previous disclosures.



Netback per boe of production is summarized below:



|                                                 |                                |        |                         |        |        |      
|------------------------------------------------ | ------------------------------ | ------ | ----------------------- | ------ | ------ | -----
|Netback per boe                                 
|                                                 | Three Months ended
December 31 |        | Years ended
December 31 |       
|2007                                             | 2006                           | Change | 2007                    | 2006   | Change
|Price received per boe (prior to unrealized MTM) | $47.36                         | $50.48 | (6%)                    | $49.34 | $51.82 | (5%) 
|Royalties per boe                                | 9.70                           | 10.22  | (5%)                    | 10.00  | 10.71  | (7%) 
|Operating expense per boe                        | 15.66                          | 16.04  | (2%)                    | 14.29  | 11.17  | 28%  
|Operating netback per boe                        | $22.00                         | $24.22 | (9%)                    | $25.05 | $29.94 | (16%)
|G&A per boe                                      | 6.35                           | 6.95   | (9%)                    | 5.41   | 4.52   | (20%)
|Interest expense per boe                         | 5.03                           | 7.81   | (36%)                   | 4.98   | 5.92   | (16%)
|Corporate netback per boe                        | $10.63                         | $9.46  | 12%                     | $14.66 | 19.50  | (25%)



Management uses netback to analyze operating performance.  Netback, as presented, is not intended to represent an alternative to net earnings (loss) or other measures of financial performance calculated in accordance with GAAP.  All references to netback throughout this MD&A are based on the reconciliation in the table below:







---



|                                                                |                                |                         |            |          
|--------------------------------------------------------------- | ------------------------------ | ----------------------- | ---------- | ---------
|Netback(in thousands, except per boe)                          
|                                                                | Three Months ended
December 31 | Years ended
December 31
|2007                                                            | 2006                           | 2007                    | 2006      
|Net loss                                                        | $(39,481)                      | $(69,189)               | $(142,036) | $(64,239)
|Income taxes                                                    | (16,136)                       | (31,951)                | (35,950)   | (57,575) 
|Foreign exchange gain                                           | 886                            | 1,384                   | 546        | 1,910    
|Non-controlling interest                                        | -                              | (101)                   | -          | (36)     
|Depletion, depreciation and accretion                           | 56,601                         | 101,987                 | 150,701    | 201,448  
|Goodwill impairment                                             | -                              | -                       | 76,463     | -        
|Amortization of deferred financing fees and financing fees      | -                              | 8,792                   | -          | 17,160   
|Other                                                           | 1,457                          | -                       | -          | -        
|Unrealized mark-to-market gains (loss) on financial instruments | 8,578                          | (559)                   | 16,793     | (10,628) 
|Corporate netback                                               | $11,905                        | $10,363                 | $66,517    | $88,040  
|Total volume (boe)                                              | 1,120,049                      | 1,095,260               | 4,536,093  | 4,508,480
|Corporate netback per boe (non-GAAP)                            | $10.63                         | $9.46                   | $14.66     | $19.50   



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 cash provided by operating activities 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:



|                                          |                                |                         |          |        
|----------------------------------------- | ------------------------------ | ----------------------- | -------- | -------
|Funds from operations(in thousands)      
|                                          | Three Months ended
December 31 | Years ended
December 31
|2007                                      | 2006                           | 2007                    | 2006    
|Cash provided by operating activities     | $2,215                         | $26,163                 | $76,844  | $64,485
|Changes in non-cash working capital items | 9,895                          | (16,605)                | ($6,381) | 21,632 
|Funds from operations                     | $12,110                        | $9,558                  | $70,463  | $86,117



In 2007, funds from operations decreased by 18% over 2006.  The decrease was primarily due to lower realized prices, an increase in operating expenses and higher general and administrative expenses.  These decreases were partially offset by lower interest expenses and the benefit of the results from Trigger Resources beginning in May 2007.



In Q4 2007, the benefit of higher production volumes due to the acquisition of Trigger Resources was only partially offset by the effects of lower commodity prices and higher operating expenses compared to Q4 2006.  As a result, funds from operations for the period increased by $2.6 million to $12.1 million compared to $9.6 million in Q4 2006.







---



DISTRIBUTIONS



|                                                                                         |                                     |                             |                          |          
|---------------------------------------------------------------------------------------- | ----------------------------------- | --------------------------- | ------------------------ | ---------
|                                                                                         | Three Months ended
December 31 2007 | Year ended
December 31 2007 | Years ended 
December 31
|Cash provided by operating activities                                                    | $2,215                              | $76,844                     | $64,485                  | $68,120  
|Net earnings (loss)                                                                      | $(39,481)                           | $(142,036)                  | $(64,239)                | $970     
|Cash distributions paid                                                                  | -                                   | $39,486                     | $90,487                  | $66,195  
|                                                                                         |                                     |                             |                          |          
|Excess (shortfall) of cash provided by operating activities over cash distributions paid | $2,215                              | $37,358                     | $(26,002)                | $1,925   
|Shortfall of net earnings (loss) over cash distributions paid                            | $(39,481)                           | $(181,522)                  | $(154,726)               | $(65,225)



To the extent that the Trust uses cash to reduce debt and fund capital additions, acquisitions and other significant expenditures, the cash that is available for distribution to unitholders will be reduced.  Cash distributions as a percentage of funds from operations in Q4 2007 were 0%.  On September 17, 2007 the Trust suspended its monthly distributions in order to redirect its cash flow to the repayment of its outstanding debt. In December 2007, Enterra has committed to extend the distribution suspension period for the duration of the credit facilities in order to advance its debt repayment.



