**ENTERRA
                ENERGY TRUST****MANAGEMENT’S
                DISCUSSION AND ANALYSIS**





The
      following is Management’s Discussion and Analysis (“MD&A”) of Enterra Energy
      Trust (“the Trust”) for the year ended December 31, 2005. This MD&A should
      be read in conjunction with the accompanying audited consolidated financial
      statements of the Trust for the year ended December 31, 2005. 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 29, 2006.





**SPECIAL
      NOTE REGARDING FORWARD-LOOKING STATEMENTS**





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





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





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





**SPECIAL
      NOTE REGARDING NON-GAAP TERMS**





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





**OVERVIEW
      AND STRATEGY**





The
      Trust’s strategy is to improve the overall quality of assets that underwrite the
      unitholder's value and future distributions. The acquisition of High Point
      Resources Inc. in August was the first significant step along this path.
      Rigorous processes have been and are being established to ensure strict cost
      accountability and regulatory compliance in all aspects of the business. These
      significant changes are ongoing into 2006, so that the Trust will continuously
      improve its performance. The Trust now has staff of over 80 employees,
      establishment of full finance, accounting, tax, technical and operational staff,
      both in head office, and in the field.




1




The
      Trust
      operates as an oil and natural gas income trust. The Trust pays monthly cash
      distributions on the 15th day of each month to unitholders of record on the
      immediately preceding distribution record date. The business strategy is to
      maintain and enhance oil and natural gas reserves to provide long term
      sustainable cash distributions to unitholders. The Trust uses a three-pronged
      strategy to achieve its goals through acquisition of producing properties with
      extensive potential for additional development upside, the use of strategic
      farm
      outs to develop these properties, and the pre-agreed acquisition from the farmee
      of the production resulting from these farm outs. Acquisitions are financed
      with
      cash flow, equity and with debt, the optimal mix being one that provides for
      the
      strongest balance sheet, and hence the maximum accretion of value to the
      unitholder. The Trust’s ability to replace and grow quality reserves using these
      strategies is a key success factor in its business outcomes.





The
      Trust
      also looks to improve the efficiency of its portfolio via a focus on higher
      quality products such as light oil and natural gas, and through the
      rationalization of assets with higher operating costs.





The
      Trust
      completed three acquisitions during the year ended December 31, 2005. On January
      26, 2005 the Trust closed an acquisition of Canadian petroleum and natural
      gas
      properties for cash consideration of $12.1 million. On June 1, 2005, the
      acquisition of Rocky Mountain Gas, Inc. (“RMG”), a Wyoming coal bed methane
      company, was closed for consideration of approximately $24.0 million, including
      $0.4 million of transaction costs. The consideration consisted of 736,842
      exchangeable shares (exchangeable on a one-to-one basis into trust units) valued
      at $16.7 million, 275,474 trust units valued at $6.3 million and $1.0 million
      in
      cash. On August 17, 2005, the acquisition of High Point Resources Inc. ("High
      Point") closed for consideration of approximately $201.5 million, including
      $1.3
      million of transaction costs. In addition the Trust assumed $75.0 million in
      debt and $6.1 million in working capital deficiency. The consideration consisted
      of 7,490,898 trust units valued at $168.5 million and 1,407,177 exchangeable
      shares (exchangeable on a one-to-one basis into trust units) valued at $31.7
      million.





With
      the
      acquisitions, and the Trust’s oil and natural gas development, the Trust
      increased its proved reserves 94% to 14,295,000 boe and its proved and probable
      reserves 102% to 19,032,200 boe. The Trust invested $21.5 million in its
      development program and on maintaining operations.





During
      2005, the Trust entered into an arrangement with Kingsbridge Capital Limited
      (“Kingsbridge”) whereby, at the discretion of the Trust, Kingsbridge has
      committed to purchase up to US$100 million of trust units over a 24-month
      period. On November 10, 2005, the Trust filed a US$500 million Base Shelf
      Prospectus.




**OVERALL
      PERFORMANCE**





Our
      financial results have been positively affected by increased natural gas sales
      volumes, arising from the three acquisitions completed in 2005, the most
      significant contributor being the High Point acquisition. With the completion
      of
      the High Point acquisition, the Trust exited 2005 with sales volumes of
      approximately 9,282 boe/day. The Trust realized an average total production
      of
      7,741 boe/day compared to 6,957 boe/day in 2004.





Fueled
      by
      the increased production from the acquisitions and higher oil and natural gas
      prices, the Trust increased cash provided by operating activities by 61% to
      $68.1 million compared to $42.3 million in 2004. This increase led to an
      increase in funds from operations of 40% to $70.5 million in 2005 compared
      to
      $50.2 million in 2004. Net earnings for the Trust decreased by 93% to $1.0
      million in 2005 from $14.0 million in 2004. On a per unit basis, the Trust
      decreased earnings by 95% to $0.03/unit compared to $0.62/unit in 2004. Net
      earnings and net earnings per unit have decreased in the current year due to
      a
      $13.8 million ceiling test write down and a $9.3 million impairment loss on
      the
      goodwill within the Trust’s U.S. cost center. In addition, net earnings
      decreased in the current year due to increased depletion costs associated with
      the acquisition of High Point in 2005.




2




A
      total
      of $66.2 million was paid to unitholders through distributions in 2005 compared
      to $40.4 million in 2004.




**SUMMARIZED
              FINANCIAL AND OPERATIONAL DATA***(in
              thousands except for volumes and per unit
              amounts)*


Three
                Months Ended December 31,
            
            
            
            Years
                Ended
              December
                31,**2005**
            
            2004
            
            
            
            **2005**
            
            2004(restated)(2)
            
            *Change*
            
            
            
            (restated)
            
            *Change*Oil
                and natural gas revenues
            
            **$**
            **50,248**
            
            $
            33,593
            
            
            50
            %
            **$**
            **157,743**
            
            $
            108,293
            
            
            46
            %Average
                sales (boe/day)
            
            
            **9,883**
            
            
            7,925
            
            
            25
            %
            
            **7,741**
            
            
            6,957
            
            
            11
            %Exit
                sales rate (boe/day)
            
            
            **9,282**
            
            
            7,258
            
            
            28
            %
            
            **9,282**
            
            
            7,258
            
            
            28
            %Cash
                provided by operating activities
            
            **$**
            **19,575**
            
            $
            14,192
            
            
            38
            %
            **$**
            **68,120**
            
            $
            42,345
            
            
            61
            %Funds
                from operations(1)
            
            **$**
            **19,519**
            
            $
            14,103
            
            
            38
            %
            **$**
            **70,545**
            
            $
            50,242
            
            
            40
            %Net
                earnings (loss)
            
            **$**
            **(12,937**
            **)**
            $
            3,256
            
            
            (497
            %)
            **$**
            **970**
            
            $
            14,027
            
            
            (93
            %)Net
                earnings (loss) per trust unit - basic
            
            **$**
            **(0.37**
            **)**
            $
            0.13
            
            
            (385
            %)
            **$**
            **0.03**
            
            $
            0.62
            
            
            (95
            %)Weighted
                average number of trust units outstanding - basic
            
            
            **35,358**
            
            
            25,296
            
            
            40
            %
            
            **29,534**
            
            
            22,518
            
            
            31
            %Average
                price per barrel of oil
            
            **$**
            **56.83**
            
            $
            49.90
            
            
            14
            %
            **$**
            **58.47**
            
            $
            43.00
            
            
            36
            %Average
                price per mcf of natural gas
            
            **$**
            **8.82**
            
            $
            6.87
            
            
            28
            %
            **$**
            **8.40**
            
            $
            6.69
            
            
            26
            %Production
                expenses per boe
            
            **$**
            **12.26**
            
            $
            10.98
            
            
            12
            %
            **$**
            **11.55**
            
            $
            9.25
            
            
            25
            %





(1) Funds
        from operations  is
        a
        non-GAAP financial measure. See non-GAAP financial measures section of the
        MD&A for a reconciliation of this measure.
 