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 was, until September 2007, passed on to unitholders in the form of taxable distributions.  The Trust anticipates that, commencing in 2011, new tax legislation that will subject the Trust to a tax in a manner similar to corporations will decrease the amount of cash available for distribution and thus reduce any potential cash distributions to unitholders.



Distributions paid to unitholders



During 2007 the Trust paid monthly cash distributions to its unitholders in U.S. dollars.  Cash distributions were paid on the 15th of the following month or the next business day if the 15th of the month fell on a weekend or a statutory holiday.  These distributions were determined each month by the board of directors, after review of a number of factors potentially impacting the Trust including its available prospects and opportunities, the outlook for commodity prices, other macro-economic factors and the financial position and commitments of the Trust.  On September 17, 2007 the Trust suspended its monthly distributions in order to redirect its cash flow to the repayment of its outstanding debt.



In July 2006 and again in January 2007 the Trust lowered the level of its distribution with the intent of investing additional cash flow in activities that would allow it to replace produced reserves and offset natural production declines and thus sustain distributions.  Distributions declared in 2006 were US$0.18 for the first half of the year, then reduced to US$0.12 for the remainder of 2007.  In January to August 2007, distributions of US$0.06 were declared per unit.



Taxation of distributions



Distributions comprise a return of capital portion (tax deferred) and a return on capital portion (taxable).  The return of capital component reduces the cost basis of the trust units held.  For 2007, distributions declared will be 99.97% return on capital for the year (taxable) and 0.03 % return of capital per unit for the year (tax deferred).  For a more detailed breakdown, please visit our website at www.enterraenergy.com.







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CAPITAL EXPENDITURES



The following table represents the capital expenditures that were paid for with cash.  The table excludes certain capital expenditures, such as the portion of the cost of acquiring the Oklahoma Assets which was paid for with non-cash consideration such as trust units.



|                                                          |                                |        |                         |         |          |      
|--------------------------------------------------------- | ------------------------------ | ------ | ----------------------- | ------- | -------- | -----
|Capital Expenditures(in thousands except for percentages)
|                                                          | Three Months ended
December 31 |        | Years ended December 31 |        
|2007                                                      | 2006                           | Change | 2007                    | 2006    | Change  
|Capital expenditures                                      | $5,137                         | $5,144 | -                       | $95,047 | $213,101 | (55%)



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 from period to period, which is not a result of capital additions or disposals.



On April 30, 2007, the Trust closed the acquisition of Trigger Resources.  The results of operations of Trigger Resources are included in the consolidated financial statements as of April 30, 2007.  Total consideration paid for Trigger Resources was $63.3 million (including transaction costs of $0.3 million).



Excluding the acquisition of Trigger Resources, during the year ended December 31, 2007 in Canada, the Trust spent $16.0 million in capital expenditures the major components of which include; $2.2 million on 3-D seismic in northeastern British Columbia to aid in the development of the proved and probable reserves, $6.9 million related to drilling and completions of which $2.2 million was related to the four wells drilled on the lands in Saskatchewan, $0.7 million for the construction of facilities and pipelines and $5.5 million for other plant and equipment.  The Trust sold $11.3 million of non-core assets during the year.



During the year ended December 31, 2007 in the U.S., approximately $5.3 million of the $15.7 million capital expenditures in the U.S. operations was spent on acquisitions of land for future development in Oklahoma.  In addition, $3.8 million was incurred on completion and equipping of two salt water disposal wells and $3.0 million on infrastructure additions to service the new wells being added by the strategic partner of the Trust.  All of the expenditures were in support of new wells being drilled under the area farm-out agreement.  An additional expenditure of $3.3 million (before adjustments) was spent for the acquisition of assets from a working interest owner in certain oil and gas properties located in Wyoming.



During 2007 in the U.S., costs totaling $4.0 million for a salt water disposal well and its related infrastructure were removed from property, plant and equipment and classified as a receivable.  Under the agreement with the joint venture partner, Enterra will recover the costs of the infrastructure over a three-year period.  During 2007, the Trust earned $0.4 million of interest revenue on the receivable under this arrangement.



RESERVES AND PRESENT VALUE SUMMARY



Enterra 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 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, 2007 are based on the interest in 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 reserves have been evaluated by independent engineers each year.  McDaniel and Associates Consultants Ltd. ("McDaniel") independently evaluated the 2007 Canadian reserves, MHA Petroleum Consultants, Inc. (MHA) independently evaluated the Wyoming reserves and Haas Petroleum Engineering Services, Inc. (Haas) evaluated the Oklahoma reserves as at December 31, 2007.

|                                                                    |         |          |        
|------------------------------------------------------------------- | ------- | -------- | -------
|                                                                   
|Reserve Continuity - Oil and Gas (mboe)                            
|                                                                    | Proved  | Probable | Total  
|December 31, 2005                                                   | 14,295  | 4,737    | 19,032 
|Discoveries and extensions                                          | 536     | 549      | 1,085  
|Purchases                                                           | 15,041  | 1,961    | 17,002 
|Dispositions                                                        | (1,492) | (613)    | (2,105)
|Production                                                          | (4,508) | 0        | (4,508)
|Revision of prior estimates                                         | (2,654) | (494)    | (3,149)
|December 31, 2006                                                   | 21,218  | 6,140    | 27,357 
|Discoveries and extensions                                          | 1,419   | 1,141    | 2,560  
|Purchases                                                           | 2,731   | 1,857    | 4,588  
|Dispositions                                                        | (468)   | (175)    | (643)  
|Production                                                          | (4,536) | 0        | (4,536)
|Revision of prior estimates                                         | 1,125   | (193)    | 932    
|December 31, 2007, including properties sold subsequent to year end | 21,489  | 8,770    | 30,259 
|Properties sold subsequent to year end                              | 2,427   | 915      | 3,342  
|December 31, 2007, excluding properties sold subsequent to year end | 19,062  | 7,855    | 26,917 
|                                                                   



Proved plus probable reserves increased 11% from the end of 2006 to the end of 2007 primarily due to the acquisition of Trigger Resources and ongoing development in Oklahoma and in Canada.  Proved reserves increased slightly from 21,218 mboe to 21,489 mboe.  Probable reserves increased 43% from 6,140 mboe to 8,770 mboe.  Total proved reserves represent 71% of total reserves versus 78% in 2006.



Discoveries and extensions of 2,560 mboe are primarily from the successful development well program in Oklahoma and recognition of a development location in our Ricinus Leduc pool based upon the performance of the existing well.  Revisions of prior estimates occurred both in the Canadian assets and the United States assets due to better than expected performance of our existing wells, increases in commodity price forecasts and increased operating expenditures.  Divesting of non-core assets during 2007 in Canada resulted in 643 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 as a measure performance.  It is calculated by dividing the operating netback per boe of production by the cost per boe of finding and developing reserves. A recycle ratio of one is considered 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), includes 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.



|                                                                                                            |                          |          |          |          |  | 
|----------------------------------------------------------------------------------------------------------- | ------------------------ | -------- | -------- | -------- |  | 
|FD&A and recycle ratio
(in $/boe, except for capital expenditures, FDC and reserves which are in thousands)
|                                                                                                            | Years ended December 31, | 3-year  
|2007                                                                                                        | 2006                     | 2005     | Average 
|Capital expenditures (excluding ARO)                                                                        | $95,047                  | $416,649 | $419,679 | $310,458
|Future Development Costs
Proved                                                                             | $34,224                  | $10,101  | $6,973   | 17,099  
|Proved Plus Probable                                                                                        | $49,268                  | $15,002  | $7,448   | $23,906 
|Reserves(1)                                                                                                 |                          |          |          |         
|Proved reserves added in the year (mboe)                                                                    | 5,276                    | 12,922   | 9,735    | 9,311   
|Probable reserves added in the year (mboe)                                                                  | 2,805                    | 2,016    | 2,713    | 2,511   
|Proved plus probable reserves added in the year  (mboe)                                                     | 8,080                    | 14,938   | 12,448   | 11,822  
|                                                                                                            |                          |          |          |         
|FD&A costs (excluding FDC)                                                                                  |                          |          |          |         
|Proved reserves ($/boe)                                                                                     | 18.02                    | 32.24    | 43.11    | 31.12   
|Proved plus probable reserves ($/boe)                                                                       | 11.76                    | 27.89    | 33.71    | 24.45   
|                                                                                                            |                          |          |          |         
|FD&A costs (including FDC)                                                                                  |                          |          |          |         
|Proved reserves ($/boe)                                                                                     | 24.50                    | 33.03    | 43.83    | 33.79   
|Proved plus probable reserves ($/boe)                                                                       | 17.86                    | 28.90    | 34.31    | 27.02   
|                                                                                                            |                          |          |          |         
|Recycle ratios                                                                                              |                          |          |          |         
|Corporate netbacks ($/boe)(2)                                                                               | 14.66                    | 19.50    | 25.98    | 20.05   
|Corporate recycle ratio (based on proved plus probable finding costs excluding FDCs)                       | 1.25                     | 0.70     | 0.77     | 0.91    
|Operating netbacks ($/boe) (3)                                                                              | 25.05                    | 29.94    | 31.31    | 28.77   
|Operating recycle ratio (based on proved plus probable reserves excluding FDCs))                           | 2.13                     | 1.07     | 0.93     | 1.38    
|(1) Includes revisions and acquisitions                                                                    
|(2) Corporate netbacks are production revenue less royalties, operating expenses, G&A and interest expense 
|(3) Operating netbacks are production revenue less royalties and operating expenses                        



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 $27.89/boe to $11.76/boe. This was due to the acquisition of Trigger Resources, the farm-in arrangement for development of the Oklahoma assets and improved capital project selection and improved project execution, all of which contributed to better capital efficiency than in prior years.