 (2) Restated
        for the adoption of EIC-151 “Exchangeable Securities Issued by Subsidiaries of
        Income Trusts”. See note 3 of the 2005 notes to consolidated financial
        statements.


**SELECT
                FINANCIAL INFORMATION***(in
                thousands except per unit amounts)***2005**
            
            2004
              (restated)
            
            2003
              (restated)Total
                revenue
            
            **$**
            **157,743**
            
            $
            108,293
            
            $
            72,097Net
                earnings
            
            **$**
            **970**
            
            $
            14,027
            
            $
            5,430Net
                earnings per trust unitBasic
            
            **$**
            **0.03**
            
            $
            0.62
            
            $
            0.29Diluted
            
            **$**
            **0.03**
            
            $
            0.62
            
            $
            0.27Total
                assets
            
            **$**
            **611,543**
            
            $
            221,128
            
            $
            116,705Total
                long term liabilities
            
            **$**
            **126,322**
            
            $
            39,544
            
            $
            19,513Cash
                distributions
            
            **$**
            **69,496**
            
            $
            42,361
            
            $
            2,451Cash
                distributions per unit
            
            **$**
            **1.90**
            
            $
            1.66
            
            $
            0.10






3




**RESULTS
      OF OPERATIONS**





**Production**





The
      Trust
      increased its average production by 11% to 7,741 boe/day from 6,957 boe/day
      in
      2004. This increase was mainly due to increased natural gas production from
      the
      High Point acquisition. The acquisition provided the Trust with 2,998 boe/day
      of
      additional volume at the time of closing. The Trust’s production consisted of
      5,453 bbls/day of oil and natural gas liquids (“NGL”) and 13,729 mcf/day of
      natural gas, or a mix of 70% oil and NGL and 30% natural gas. As at December
      31,
      2005, the Trust had an exit rate of 9,282 boe/day.





**Production***(in
                thousands except for volumes and
                percentages)*


Three
                Months Ended December 31,
            
            
            
            Years
                Ended
              December
                31,**2005**
            
            2004
            
            
            
            **2005**
            
            2004(restated)
            
            *Change*
            
            
            
            (restated)
            
            *Change***Daily
                Sales Volumes - Average**Oil
                & NGL (bbls/day)
            
            
            **5,762**
            
            
            6,766
            
            
            (15
            %)
            
            **5,453**
            
            
            5,821
            
            
            (6
            %)Natural
                gas (mcf/day)
            
            
            **24,727**
            
            
            6,954
            
            
            256
            %
            
            **13,729**
            
            
            6,817
            
            
            101
            %Total
                (boe/day)
            
            
            **9,883**
            
            
            7,925
            
            
            25
            %
            
            **7,741**
            
            
            6,957
            
            
            11
            %**Daily
                Sales Volumes - Exit Rate**Oil
                & NGL (bbls/day)
            
            
            **5,476**
            
            
            5,905
            
            
            (7
            %)
            
            **5,476**
            
            
            5,905
            
            
            (7
            %)Natural
                gas (mcf/day)
            
            
            **22,836**
            
            
            8,118
            
            
            181
            %
            
            **22,836**
            
            
            8,118
            
            
            181
            %Total
                (boe/day)
            
            
            **9,282**
            
            
            7,258
            
            
            28
            %
            
            **9,282**
            
            
            7,258
            
            
            28
            %**Sales
                Volumes mix by product**Oil
                & NGL
            
            
            **58**
            **%**
            
            81
            %
            
            
            
            
            **70**
            **%**
            
            81
            %Natural
                gas
            
            
            **42**
            **%**
            
            19
            %
            
            
            
            
            **30**
            **%**
            
            19
            %**100**
            **%**
            
            100
            %
            
            
            
            
            **100**
            **%**
            
            100
            %





For
      the
      fourth quarter ended December 2005, the Trust realized an average sales volume
      of 5,762 bbls/day of oil and NGL and 24,727 mcf/day of gas (2004: 6,766 bbls/day
      and 6,954 mcf/day respectively).





For
      2006,
      the Trust expects production to increase significantly. The Trust acquired
      oil
      and gas producing properties located in Oklahoma (“Oklahoma Assets”) in the
      first quarter of 2006. These assets are forecasted to add approximately 6,300
      boe/day of production for the Trust.





**COMMODITY
      PRICING**





Prices
      for both oil and natural gas increased significantly in 2005 compared to 2004.
      A
      combination of increasing world demand and one of the worst hurricane seasons
      North America has experienced pushed prices to their highest levels ever. In
      addition, during the latter part of 2005, the Trust instituted the
      internalization of full service product marketing functionality including active
      movement of heavier crudes to specific market centers to maximize realizations,
      and establishing gas trunk line shipper status. These latter organizational
      changes have had a positive impact on company realizations.





West
      Texas Intermediate (“WTI”) is a standard benchmark for the price of oil. WTI is
      expressed in US dollars per barrel (“bbl”). The Trust reports the price it
      receives for oil in Canadian dollars per bbl. Alberta Spot prices, represented
      as AECI hub pricing (“AECO”), is a standard benchmark for the price of natural
      gas in Western Canada. AECO is expressed in Canadian dollars.





WTI
      realized an average price of US$56.56/bbl for 2005 compared to US$41.40/bbl
      in
      2004. Alberta AECO was $8.73/mcf for 2005 compared to $6.79/mcf for 2004. The
      strengthening of the Canadian dollar dampened the upward price movement as
      oil
      and gas are benchmarked in US dollars. The average exchange rate decreased
      to
      1.21 in 2005 from 1.30 in 2004.




4




The
      Trust
      utilized a price risk management program to mitigate its exposure to price
      changes for oil and natural gas. Inclusive of this price risk management
      program, the Trust realized an average price of $58.11/bbl of oil in 2005
      compared to $43.00/bbl in 2004 and $8.40/mcf of natural gas in 2005 compared
      to
      $6.69/mcf in 2004.





The
      Trust
      has financial collars for 2,000 boe/day of oil production into 2006 the price
      of
      which is between US$55.00/bbl and US$80.00/bbl. The Trust has financial floor
      and collar swaps for 10,000 GJ/day of gas production into 2006 the price of
      which ranges from Cdn$8.50/GJ to Cdn$14.00/GJ.








**Pricing***(in
                thousands except for volumes and
                pricing)*


Three
                Months Ended December 31,
            
            
            
            Years
                Ended
              December
                31,**2005**
            
            2004
            
            
            
            
            
            2004(restated)
            
            *Change*
            
            **2005**
            
            (restated)
            
            *Change***Pricing
                Benchmarks**WTI
                (US$/bbl)
            
            **$**
            **60.03**
            
            $
            48.28
            
            
            24
            %
            **$**
            **56.56**
            
            $
            41.40
            
            
            37
            %Average
                exchange rate: US$1.00 to $CDN =
            
            
            **1.17**
            
            
            1.25
            
            
            (6
            %)
            
            **1.21**
            
            
            1.30
            
            
            (7
            %)WTI
                (CDN$/bbl)
            
            **$**
            **70.24**
            
            $
            60.35
            
            
            16
            %
            **$**
            **68.44**
            
            $
            53.82
            
            
            27
            %AECO
                monthly index (CDN$/mcf)
            
            **$**
            **11.39**
            
            $
            7.09
            
            
            61
            %
            **$**
            **8.73**
            
            $
            6.79
            
            
            29
            %**Average
                Prices Received by the Trust**Oil
                (CDN per bbl)
            
            **$**
            **56.83**
            
            $
            49.90
            
            
            14
            %
            **$**
            **58.11**
            
            $
            43.00
            
            
            35
            %Natural
                gas (CDN per mcf)
            
            **$**
            **8.82**
            
            $
            6.87
            
            
            28
            %
            **$**
            **8.40**
            
            $
            6.69
            
            
            26
            %Total
                (CDN per boe)
            
            **$**
            **55.26**
            
            $
            47.33
            
            
            17
            %
            **$**
            **55.83**
            
            $
            42.53
            
            
            31
            %





In
      Q4
      2005 the Trust realized an average price of $56.83/bbl for oil and $8.82/mcf
      for
      natural gas compared to $49.90/bbl and $6.87/mcf respectively in
      2004.