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

December 31, 2007 (NPV in millions)

|                                                                                                                                    |        |        |        |         |        |                       |     |    
|----------------------------------------------------------------------------------------------------------------------------------- | ------ | ------ | ------ | ------- | ------ | --------------------- | --- | ---
|                                                                                                                                    | Light/ |        |        |         |        | Net Present Value    
|                                                                                                                                    | Medium | Heavy  |        | Natural |        | Before Income Tax ($)
|                                                                                                                                    | Oil    | Oil    | NGL    | Gas     | Total  |                       |     |    
|                                                                                                                                    | (mbbl) | (mbbl) | (mbbl) | (mmcf)  | (mboe) | 0%                    | 5%  | 10%
|Canadian Assets                                                                                                                     |        |        |        |         |        |                       |     |    
|                                                                                                                                   
|McDaniel report                                                                                                                    
|Proved Producing                                                                                                                    | 2,100  | 1,444  | 526    | 33,747  | 9,694  | 233                   | 206 | 185
|Proved Non-Producing                                                                                                                | 26     | 13     | 38     | 1,995   | 409    | (2)                   | (1) | (1)
|Proved Undeveloped                                                                                                                  | 182    | 120    | 18     | 2,454   | 730    | 10                    | 8   | 7  
|Total Proved                                                                                                                        | 2,308  | 1,577  | 582    | 38,196  | 10,833 | 241                   | 213 | 191
|Total Probable                                                                                                                      | 1,155  | 662    | 246    | 24,083  | 6,076  | 149                   | 107 | 81 
|Total Proved &
Probable                                                                                                             | 3,463  | 2,239  | 828    | 62,279  | 16,909 | 390                   | 319 | 272
|                                                                                                                                    |        |        |        |         |        |                       |     |    
|United States Assets                                                                                                                |        |        |        |         |        |                       |     |    
|                                                                                                                                   
|Haas and MHA reports(1)                                                                                                            
|Proved Producing                                                                                                                    | 975    | 0      | 0      | 46,250  | 8,684  | 204                   | 169 | 145
|Proved Non-Producing                                                                                                                | 29     | 0      | 0      | 2,661   | 472    | 9                     | 8   | 7  
|Proved Undeveloped                                                                                                                  | 127    | 0      | 0      | 8,245   | 1,501  | 35                    | 27  | 18 
|Total Proved                                                                                                                        | 1,131  | 0      | 0      | 57,156  | 10,658 | 248                   | 204 | 170
|Total Probable                                                                                                                      | 303    | 0      | 0      | 14,344  | 2,694  | 72                    | 55  | 44 
|Total Proved &
Probable                                                                                                             | 1,434  | 0      | 0      | 71,500  | 13,351 | 320                   | 259 | 215
|Consolidated Assets                                                                                                                 |        |        |        |         |        |                       |     |    
|                                                                                                                                    |        |        |        |         |        |                       |     |    
|Proved Producing                                                                                                                    | 3,075  | 1,444  | 526    | 79,997  | 18,377 | 437                   | 375 | 330
|Proved Non-Producing                                                                                                                | 55     | 13     | 38     | 4,655   | 882    | 7                     | 7   | 6  
|Proved Undeveloped                                                                                                                  | 309    | 120    | 18     | 10,700  | 2,231  | 45                    | 35  | 25 
|Total Proved                                                                                                                        | 3,439  | 1,577  | 582    | 95,352  | 21,490 | 489                   | 417 | 361
|Total Probable                                                                                                                      | 1,458  | 662    | 246    | 38,427  | 8,770  | 221                   | 161 | 125
|Total Proved &
Probable                                                                                                             | 4,897  | 2,239  | 828    | 133,779 | 30,260 | 710                   | 578 | 487
|(1) The Haas and MHA reports were converted to Canadian dollars by the Trust using an exchange rate of US$1.00 per Canadian dollar. |       









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

Total excluding properties sold subsequent to year end

December 31, 2007 (NPV in millions)