5





**REVENUES**





The
      increase in revenues was due to the increase in natural gas sales volumes
      together with the increases in the sales prices of oil and natural gas. The
      increase in natural gas sales volumes was a direct result of the High Point
      acquisition, a company whose production was heavily natural gas weighted, for
      which the operating results have been included in the consolidated balances
      since August 17, 2005. The increase in sales prices was a result of the current
      commodity price environment tempered by the stronger Canadian dollar.


**Revenues***(in
                thousands)*


Three
                Months Ended December 31,
            
            
            
            Years
                Ended
              December
                31,2004
            
            
            
            **2005**
            
            2004**2005**
            
            (restated)
            
            *Change*
            
            
            
            (restated)
            
            *Change***Revenues**Oil
                and NGL
            
            **$**
            **30,105**
            
            $
            29,196
            
            
            3
            %
            **$**
            **115,645**
            
            $
            91,611
            
            
            26
            %Natural
                gas
            
            
            **20,143**
            
            
            4,397
            
            
            358
            %
            
            **42,098**
            
            
            16,682
            
            
            152
            %Total
            
            **$**
            **50,248**
            
            $
            33,593
            
            
            50
            %
            **$**
            **157,743**
            
            $
            108,293
            
            
            46
            %





Revenue
      in Q4 2005 increased 50% to $50.2 million from $33.6 million in 2004. The
      increase in this revenue is due to the increased natural gas volumes from the
      High Point acquisition and the increased commodity prices received in the
      quarter.





**ROYALTIES**





Royalties,
      which include Crown, freehold and overriding royalties, offset by Alberta
      Royalty Tax Credits (“ARTC”), have increased compared to the prior periods as
      the result of the increased revenues in 2005. Royalties are based on the volume
      of production or sales and commodity price, therefore royalties per boe
      fluctuate in relation to the fluctuation in the prices received by the Trust
      for
      the oil and natural gas sales.


**Royalties***(in
                thousands except for percentages and per boe
                amounts)*


Three
                Months EndedDecember 31,
            
            
            
            Years
                EndedDecember
                31,**2005**
            
            2004
            
            
            
            **2005**
            
            2004(restated)
            
            *Change*
            
            
            
            (restated)
            
            *Change*Royalties
            
            **$**
            **12,920**
            
            $
            7,958
            
            
            62
            %
            **$**
            **36,079**
            
            $
            24,527
            
            
            47
            %As
                a percentage of revenue
            
            
            **26**
            **%**
            
            24
            %
            
            
            
            
            **23**
            **%**
            
            23
            %Royalties
                per boe
            
            **$**
            **14.21**
            
            $
            10.91
            
            
            30
            %
            **$**
            **12.77**
            
            $
            9.63
            
            
            33
            %





For
      2006,
      the Trust projects royalties to remain relatively constant as a percentage
      of
      revenue.





6




**PRODUCTION
      EXPENSES**





The
      Trust
      experienced higher operating costs in 2005 compared to 2004. The additions
      of
      production due to the acquisition of Rocky Mountain Energy, Rocky Mountain
      Gas
      and High Point have increased the Trust’s overall lifting expense. The Trust’s
      southeastern Alberta oil producing properties are under extensive water flood
      and pumping schemes and were subject to higher electricity prices and workover
      costs in 2005 ($4.4 million) relative to 2004 ($1.7 million). In addition,
      cost
      increases in fuel, well servicing day rates, and contractor expense occurred
      due
      to competitive nature of the oil and gas industry. One time costs totaling
      $0.4
      million were incurred at Sylvan Lake field to replace defective pumping rods
      and
      at Claire field to refit a water source well. Overall, the 2005 cost increases
      were partially offset by the low cost production associated with the properties
      acquired in the High Point acquisition. **Production
                  Expenses***(in
                  thousands except for percentages and per boe amounts)*Three
                  Months Ended December 31,
              
              
              
              Years
                  Ended
                December
                  31,**2005**
              
              2004
                (restated)
              
              *Change*
              
              **2005**
              
              2004
                (restated)
              
              *Change*Production
                  expenses
              
              **$**
              **11,007**
              
              $
              8,007
              
              
              37
              %
              **$**
              **32,620**
              
              $
              23,492
              
              
              39
              %Production
                  expenses per boe
              
              **$**
              **12.11**
              
              $
              10.98
              
              
              10
              %
              **$**
              **11.55**
              
              $
              9.25
              
              
              25
              %




With
      the
      completion of the High Point acquisition, and continued development of the
      related natural gas properties, overall operating costs per boe are expected
      to
      trend downward in 2006. The Oklahoma asset additions are expected to have
      production costs lower than the existing assets of the Trust.





**GENERAL
      AND ADMINISTRATIVE EXPENSES**





General
      and administrative expenses increased by 133% to $10.3 million from $4.4 million
      in 2004. The year over year increase was also impacted by the increased audit
      and consulting services required to respond to the resignation of senior
      officers of the Trust in the first quarter of 2005 and the 2004 bonus that
      was
      approved by the unitholders in 2005, paid and recorded as an expense in the
      second quarter of 2005. Additionally, G&A expenses have increased due to
      computer software purchases and higher costs associated with regulatory
      compliance in Canada and the U.S. During 2005, the Trust expanded its employee
      base to reduce the Trust’s reliance on the Technical Services Agreement between
      the Trust and JED Oil Inc. Finally, the Trust discontinued the capitalization
      of
      administrative costs.


**General
                    and Administrative Expenses***(in
                    thousands except for percentages and per boe amounts)*Three
                    Months Ended December 31,
                
                
                
                Years
                    Ended
                  December
                    31,**2005**
                
                2004
                  (restated)
                
                *Change*
                
                **2005**
                
                2004
                  (restated)
                
                *Change*G&A
                    expenses
                
                **$**
                **2,990**
                
                $
                1,300
                
                
                130
                %
                **$**
                **10,331**
                
                $
                4,440
                
                
                133
                %G&A
                    per boe
                
                **$**
                **3.29**
                
                $
                1.78
                
                
                85
                %
                **$**
                **3.66**
                
                $
                1.75
                
                
                109
                %


General
      and administrative ("G&A") expenses for Q4 2005 increased over the
      corresponding period in 2004 due to the expansion in operations of the Trust.
      Additional personnel costs in the form of salaries and consulting fees along
      with higher legal costs have been incurred in connection with the integration
      and administration of the High Point assets, regulatory compliance requirements
      and the filing of the Base Shelf Prospectus.





G&A
      expenses per boe are expected to decline in 2006 as a result of the additional
      sales volumes acquired with the High Point acquisition that will be included
      for
      the entire year. The Oklahoma Assets will provide additional sales volumes
      with
      relatively low associated G&A. The acquisition will increase total G&A,
      but decrease it on a per boe basis.





7





**INTEREST
      EXPENSE**





Interest
      expense has increased due to the higher average outstanding loan balances during
      the period, interest on the bridge credit facility for the High Point
      acquisition, and the increase in interest rates from the prior periods.


**Interest
                  Expense***(in
                  thousands except for percentages and per boe amounts)*Three
                  Months Ended December 31,
              
              
              
              Years
                  Ended
                December
                  31,**2005**
              
              2004
                (restated)
              
              *Change*
              
              **2005**
              
              2004
                (restated)
              
              *Change*Bank
                  debt, capital lease, and notes payable at end of period
              
              **$**
              **102,101**
              
              $
              47,316
              
              
              116
              %
              **$**
              **102,101**
              
              $
              47,316
              
              
              116
              %Interest
                  expense
              
              **$**
              **2,000**
              
              $
              491
              
              
              307
              %
              **$**
              **4,715**
              
              $
              2,222
              
              
              112
              %Interest
                  expense per boe
              
              **$**
              **2.20**
              
              $
              0.67
              
              
              227
              %
              **$**
              **1.67**
              
              $
              0.87
              
              
              92
              %




Interest
      expense has increased in Q4 2005 compared to Q4 2004 due to the higher average
      outstanding loan balances during the period, interest on the bridge credit
      facility for the High Point acquisition, and the increase in interest rates
      from
      the prior periods.





The
      Trust
      expects interest expense to increase in 2006 due to the bridge financing of
      the
      acquisition of the assets in Oklahoma. This bridge facility is expected to
      be
      replaced by a combination of equity and debt.





**DEPLETION,
      DEPRECIATION AND ACCRETION (“DD&A”)**





DD&A
      expense increased in both Q4 2005 and the full year 2005 compared to respective
      periods in 2004, primarily due to the higher cost per boe of the oil and natural
      gas properties acquired with the east central Alberta, RMG, and High Point
      acquisitions.





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


**Depletion,
                  Depreciation and Accretion***(in
                  thousands except for percentages and per boe amounts)*Three
                  Months Ended
                December
                  31,
              
              
              
              Years
                  Ended
                December
                  31,**2005**
              
              2004
                (restated)
              
              *Change*
              
              **2005**
              
              2004
                (restated)
              
              *Change*DD&A
                  - excluding write down
              
              **$**
              **27,812**
              
              $
              11,794
              
              
              136
              %
              **$**
              **68,229**
              
              $
              35,976
              
              
              90
              %DD&A
                  - excluding write down per boe
              
              **$**
              **30.59**
              
              $
              16.18
              
              
              89
              %
              **$**
              **24.15**
              
              $
              14.13
              
              
              71
              %Ceiling
                  test provision
              
              **$**
              **13,844**
              
              
              -
              
              
              
              
              **$**
              **13,844**
              
              
              -DD&A
              
              **$**
              **41,656**
              
              $
              11,794
              
              
              253
              %
              **$**
              **82,073**
              
              $
              35,976
              
              
              128
              %DD&A
                  per boe
              
              **$**
              **45.82**
              
              $
              16.18
              
              
              183
              %
              **$**
              **29.05**
              
              $
              14.13
              
              
              105
              %





**GOODWILL
      IMPAIRMENT LOSS**





With
      the
      ceiling test write down in the United States cost center as noted above, the
      Trust also realized an impairment loss on the goodwill for the United States
      reporting unit. A loss of $9.3 million was realized for 2005 due to this
      impairment.




8





**COMMODITY
      CONTRACTS**





For
      2005,
      the Trust entered into financial floor and collar swap contracts to hedge a
      portion of the natural gas and oil production. At December 31, 2005 these
      contracts had a mark-to-market value of $0.4 million. Hedge costs of $0.1
      million were incurred on the contracts.





During
      2004, the Trust had several commodity hedge contracts that resulted in losses
      of
      $1.9 million, $0.3 million and $1.0 million in Q1, Q2 and Q4
      respectively.





The
      Trust
      has entered into physical delivery contracts to sell certain natural gas volumes
      at fixed prices. The physical delivery contracts are summarized
      below:


**Contract
                Period End**
            **Quantity**
            **Pricing**
              **(Cdn/GJ)**
            **Estimated
                fair value**Natural
                Gas Contracts
            March
                31, 2006
            8,000
                GJ/day
            $8.01
                to $8.85
            $(1,293)





**TAXES**





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





The
      corporate subsidiaries of the Trust are subject to tax if the discretionary
      deductions available are inadequate to reduce taxable income to zero. These
      discretionary deductions are often referred to as tax pools.


Three
                  Months Ended December 31,
              
              Years
                  Ended December 31,**2005**
              
              2004
                (restated)
              
              **2005**
              
              2004
                (restated)Current
                  tax expense
              
              **$**
              **354**
              
              $
              170
              
              **$**
              **1,456**
              
              $
              260Future
                  income tax (recovery)
              
              
              **(15,325**
              **)**
              
              (396
              )
              
              **(18,689**
              **)**
              
              (280
              )Total
                  tax (recovery)
              
              **$**
              **(14,971**
              **)**
              $
              (226
              )
              **$**
              **(17,233**
              **)**
              $
              (20
              )


Current
      tax expense relates primarily to capital tax, which is based on debt and equity
      levels at the end of the year. The increase in capital tax expense in 2005
      is
      primarily due to a higher taxable capital base from the acquisition of High
      Point.





Future
      income tax recovery of $18.7 million arises from several factors. One factor
      is
      the decreased accounting basis of the property, plant and equipment stemming
      from the impairment of US cost center of $13.8 million, giving a future income
      tax recovery of $4.7 million. The second factor arises from an adjustment in
      the
      tax rate applied to the temporary differences in the fourth quarter of 2005,
      giving rise to approximately $1.2 million in the future income tax recovery.
      The
      remainder relates to the excess of depletion taken over the use of tax pools
      in
      the fourth quarter, a result from the acquisition of High Point.





The
      corporate acquisitions in 2005 resulted in an increase of $96.9 million in
      the
      future income tax liability. This represents the difference between the tax
      basis and fair values assigned to the acquired assets.




9




**NON-CONTROLLING
      INTEREST**





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





In
      2005,
      953,129 exchangeable shares were exchanged into trust units (2004 - 1,784,264).





**NON-GAAP
      FINANCIAL MEASURES**





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





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





**FUNDS
      FROM OPERATIONS**





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


Three
                  Months Ended December 31,
              
              Years
                  EndedDecember
                  31,**2005**
              
              2004
                (restated)
              
              **2005**
              
              2004
                (restated)**Cash
                  provided by operating activities**
              
              **$**
              **20,575**
              
              $
              14,192
              
              **$**
              **68,120**
              
              $
              42,345Changes
                  in non-cash working capital items
              
              
              **(1,056**
              **)**
              
              (89
              )
              
              **2,425**
              
              
              7,897**Funds
                  from operations**
              
              **$**
              **19,519**
              
              $
              14,103
              
              **$**
              **70,545**
              
              $
              50,242





**QUARTERLY
      FINANCIAL INFORMATION**


**Quarterly
                Financial Information***(in
                thousands except for per unit amounts)***2005**
            
            2004Q1
              (restated)
            
            Q2
            
            Q3
            
            **Q4**
            
            Q1
              (restated)
            
            Q2
              (restated)
            
            Q3
              (restated)
            
            Q4
              (restated)Revenues
            
            $
            30,050
            
            $
            29,807
            
            $
            47,638
            
            **$**
            **50,248**
            
            $
            21,648
            
            $
            27,585
            
            $
            25,467
            
            $
            33,593Earnings
                (loss)before taxes and non-controlling interest
            
            $
            3,757
            
            $
            947
            
            $
            7,530
            
            **$**
            **(28,526**
            **)**
            $
            201
            
            $
            5,798
            
            $
            5,313
            
            $
            3,103Net
                earnings
            
            $
            4,252
            
            $
            2,567
            
            $
            7,088
            
            **$**
            **(12,937**
            **)**
            $
            2,396
            
            $
            4,455
            
            $
            3,920
            
            $
            3,256Net
                earnings (loss) per trust unitBasic
            
            $
            0.16
            
            $
            0.10
            
            $
            0.23
            
            **$**
            **(0.37**
            **)**
            $
            0.12
            
            $
            0.21
            
            $
            0.17
            
            $
            0.13Diluted
            
            $
            0.16
            
            $
            0.10
            
            $
            0.23
            
            **$**
            **(0.37**
            **)**
            $
            0.12
            
            $
            0.21
            
            $
            0.17
            
            $
            0.13Distributions
                (US$)
            
            $
            0.43
            
            $
            0.46
            
            $
            0.49
            
            **$**
            **0.52**
            
            $
            0.31
            
            $
            0.34
            
            $
            0.37
            
            $
            0.40





The
      quarterly information reflects a general trend to increasing revenues reflecting
      the overall growth of the Trust and the rising price of the oil and natural
      gas
      sold by the Trust. This growth has provided cash flow for the Trust to increase
      distributions to its unitholders.