|                                                                                                                                    |        |        |        |         |        |                       |     |    
|----------------------------------------------------------------------------------------------------------------------------------- | ------ | ------ | ------ | ------- | ------ | --------------------- | --- | ---
|                                                                                                                                    | Light/ |        |        |         |        | Net Present Value    
|                                                                                                                                    | Medium | Heavy  |        | Natural |        | Before Income Tax ($)
|                                                                                                                                    | Oil    | Oil    | NGL    | Gas     | Total  |                       |     |    
|                                                                                                                                    | (mbbl) | (mbbl) | (mbbl) | (mmcf)  | (mboe) | 0%                    | 5%  | 10%
|Canadian Assets                                                                                                                     |        |        |        |         |        |                       |     |    
|                                                                                                                                   
|McDaniel report                                                                                                                    
|Proved Producing                                                                                                                    | 2,051  | 922    | 122    | 25,756  | 7,387  | 175                   | 156 | 142
|Proved Non-Producing                                                                                                                | 26     | 13     | 33     | 1,678   | 352    | (2)                   | (1) | (1)
|Proved Undeveloped                                                                                                                  | 182    | 120    | 3      | 2,163   | 665    | 9                     | 7   | 6  
|Total Proved                                                                                                                        | 2,259  | 1,055  | 158    | 29,597  | 8,404  | 182                   | 162 | 147
|Total Probable                                                                                                                      | 1,136  | 547    | 81     | 20,386  | 5,162  | 122                   | 89  | 68 
|Total Proved &
Probable                                                                                                             | 3,395  | 1,602  | 239    | 49,983  | 13,567 | 304                   | 251 | 215
|                                                                                                                                    |        |        |        |         |        |                       |     |    
|United States Assets                                                                                                                |        |        |        |         |        |                       |     |    
|                                                                                                                                   
|Haas and MHA reports(1)                                                                                                            
|Proved Producing                                                                                                                    | 975    | 0      | 0      | 46,250  | 8,684  | 204                   | 169 | 145
|Proved Non-Producing                                                                                                                | 29     | 0      | 0      | 2,661   | 472    | 9                     | 8   | 7  
|Proved Undeveloped                                                                                                                  | 127    | 0      | 0      | 8,245   | 1,502  | 35                    | 27  | 18 
|Total Proved                                                                                                                        | 1,131  | 0      | 0      | 57,156  | 10,658 | 248                   | 204 | 170
|Total Probable                                                                                                                      | 303    | 0      | 0      | 14,344  | 2,694  | 72                    | 55  | 44 
|Total Proved &
Probable                                                                                                             | 1,434  | 0      | 0      | 71,500  | 13,351 | 320                   | 259 | 215
|Consolidated Assets                                                                                                                 |        |        |        |         |        |                       |     |    
|                                                                                                                                    |        |        |        |         |        |                       |     |    
|Proved Producing                                                                                                                    | 3,026  | 922    | 122    | 72,006  | 16,071 | 378                   | 325 | 287
|Proved Non-Producing                                                                                                                | 55     | 13     | 33     | 4,339   | 824    | 8                     | 8   | 6  
|Proved Undeveloped                                                                                                                  | 309    | 120    | 3      | 10,408  | 2,166  | 44                    | 34  | 24 
|Total Proved                                                                                                                        | 3,390  | 1,055  | 158    | 86,753  | 19,062 | 430                   | 366 | 317
|Total Probable                                                                                                                      | 1,439  | 547    | 81     | 34,730  | 7,855  | 194                   | 144 | 113
|Total Proved &
Probable                                                                                                             | 4,829  | 1,602  | 239    | 121,483 | 26,917 | 624                   | 510 | 430
|(1) The Haas and MHA reports were converted to Canadian dollars by the Trust using an exchange rate of US$1.00 per Canadian dollar. |       









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LIQUIDITY & CAPITAL RESOURCES



On December 18, 2007 the credit facilities were amended to extend the maturity date of these facilities to November 20, 2008.  The first-lien debt of $148.0 million is made up of a $129.5 million revolving facility and a $18.5 million operating facility.  The second-lien debt was $40.0 million as at December 31, 2007.



Under the credit agreement, Enterra will reduce the indebtedness under the revolving and operating credit facilities from $148.0 million to $110.0 million by March 31, 2008 and the indebtedness under the second lien credit facility, which is currently at $29.1 million, to $28.0 million by June 30, 2008.  Enterra has also committed to extend the distribution suspension period for the duration of the facilities in order to advance its debt repayment strategy.  The agreement also restricts the convertible debenture interest payments for June 30, 2008 from being sourced from internally generated cash flow or with the proceeds of asset sales, but allows for the payment via alternative financings or via the trust unit interest payment election mechanism contained in the terms governing the convertible debentures.



Borrowings under the $129.5 million revolving facility and the $18.5 million operating facility bear interest at Canadian dollar BA or U.S. dollar LIBOR rates plus a margin of 2.00%, or Canadian or U.S. Prime rates plus a margin of 1.00% depending on the form of borrowing and the amount of debt outstanding relative to cash flow.  As at December 31, 2007 all borrowings under the facilities were denominated in Canadian dollars and interest was being accrued at a rate of 6.37% per annum.  At December 31, 2007, letters of credit totaling $0.5 million reduced the amount that can be drawn under the operating credit facility.



The $40.0 million second-lien facility is a non-revolving credit facility that matures on November 20, 2008 and is subordinated to the $129.5 million revolving facility and to the $18.5 million revolving operating facility.  The facility bears interest at Canadian dollar BA or U.S. dollar LIBOR rates plus a margin of 6.5%, or Canadian or U.S. prime rates plus a margin of 5.5% depending on the form of borrowing.  As at December 31, 2007 all borrowings under the second-lien facility were denominated in Canadian dollars and interest was being accrued at a rate of 11.75% per annum.



On April 26, 2007, the Trust issued $40.0 million of convertible debentures with a face value of $1,000 per convertible debenture that mature on June 30, 2012, bear interest at 8.25% per annum paid semi-annually on June 30 and December 31 of each year with the first payment occurring on December 31, 2007 and are subordinated to the bank credit facilities.  The convertible debentures are convertible at the option of the holder into trust units at any time prior to the maturity date at the conversion price of $6.80 per trust unit.



At the option of the Trust, the repayment of the principal portion of the convertible debentures may be settled in trust units.  The number of trust units issued upon redemption by the Trust will be calculated by dividing the principal by 95% of the weighted average trading price of trust units.  The convertible debentures are not redeemable on or before June 30, 2010. On or after July 1, 2010 and prior to maturity, the convertible debentures may be redeemed in whole or in part from time to time at the option of the Trust on not more than 60 days and not less than 30 days notice, at a redemption price of $1,050 per convertible debenture on or after July 1, 2010 and, on or before June 30, 2011, at a redemption price of $1,025 per convertible debenture and on or after July 1, 2011 and prior to maturity, in each case, plus accrued and unpaid interest thereon, if any.



In addition to the convertible debentures, on April 26, 2007, the Trust issued $29.2 million of trust units (4,945,000 trust units).



The net proceeds from the equity and convertible debenture issuances were used to finance the acquisition of Trigger Resources.



|                                                 |                          |           
|------------------------------------------------ | ------------------------ | ----------
|Working Capital(in thousands)                    | Years Ended December 31,
|                                                 | 2007                     | 2006      
|Working capital (deficiency)                     | $(177,369)               | $(188,683)
|Working capital (deficiency) excluding bank debt | $(5,416)                 | $(529)    
|                                                 |                          |           









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CONTRACTUAL OBLIGATIONS



The following are contractual obligations and commitments over the next five years:



|                                       |                                       |                  |            |             |                   | 
|-------------------------------------- | ------------------------------------- | ---------------- | ---------- | ----------- | ----------------- | 
|                                       | Payments due by period (in thousands)
|Contractual Obligations                | Total                                 | Less than 1 year | 1- 3 years | 3  5 years | More than 5 years
|Debt obligations                       | $171,953                              | $171,280         | $-         | $-          | $336             
|Interest on above debt (1)             | 13,532                                | 13,441           | -          | -           | 91               
|Convertible debentures                 | 120,331                               | -                | -          | 120,331     | -                
|Interest on convertible debentures (2) | 40,006                                | 9,726            | 19,453     | 10,827      | -                
|Operating lease obligations            | 5,317                                 | 1,165            | 2,118      | 1,758       | 276              
|Other long-term liabilities            | 29,939                                | 2,000            | -          | -           | 27,939           
|Total                                  | $381,078                              | $197,612         | $21,571    | $132,916    | $28,642          

(1)

using the December 31, 2007 debt balances and interest rate of 8.0%

(2)

using the December 31, 2007 debenture balances and its interest rates ranging from 8.0% to 8.25%



RELATED PARTY TRANSACTIONS

During 2007 Enterra paid $0.7 million (2006 - $0.8 million) to Macon Resources Ltd. (Macon), a company 100% owned by the former Chief Executive Officer, for management services provided by the former Chief Executive Officer, and for a portion of 2006 a previous Chief Financial Officer.  At December 31, 2007 and 2006, nil was payable to Macon for management services.  During Q1 2007 50,000 restricted units (valued at $0.4 million based on the unit price of trust units on the grant date) were granted to Macon.  On February 28, 2007, these restricted units vested and were converted to 50,441 trust units.  The former Chief Executive Officer resigned as an officer and director on November 27, 2007 and February 20, 2008 respectively.  Of the $0.7 million payment to Macon is an agreed amount of $0.3 million related to the termination of the contract that otherwise would have run to June 1, 2008.



During 2006 Enterra entered into a farm-out agreement with Petroflow Energy Ltd. (Petroflow), a public oil and gas company, to fund 100% of the drilling and completion costs of the Oklahoma Assets undeveloped lands.  The former Chief Executive Officer of the Trust and a current member of the board of directors own, directly and indirectly, approximately 16% and 2% of the outstanding shares of Petroflow respectively.  As at December 31, 2007, US$2.5 million of trade receivables and US$6.4 million of long-term receivables were due from Petroflow (of which US$2.3 million is due within one year and classified as current).  The long-term receivables are for infrastructure costs incurred that are to be repaid by Petroflow over a three-year period and is subject to interest of 12% per annum.  During 2007, US$0.4 million of interest income was earned on the long-term receivables from Petroflow (2006  US$0.3 million).  In 2007, $1.1 million of principal payments have been received.  The balance at year end December 31, 2007 is US$6.4 million.



On November 23, 2007, the Trust entered into a consulting agreement with Trigger Projects Ltd. for management services that would effectively be expected of the most senior manager of the Trust.  This contract has terms that require payment for services of $40,000 per month and a bonus of up to $0.5 million on termination.  The contract expires on May 31, 2008.  Payments of $50,000 were made to Trigger Projects Ltd. during 2007 and $nil was payable at December 31, 2007.