10




**CASH
      DISTRIBUTIONS PAID TO UNITHOLDERS**





The
      Trust
      pays monthly cash distributions to its unitholders. Cash distributions are
      paid
      on the 15th of the following month (e.g. the December distribution was paid
      on
      January 15). The monthly cash distributions per trust unit since the inception
      of the Trust are as follows:





**US$**
            
            **2006**
            
            **2005**
            
            **2004**
            
            **2003**January
            
            **$**
            **0.18**
            
            **$**
            **0.14**
            
            $
            0.10February
            
            **$**
            **0.18**
            
            **$**
            **0.14**
            
            $
            0.10March
            
            **$**
            **0.18**
            
            **$**
            **0.15**
            
            $
            0.11April
            
            
            
            
            **$**
            **0.15**
            
            $
            0.11May
            
            
            
            
            **$**
            **0.15**
            
            $
            0.11June
            
            
            
            
            **$**
            **0.16**
            
            $
            0.12July
            
            
            
            
            **$**
            **0.16**
            
            $
            0.12August
            
            
            
            
            **$**
            **0.16**
            
            $
            0.12September
            
            
            
            
            **$**
            **0.17**
            
            $
            0.13October
            
            
            
            
            **$**
            **0.17**
            
            $
            0.13November
            
            
            
            
            **$**
            **0.17**
            
            $
            0.13December
            
            
            
            
            **$**
            **0.18**
            
            $
            0.14
            
            $
            0.10


**Three
                  months Ended**
                **December
                  31,**
              
              
              
              **Years
                  Ended**
                **December
                  31,****2005**
              
              2004
                (restated)
              
              *Change*
              
              **2005**
              
              2004
                (restated)
              
              *Change*Cash
                  distributions to unitholders
              
              **$**
              **21,067**
              
              $
              12,076
              
              
              74
              %
              **$**
              **66,195**
              
              $
              40,414
              
              
              64
              %Funds
                  from operations
              
              **$**
              **19,519**
              
              $
              14,103
              
              
              38
              %
              **$**
              **70,545**
              
              $
              50,242
              
              
              40
              %Cash
                  distributions as a percentage of funds from operations
              
              
              **108**
              **%**
              
              86
              %
              
              
              
              
              **94**
              **%**
              
              80
              %





In
      the
      fourth quarter, funds from operations were reduced due to several large
      adjustments. There was a reclassification
      of certainworkovers, which resulted in an expense of $2.2 million of
      previously capitalized items. The fourth quarter also recorded additional
      freehold and gross overriding royalties of $0.8 million pertaining to wells
      acquired through the 2004 Rocky Mountain Energy Corp. The capital tax accrual
      for 2005 was increased by $0.8 million as a result of finalizing the balance
      sheet values on an unconsolidated basis and including the High Point
      organizations in the calculation.





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





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




11





For
      Canadian tax purposes, cash distributions comprise of a return of capital
      portion, which is tax deferred, and return on capital portion, which is taxable
      income. The return of capital portion reduces the cost base of the trust units
      held. The cost base is required in the calculation of a capital gain or loss
      upon the disposition of the trust units. For 2005, the cash distributions
      declared for 2005 is approximately at 51% return on capital (taxable) and 49%
      return of capital (tax deferred). For tax information for non-resident
      unitholders, please visit our website at www.enterraenergy.com .





**CAPITAL
      EXPENDITURES**





The
      Trust
      does not have material commitments for capital expenditures. The business
      strategy is to have other companies spend the capital to develop our properties
      in exchange for the Trust receiving a 30% working interest in the developed
      properties at no additional cost. We also retain a right of first refusal to
      purchase the remaining 70% working interest. Any such purchases are financed
      with cash flow, issuing new trust units or incurring new debt.





The
      Trust
      closed three acquisitions in 2005. On January 26, 2005 the Trust closed an
      acquisition of petroleum and natural gas properties for cash consideration
      of
      $12.1 million. On June 1, 2005, the acquisition of Rocky Mountain Gas, Inc.
      closed for consideration of approximately $24.0 million, including $0.4 million
      of transaction costs. The consideration consisted of 736,842 exchangeable shares
      (exchangeable on a one-to-one basis into trust units) valued at $16.7 million,
      275,474 trust units valued at $6.3 million and $1.0 million in cash. The
      acquisition of High Point was closed on August 17, 2005, for consideration
      of
      approximately $201.5 million, including $1.3 million of transaction costs.
      In
      addition the Trust assumed $75.0 million in debt and $6.1 million working
      capital deficiency. The consideration consisted of 7,490,898 trust units valued
      at $168.5 million and 1,407,177 exchangeable shares (exchangeable on a
      one-to-one basis into trust units) valued at $31.7 million.





The
      following table represents the Trust's capital expenditures that were paid
      for
      with cash. The source of this cash was through private placements of trust
      units
      and from working capital. The table excludes capital expenditures, such as
      the
      portion of the RMG and High Point acquisitions, that were paid for with non-cash
      consideration such as trust units and exchangeable shares.


**Capital
                  Expenditures Paid with Cash***(in
                  thousands except for percentages)*Three
                  Months Ended December 31,
              
              
              
              Years
                  Ended
                December
                  31,**2005**
              
              2004
                (restated)
              
              *Change*
              
              **2005**
              
              2004
                (restated)
              
              *Change*Capital
                  expenditures net of disposals
              
              **$**
              **9,181**
              
              $
              615
              
              
              1,392
              %
              **$**
              **33,617**
              
              $
              30,409
              
              
              11
              %




Capital
      additions for the year ended December 31, 2005 were $424.2 million (2004 -
      $65.2
      million). In addition to the three acquisitions and the capital expenditures
      paid with cash, $1.9 million of net asset retirement obligations (“ARO”) were
      charged to property, plant and equipment.


Years
                  Ended
                December
                  31,**2005**
              
              2004
                (restated)Property
                  acquisitions
              
              **$**
              **393,784**
              
              $
              30,385Proceeds
                  on disposal of properties
              
              
              **-**
              
              
              (1,177
              )Drilling
                  and completions
              
              
              **10,637**
              
              
              11,001Facilities
                  and equipment
              
              
              **14,630**
              
              
              24,475Other
              
              
              **628**
              
              
              555Other
                  ARO additions
              
              
              **1,901**
              
              
              1,270Net
                  capital additions
              
              **$**
              **421,580**
              
              $
              66,509




12




For
      2006,
      the Trust plans to continue its capital additions through a combination of
      acquisitions and development activities. The Trust will continue to farm out
      its
      undeveloped land to keep capital expenditures to a minimum while still
      increasing its production base. This trend of lower drilling and completions
      and
      facilities and equipment costs is expected to continue through 2006. The Trust
      also closed the acquisition of roughly 6,300 boe/day of assets in Oklahoma
      during the first quarter of 2006.





**RESERVES
      AND PRESENT VALUE SUMMARY**





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





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





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




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





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





The
      Trust
      has its reserves evaluated by independent engineers each year. McDaniel and
      Associates Consultants Ltd. ("McDaniel") independently evaluated the 2005
      Canadian asset reserves of the Trust and Sproule Associates Inc. (“Sproule”)
      independently evaluated the Trust’s affiliate Rocky Mountain Gas 2005 reserves
      as at December 31, 2005.




13




**Reserve
                Continuity****Oil
                and Gas (mboe)****Proved**
            
            **Probable**
            
            **Total****December
                31, 2003**
            
            
            6,142.9
            
            
            2,291.9
            
            
            8,434.8Discoveries
                and extensions
            
            
            185.7
            
            
            81.3
            
            
            267.0Purchases
            
            
            3,544.2
            
            
            1,362.0
            
            
            4,906.2Dispositions
            
            
            (29.0
            )
            
            (2.0
            )
            
            (31.0
            )Production
            
            
            (2,550.5
            )
            
            -
            
            
            (2,550.5
            )Revision
                of prior estimates
            
            
            92.2
            
            
            (1,709.3
            )
            
            (1,617.1
            )**December
                31, 2004**
            
            
            7,385.5
            
            
            2,023.9
            
            
            9,409.4Discoveries
                and extensions
            
            
            **47.5**
            
            
            **13.8**
            
            
            **61.3**Purchases
                (including East Central Properties acquisition)
            
            
            **9,784.1**
            
            
            **5,020.1**
            
            
            **14,804.2**Dispositions
            
            
            **-**
            
            
            **-**
            
            
            **-**Production
            
            
            **(2,825.3**
            **)**
            
            **-**
            
            
            **(2,825.3**
            **)**Revision
                of prior estimates(1)
            
            
            **(96.8**
            **)**
            
            **(2,320.6**
            **)**
            
            **(2,417.4**
            **)****December
                31, 2005**
            
            
            **14,294.9**
            
            
            **4,737.2**
            
            
            **19,032.1**(1)
                Revision of prior estimates includes revision of 1,630 mboe related
                to
                2005 purchased assets in the U.S. based upon performance versus initial
                expectations





Proved
      plus probable reserves increased 102% from the end of 2004 to the end of 2005
      due to ongoing development and three acquisitions. Proved reserves increased
      94%
      from 7,385.5 mboe to 14,294.9 mboe and probable reserves increased 134% from
      2,023.9 mboe to 4,737.2 mboe. Total proved reserves represent 75% of total
      reserves versus 78% in 2004.





Finding
      costs incurred over the last three years are highlighted below, along with
      the
      recycle ratios for each year. The recycle ratio is a critical measure of any
      success in the oil and gas industry. It compares the netbacks with the finding
      costs. Basically, a recycle ratio of one is a “break even point”, indicating
      that the enterprise earns the same amount when selling its production as it
      pays
      when finding new production.




14




**Finding
                  costs and recycle ratio***(in
                  $/boe, except for capital expenditures which are in
                  thousands)***2005**
              
              **2004**
              
              **2003**
              
              **3-year**
                **Average****Capital
                  expenditures**
              
              $
              421,580
              
              $
              66,509
              
              $
              51,577
              
              $
              179,889**Reserves**Proved
                  reserves added in the year (in mboe)
              
              
              9,831.6
              
              
              3,729.9
              
              
              2,940.1
              
              
              5,500.5Probable
                  reserves added in the year (in mboe)
              
              
              5,033.9
              
              
              1,443.3
              
              
              892.5
              
              
              2,456.6Established
                  reserves added in the year (in mboe)(1)
              
              
              14,865.5
              
              
              5,173.2
              
              
              3,832.6
              
              
              7,957.1**Finding
                  costs**Proved
                  reserves ($/boe)
              
              
              42.88
              
              
              17.83
              
              
              17.54
              
              
              32.70Established
                  reserves ($/boe)
              
              
              28.36
              
              
              12.86
              
              
              13.46
              
              
              22.61**Recycle
                  ratio (netbacks divided by finding costs)**Corporate
                  netbacks ($/boe)(2)
              
              
              25.98
              
              
              21.06
              
              
              19.93
              
              
              22.32Corporate
                  recycle ratio (based on established finding costs)
              
              
              0.92
              
              
              1.64
              
              
              1.48
              
              
              0.99Operating
                  netbacks ($/boe)(3)
              
              
              31.31
              
              
              23.67
              
              
              22.73
              
              
              25.90Operating
                  recycle ratio (based on established reserves)
              
              
              1.10
              
              
              1.84
              
              
              1.69
              
              
              1.15(1)Established reserves are proved plus probable reserves(2)Corporate netbacks are production revenue less royalties, operating
                  costs,
                  G&A and interest expense(3)Operating netbacks are production revenue less royalties and operating
                  costs




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


Enterra's
      high finding costs in 2005 are largely caused by the three acquisitions that
      were made. The very competitive acquisition market in 2005 resulted in increased
      acquisition costs versus previous years. The reserve additions from development
      opportunities were more than offset by negative revisions due to earlier
      shutting in of several pools in Rocky Mountain Gas due to increased nitrogen
      content in the gas making it unmarketable.





An
      additional factor impacting finding costs in 2005 is the higher than normal
      expenditures on capital projects to maintain existing production. Examples
      of
      these projects are the consolidation of existing production facilities to lower
      operating costs and the replacement of existing failed pipelines.




15




**Enterra
                Energy Trust - Estimated Petroleum and Natural Gas Reserves and Net
                Present Value****(December
                31, 2005) (NPV in thousands)****Light/**
              
              
              
              
              
              
              
              
              
              **Net
                  Present Value****Medium**
              
              **Heavy**
              
              **Natural**
              
              
              
              
              
              **Before
                  Income Tax (M$)****Oil**
              
              **Oil**
              
              **Gas**
              
              **NGL’s**
              
              **Total****(MBBL)**
              
              **(MBBL)**
              
              **(MMCF)**
              
              **(MBBL)**
              
              **(MBOE)**
              
              **0%**
              
              **10%**
              
              **15%****Canadian
                  Assets****McDaniel
                  report**Proved
                  Producing
              
              
              3,623.6
              
              
              1,292.4
              
              
              33,986.3
              
              
              1,121.1
              
              
              11,701.6
              
              
              321.7
              
              
              249.4
              
              
              226.9Proved
                  Non-Producing
              
              
              4.2
              
              
              -
              
              
              5,877.4
              
              
              143.4
              
              
              1,127.1
              
              
              32.6
              
              
              27.8
              
              
              25.9Proved
                  Undeveloped
              
              
              53.4
              
              
              -
              
              
              4,634.3
              
              
              141.8
              
              
              967.5
              
              
              32.2
              
              
              23.9
              
              
              21.3Total
                  Proved
              
              
              3,681.2
              
              
              1,292.4
              
              
              44,498.0
              
              
              1,406.3
              
              
              13,796.2
              
              
              386.5
              
              
              301.1
              
              
              274.1Total
                  Probable
              
              
              1,148.1
              
              
              421.2
              
              
              15,610.1
              
              
              523.5
              
              
              4,694.5
              
              
              139.2
              
              
              76.8
              
              
              62.7Total
                  Proved &
                Probable
              
              
              4,829.3
              
              
              1,713.6
              
              
              60,108.1
              
              
              1,929.8
              
              
              18,490.7
              
              
              525.7
              
              
              377.9
              
              
              336.8**United
                  States Assets****Sproule
                  report**Proved
                  Producing
              