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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:



|                                                    |  |                |                   |                  
|--------------------------------------------------- |  | -------------- | ----------------- | -----------------
|Outstanding unit data                               |  |               
|As at                                               |  | March 28, 2008 | December 31, 2007 | December 31, 2006
|Trust units                                         |  | 61,435,895     | 61,435,895        | 56,097,875       
|Exchangeable shares                                 |  |                |                   |                  
|EEC exchangeable shares                             |  | -              | -                 | 16,337           
|RMG exchangeable shares                             |  | -              | -                 | -                
|RMAC Series B exchangeable shares                   |  | -              | -                 | 66,720           
|Trust unit options                                  |  | 1,451,000      | 1,474,334         | 1,481,000        
|Restricted units                                    |  | 1,200,227      | 1,057,483         | 423,855          
|Performance units                                   |  | 293,469        | 454,171           | 212,948          
|Warrants                                            |  | 301,000        | 301,000           | 301,000          
|8.0% Convertible debentures ($1,000 per debenture)  |  | $80,331        | $80,331           | $80,331          
|8.25% Convertible debentures ($1,000 per debenture) |  | $40,000        | $40,000           | $         -      



SENSITIVITIES



Enterra is exposed to risks inherent within the oil and gas sector, including commodity price risk, foreign-currency exchange risk, interest rate risk and credit risk.  Management conducts its operations in a manner intended to minimize exposure to these risks as described in note 16 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 accounts receivable are with customers in the energy industry and are subject to normal industry credit risk.  Management 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 Canadian operations, the price received 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, drilling and general overhead expenses are paid in Canadian dollars.  The U.S. operations receive revenue in U.S. dollars as well as pay the operating, drilling and general overhead expenses in U.S. dollars.  Monthly distributions are paid on a value expressed 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 earnings by approximately $0.8 million and our cash provided by operating activities by $1.8 million.







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Commodity Price Risk



The financial condition of Enterra, 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 fluctuations and market uncertainties due to a variety of factors that are beyond the control of the Trust.  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, 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 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 oil and natural gas reserves, including reductions due to price fluctuations, can have an adverse affect on the ability to obtain capital for development activities.  Similarly, any improvements in oil and natural gas prices can have a favorable impact on the financial condition, results of operations and capital resources.  WTI oil price sensitivity is such that a change of US$1.00 per bbl would impact earnings by approximately $1.2 million and cash flow by approximately $1.8 million.  Natural gas sensitivity is such that a change of US$0.50 per mcf would impact earnings by approximately $6.1 million and impact cash-flow provided by operating activities by approximately $9.1 million.



Enterra uses financial derivatives and physical sales contracts to mitigate a portion of oil and natural gas commodity 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 commodity price increases.



Interest Rate Risk



Interest rate risk exists principally with respect to indebtedness that bears interest at floating rates.  At December 31, 2007, the Trust had $172.0 million of indebtedness bearing interest at floating rates.  If interest rates were to change by 1.0%, the net impact on earnings would be approximately $1.2 million and the net impact on cash-flow provided by operating activities would be approximately $1.7 million.



Summarized below are the sensitivities to various risks based on its 2007 operations:



|                                                           |                                   |          
|---------------------------------------------------------- | --------------------------------- | ---------
|Sensitivity                                                | Estimated 2007 Impact On: (000s)
|                                                           | Net Earnings                      | Cash Flow
|Crude oil  US$1.00/bbl change in WTI                      | $1,233                            | $1,842   
|Natural gas  US$0.50/mcf change                           | 6,086                             | 9,092    
|Foreign exchange - $0.01 change in U.S. to Canadian dollar | 817                               | 1,757    
|Interest rate  1.0% change                                | 1,167                             | 1,720    





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 collected and communicated to the management, as appropriate, to allow timely decisions regarding required disclosure.  The Chairman of the Special Committee of the Board of Directors, acting as the Chief Executive Officer, and the Chief Financial Officer have concluded, based on their evaluation as of December 31, 2007, that as a result of the material weakness described below, disclosure controls and procedures were ineffective to provide reasonable assurance that material information is made known to them by others within the Trust.







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Managements Report on Internal Controls over Financial Reporting



A material weakness, as defined by SEC rules, is a control deficiency, or combination of control deficiencies, such that there is a reasonable possibility that a material misstatement of the annual or interim financial statements will not be prevented or detected on a timely basis.



Management of the Trust is responsible for designing internal controls over financial reporting or causing them to be designed under their supervision in order to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with Canadian GAAP, including note disclosure of the reconciliation to US GAAP.  Management has assessed the effectiveness of internal controls over financial reporting based on the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control-Integrated Framework.  During this process, a material weakness in internal control over financial reporting was identified as follows:



The major turnover in key personnel including the Chief Executive Officer, Chief Financial Officer, Controller and Manager of Operations Accounting in Canada and the Chief Operating Officer and Operations Manager in the U.S. have impacted the ability of the Trust to achieve complete segregation of duties  and provide adequate management review.  Notwithstanding the material weakness, no adjustments to the financial statements were made Management determined that as a result of the deficiencies, which are pervasive in nature, there is a reasonable possibility that a material misstatement of the annual or interim financial statements would not be prevented or detected on a timely basis.



As a result of the existence of the material weakness discussed above, management has concluded that the Trust did not maintain effective internal control over financial reporting as of December 31, 2007, based on the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control-Integrated Framework.