              
              -
              
              
              -
              
              
              2,993.0
              
              
              -
              
              
              498.7
              
              
              5.9
              
              
              5.2
              
              
              4.9Proved
                  Non-Producing
              
              
              -
              
              
              -
              
              
              -
              
              
              -
              
              
              -
              
              
              -
              
              
              -
              
              
              -Proved
                  Undeveloped
              
              
              -
              
              
              -
              
              
              -
              
              
              -
              
              
              -
              
              
              -
              
              
              -
              
              
              -Total
                  Proved
              
              
              -
              
              
              -
              
              
              2,993.0
              
              
              -
              
              
              498.7
              
              
              5.9
              
              
              5.2
              
              
              4.9Total
                  Probable
              
              
              -
              
              
              -
              
              
              256.0
              
              
              -
              
              
              42.7
              
              
              0.3
              
              
              0.2
              
              
              0.1Total
                  Proved &Probable
              
              
              -
              
              
              -
              
              
              3,249.0
              
              
              -
              
              
              541.4
              
              
              6.2
              
              
              5.4
              
              
              5.0**Consolidated
                  Assets**Proved
                  Producing
              
              
              3,623.6
              
              
              1,292.4
              
              
              36,979.3
              
              
              1,121.1
              
              
              12,200.3
              
              
              327.6
              
              
              254.6
              
              
              231.8Proved
                  Non-Producing
              
              
              4.2
              
              
              -
              
              
              5,877.4
              
              
              143.4
              
              
              1,127.1
              
              
              32.6
              
              
              27.8
              
              
              25.9Proved
                  Undeveloped
              
              
              53.4
              
              
              -
              
              
              4,634.3
              
              
              141.8
              
              
              967.5
              
              
              32.2
              
              
              23.9
              
              
              21.3Total
                  Proved
              
              
              3,681.2
              
              
              1,292.4
              
              
              47,491.0
              
              
              1,406.3
              
              
              14,294.9
              
              
              392.4
              
              
              306.3
              
              
              279.0Total
                  Probable
              
              
              1,148.1
              
              
              421.2
              
              
              15,866.1
              
              
              523.5
              
              
              4,737.2
              
              
              139.5
              
              
              77.0
              
              
              62.8Total
                  Proved &Probable
              
              
              4,829.3
              
              
              1,713.6
              
              
              63,357.1
              
              
              1,929.8
              
              
              19,032.1
              
              
              531.9
              
              
              383.3
              
              
              341.8(1)
                  The Sproule report was converted to Canadian dollars by the Trust
                  using
                  and exchange rate of US$0.85 per Canadian dollar.


**LIQUIDITY
      & CAPITAL RESOURCES**





The
      Trust’s business strategy is to have other companies spend the capital to
      develop properties in exchange for the Trust receiving a 30% working interest
      in
      the developed properties at no additional cost. The Trust also retains a right
      of first refusal to purchase the remaining 70% working interest. Any such
      purchases will be financed by issuing new equity and/or with debt. The Trust
      does not have material commitments for capital expenditures.





In
      March
      2006, the Trust closed a $110.0 million senior secured bridge facility. This
      non-revolving credit facility was be used to payout the existing $100.0 million
      credit facilities of the Trust. The facility bears interest at 2.5% above bank
      prime lending rates and matures on December 31, 2006. The facility is secured
      by
      a first charge over all Canadian assets of the Trust and a second charge over
      all US assets.





16





At
      December 31, 2005, bank indebtedness represented the outstanding balance under
      two revolving lines of credit that had a total capacity of $100.0 million.
      These
      credit facilities replaced the Trust’s previous $41.0 million credit facilities.
      Drawings on the revolving facilities bear interest at 0.25% above the bank’s
      prime lending rate or bankers’ acceptance rates plus margins which were
      initially set at 135 basis points and are be subject to adjustment up or down
      prospectively, on a three-month basis as determined by the Trust’s consolidated
      debt to cash flow ratio. Security is provided by a first charge over all of
      the
      Trust’s assets. The amounts available under these new credit facilities are
      subject to a semi-annual borrowing base determination.





A
      bridge
      credit facility was put in place on August 17, 2005 to facilitate the
      acquisition of High Point. The bridge credit facility was a reducing
      non-revolving secured loan with a principal amount of $75.0 million. Security
      was provided by a first charge on all of the High Point assets that were
      acquired. The loan bore interest at bank prime rate plus 1% and was repayable
      from the proceeds of any debt or equity financing or proceeds from the disposal
      of assets. The loan was repaid in full on November 28, 2005 upon the drawing
      on
      the Trust’s above noted credit facilities.





On
      April
      22, 2005, the Trust entered into an arrangement with Kingsbridge Capital Limited
      whereby Kingsbridge has committed to purchase US$100.0 million of trust units.
      The Trust is not obligated to access any of the capital available under this
      commitment yet has an option to draw on this commitment through installments
      for
      a period of 24 months or until the US$100.0 million is fully drawn. In
      conjunction with the agreement, Kingsbridge was granted 301,000 warrants to
      purchase trust units at initially US$25.77 per trust unit.





On
      November 9, 2005, the Trust filed a US$500.0 million Base Shelf Prospectus
      and
      corresponding US Registration Statement. This filing enables the Trust to access
      the Kingsbridge equity arrangement .
      The
      Trust issued 689,079 units for $15.8 million under the Kingsbridge arrangement.





On
      December 20, 2005 the Trust filed a Prospectus Supplement for the issuance
      of up
      to 950,000 trust units at US $16.00 per unit. Under
      the
      prospectus, the Trust issued 882,500 units at USD $16.00 per unit under
      this supplement.




*(in
                thousands)*As
                at December 31,**2005**
            
            2004Working
                capital (deficiency)
            
            **$**
            **(112,397**
            **)**
            $
            (42,354
            )Working
                capital (deficiency) excluding bank debt
            
            **$**
            **(16,947**
            **)**
            $
            1,576





The
      working capital deficiency mainly relates to the requirement of GAAP that the
      Trust's bank indebtedness and bridge credit facility are classified as current
      liabilities even though there is no expectation that the revolving lines of
      credit will be called by the bank.


The
        Trust
        does not expect to repay the two bridge facilities from internally generated
        cash and will need to seek additional financing through the issuance of debt
        or
        equity.
 
 The
        Trust’s credit facilities require the Trust to comply with certain financial
        covenants. Under the arrangements, the lenders can restrict the distributions
        of
        the Trust if the Trust is in default. In 2006, the Trust’s US$200 million credit
        facility restricts the Trust’s ability to distribute cash flow from the U.S.
        cost center to US$1.5 million per month.


The
      Trust
      expects to increase its cash provided by operating activities and its funds
      from
      operations in 2006. The continued benefit of the cash flow from the High Point
      acquisition combined with the acquisition of the Oklahoma assets is expected
      to
      provide strong cash flows for the Trust to fund its working capital, capital
      expenditures and distributions for 2006.




17




**CONTRACTUAL
        OBLIGATIONS**





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


Payments
                  due by period (in 000’s)***Contractual
                  Obligations***
              ***Total***
              ***Less
                  than 1 year***
              ***1-
                  3 years***
              ***3
                  - 5 years***
              ***More
                  than 5 years***Short-Term
                  Debt Obligations
              $99,521
              $99,521
              $-
              $-
              $-Interest
                  on above debt (1)
              5,011
              5,011
              -
              -
              -Long-Term
                  Debt Obligations
              -
              -
              -
              -
              -Capital
                  (Finance) Lease Obligations
              2,864
              1,065
              1,799
              --
              --Operating
                  Lease Obligations
              5,654
              1,160
              2,140
              2,257
              97Purchase
                  ObligationsOther
                  Long-Term Liabilities Reflected on the Registrant's Balance Sheet
                  under
                  Canadian GAAP
              24,323
              -
              -
              -
              24,323Total
              $137,373
              $106,757
              $3,939
              $2,257
              $24,420
 *(1)
        using the December 31, 2005 loan balance and its interest rate of
        5.25%*


The
      Trust
      has indemnified all of the directors and officers of the Trust and all the
      officers, directors, shareholders, employees and agents of JED Oil Inc. There
      is
      no pending litigation or proceeding involving any director or officer of the
      Trust for which a claim is being sought, nor is the Trust aware of any
      threatened litigation that may result in claims.