KPMG LLP, the registered public accounting firm that audited the financial statements has issued an attestation report on the internal controls of the Trust over financial reporting dated March 31, 2008. This report is adjacent to the financial statements on page 3 of the annual financial statements and notes.



CHANGES TO INTERNAL CONTROLS AND PROCEDURES FOR FINANCIAL REPORTING



During the year ended December 31, 2007 and subsequent thereto, the Trust had turnover in some of its key positions, notably the Chief Financial Officer and the Chief Executive Officer.  As a result of this turnover, the potential for control weaknesses was heightened. In many cases the individual control deficiencies which in aggregate resulted in the material weakness have already been addressed by new management in late 2007 and Q1 2008.  Senior management will continue to monitor the effectiveness of these controls and consult with external experts to assist management in their analysis.

MANAGEMENT REMEDIATION PLANS



Senior management positions have been filled with individuals that have the necessary experience and knowledge to address the complexity of the Trusts financial reporting requirements.  These individuals are addressing the individual control deficiencies which in aggregate resulted in the material weakness noted above.  Senior management is very confident that these deficiencies will be resolved in a timely manner now that there is stability in key positions within the organization.



CHANGES IN ACCOUNTING POLICIES



Effective January 1, 2007, Enterra adopted new Canadian accounting standards and related amendments to other standards on financial instruments.  Prior periods have not been restated, except as discussed below.  As at January 1, 2007 the effects on the financial statements are:







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Financial instruments  recognition and measurement



Effective January 1, 2007, the Trust's cash and cash equivalents and investments in marketable securities have been classified as held for trading and are recorded at fair value on the balance sheet. Fair values are determined directly by reference to published price quotations in an active market. Changes in the fair value of these instruments are recorded in net earnings.  All other financial instruments are recorded at cost or amortized cost, subject to impairment reviews. At December 31, 2007 there were no held to maturity or available for sale financial assets.  Enterra has not elected to record any financial instruments as held for trading.



The Trusts physical purchase and sale contracts have been designated as derivatives and are recorded at estimated fair value with changes in estimated fair value each period charged to earnings.  Embedded derivatives that do not meet certain exemptions are also required to be separately accounted for at fair value with changes in fair value included in earnings.  There are no significant embedded derivatives that required separate accounting as at December 31, 2007.  Transaction costs on the convertible debentures are presented net of the related debt and amortized to earnings using the effective interest method.



Comprehensive income



Comprehensive income includes net loss, holding gains and losses on available for sale investments, gains and losses on cash flow hedges and foreign currency gains and losses relating to self-sustaining foreign operations, all of which are not included in the calculation of earnings until realized.



When Enterra has not adopted a new accounting standard that has been issued but not yet effective, the entity is required to disclose (a) this fact; and (b) known or reasonably estimable information relevant to assessing the possible impact that application of the new standard will have on the Trusts financial statements in the period of initial application.



Capital disclosures



New Canadian accounting recommendations for capital disclosures have been issued which will require additional disclosure of both qualitative and quantitative information about objectives, policies and processes for managing capital.  These recommendations are effective for year-ends beginning January 1, 2008.



International Financial Reporting Standards



In February 2008, the Canadian Institute of Chartered Accountants confirmed that Canadian GAAP for publicly accountable enterprises will be converted to International Financial Reporting Standards (IFRS) on January 1, 2011.  This change in GAAP will be effective for years beginning January 1, 2011.



In December 2007, the SEC announced that the U.S. GAAP reconciliations requirement will be waived for Foreign Private Issuers who file financial statements prepared in accordance with IFRS for years beginning on or after January 1, 2009.







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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.  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;



e)

estimated future recoverable value of property, plant and equipment and goodwill; and



f)

estimated fair value of derivatives and investments.



ADDITIONAL INFORMATION



Additional information relating to Enterra Energy Trust can be found on SEDAR at www.sedar.com, on EDGAR at www.sec.gov/edgar.shtml, as well as on the website at www.enterraenergy.com.



|              |                                                      
|------------- | -----------------------------------------------------
|ABBREVIATIONS |                                                      
|AECO          | Natural gas reference price in Alberta               
|bbl           | barrel of oil                                        
|bbls/day      | barrels of oil per day                               
|boe           | barrels of oil equivalent                            
|              | (6 mcf equivalent to 1 bbl)                          
|boe/day       | barrels of oil equivalent per day                    
|Cdn$          | Canadian dollars                                     
|GAAP          | Canadian Generally Accepted Accounting Principles    
|GJ            | Gigajoule                                            
|mbbl          | thousand barrels of oil                              
|mboe          | thousands of barrels of oil equivalent               
|mcf           | thousand cubic feet of natural gas                   
|mcf/day       | thousands of cubic feet of natural gas per day       
|mmbtu         | millions of British Thermal Units                    
|mmbtu/day     | millions of British Thermal Units per day            
|mmcf          | millions of cubic feet of natural gas                
|Mwh           | megawatt-hour                                        
|NGL           | natural gas liquids                                  
|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
|US$           | United States dollars                                
|WTI           | West Texas Intermediate (oil reference price)