**SUBSEQUENT
        EVENTS AND PROPOSED TRANSACTIONS**


During
      the first quarter of 2006, the Trust acquired roughly 5,000 boe/day of producing
      oil and gas assets located in Oklahoma. In the second quarter of 2006, the
      Trust
      expects to complete a final closing for additional working interests in the
      properties representing roughly 1,300 boe/day. The assets consist of
      approximately 80% natural gas and 20% light oil and include over 53,000 net
      acres of land of which over 25,000 net acres are undeveloped. The current
      operating staff of the assets is being retained by the Trust.





The
      purchase price of US$221.0 million was paid for through the issuance of
      5,178,792 units of the Trust valued at US $91.7 million, cash of US $102.3
      million and US $27.0 million of assumed debts. Certain post closing purchase
      price adjustment provisions remain in place, based on production rates achieved
      from the assets through September 19, 2006. The purchase prices on the final
      closing of the additional working interests will be paid with a combination
      of
      units and cash.





The
      Trust
      is in the process of entering into a farmout agreement with Petroflow Energy
      Inc. (“Petroflow”), an oil and gas development company, to fund 100% of the
      drilling and completion costs on the undeveloped lands to maximize their
      production potential. The Chief Executive Officer of Enterra Energy Company
      as
      administrator of the Trust owns, directly and indirectly, approximately 20%
      of
      the outstanding shares of Petroflow.





On
      January 18, 2006, the Trust entered into an arrangement with a bank for a $50.0
      million USD bridge credit facility. This credit facility was used to secure
      the
      acquisition of the Oklahoma assets. The facility was a reducing non-revolving
      loan secured by a first charge over the notes from the sellers of the Oklahoma
      assets, which were secured by the Oklahoma assets. The loan bore interest at
      U.S. dollar commercial loan rate + 0.5% and was repaid on March 22,
      2006.





In
      March
      2006 the Trust closed a US $200.0 million senior secured bridge credit facility
      to fund the acquisition of the Oklahoma assets, repay the US $50.0 million
      bridge credit facility noted above and provide additional working capital to
      the
      Trust. This non-revolving facility bears interest at 4.5% above London Interbank
      Offering Rate and matures September 20, 2006 with a one-time option to extend
      the facility for an additional three-month period. The facility is secured
      by a
      first charge over all US assets of the Trust and a second charge over all
      Canadian assets. As a fee for the facility, the Trust issued 110,000 units
      to
      Fortress Credit Corp. The
      terms
      of the agreement restrict the Trust’s ability to distribute cash flow from the
      U.S. cost center to US $1.5 million per month.





In
      2006,
      the Trust closed a $110.0 million senior secured bridge facility. This reducing
      non-revolving credit facility was be used to payout the existing $100.0 million
      credit facilities of the Trust. The facility bears interest at 2.5% above bank
      prime lending rates and matures on December 31, 2006. The facility is reduced
      to
      $100 million on June 30, 2006. The facility is secured by a first charge over
      all Canadian assets of the Trust and a second charge over all US
      assets.




18




The
      Trust
      does not expect to repay the two bridge facilities from internally generated
      cash and will need to seek additional financing through the issuance of debt
      or
      equity.





**RELATIONSHIP
      WITH JED OIL INC. (“JED”)**





Under
      a
      Technical Services Agreement between the Trust and JED, JED provided certain
      staff to the Trust while the Trust provided offices and other administrative
      services to JED. During 2005, JED employees were considered consultants to
      the
      Trust and as such, JED’s employees were eligible to participate in benefit plans
      of the Trust. The Chairman of JED is also the Chairman of the Trust.





Under
      the
      Technical Services Agreement between the Trust and JED, costs of management,
      development, exploitation, operations and general and administrative activities
      were allocated based on relative production and capital expenditures, or as
      otherwise mutually agreed. For the year ended December 31, 2005, total general
      and administrative expenses charged by JED to the Trust on a cost recovery
      basis
      were approximately $3.9 million and field operating expenses charged by JED
      to
      the Trust on a cost recovery basis were approximately $3.0 million.





Effective
      January 1, 2006 the Technical Services Agreement between the Trust and JED
      was
      terminated. The current Chairman of the Trust has resigned effective March
      31,
      2006 and remains as Chairman of JED.





JED
      had
      loaned $8.0 million to the Trust secured by a promissory note. The note had
      no
      stated terms of repayment and an initial interest rate of bank prime rate plus
      0.4%. Effective August 1, 2005 interest charged on the note increased to 10%.
      For the year ended December 31, 2005, $0.4 million (2004 - $0 million) of
      interest was charged on the loaned funds. The promissory note, plus interest
      charged to January 31, 2006 was repaid in full February 1, 2006.




The
      balance due to JED at December 31, 2005 was $15.2 million (December 31, 2004
      -
      $4.5 million) consisting of $8.0 million of notes payable and $7.2 million
      of
      other transactions.





**RELATED
      PARTY TRANSACTIONS**





During
      2005 the Trust paid $0.4 million to Macon Resources Ltd., a company 100% owned
      by the Chief Executive Officer of EEC, for management services provided by
      the
      Chief Executive Officer and the Chief Financial Officer. During 2005 the Trust
      issued 400,000 trust unit options to Macon at $23.96 per option. The options
      have a 5-year life and vest over a 3-year period.





There
      were no related party transactions in 2004.





**OFF
      BALANCE SHEET ARRANGEMENTS**





There
      were no off balance sheet arrangements in 2005 or 2004 other than the operating
      leases discussed elsewhere in the MD&A.




19




**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 and warrants
      to purchase trust units outstanding. The following table outlines the units,
      exchangeable shares, options and warrants outstanding:


**Outstanding
                unit data***(units
                / shares)***As
                at**
            
            **March
                27, 2006**
            
            **December
                31, 2005**
            
            December
                31, 2004Trust
                units
            
            
            **43,054,024**
            
            
            **36,504,416**
            
            
            25,426,800Exchangeable
                sharesEEC
                exchangeable shares
            
            
            **336,946**
            
            
            **348,146**
            
            
            410,770RMAC
                Series A exchangeable shares
            
            
            **-**
            
            
            **-**
            
            
            142,444RMG
                exchangeable shares
            
            
            **736,842**
            
            
            **736,842**
            
            
            -RMAC
                Series B exchangeable shares
            
            
            **93,905**
            
            
            **659,116**
            
            
            -Trust
                unit options
            
            
            **1,451,405**
            
            
            **1,431,405**
            
            
            950,000Warrants
            
            
            **301,000**
            
            
            **301,000**
            
            
            -





The
      exchangeable shares of the subsidiary corporations are not listed for trading
      on
      an exchange and are treated as a minority interest under GAAP. The exchangeable
      shares are convertible into trust units based on their respective exchange
      ratios.





**SENSITIVITIES**





The
      Trust
      is exposed to the normal risks inherent within the oil and gas sector, including
      commodity price risk, foreign-currency rate risk, interest rate risk and credit
      risk. The Trust manages its operations in a manner intended to minimize
      exposure, as described in note 14 to the consolidated financial
      statements.





**Credit
      Risk**


Credit
      risk is the risk of loss resulting from non-performance of contractual
      obligations by a customer or joint venture partner. A substantial portion of
      the
      Trust’s accounts receivable are with customers in the energy industry and are
      subject to normal industry credit risk. The Trust assesses the financial
      strength of its customers and joint venture partners through regular credit
      reviews in order to minimize 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. The price we receive for oil and natural gas production is
      based on a benchmark expressed in U.S. dollars, which is the standard for the
      oil and natural gas industry worldwide. Monthly distributions are paid on a
      value expressed in U.S. dollars. However, operating expenses, drilling expenses
      and general overhead expenses in Canadian 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
      CDN dollar would impact the Trust’s earnings by approximately $1.9 million and
      our cash provided by operating activities by $1.2 million.





**Commodity
      Price Risk**


The
      Trust’s financial condition, results of operations and capital resources are
      highly dependent upon the prevailing market prices of oil and natural gas.
      These
      commodity prices are subject to wide fluctuations and market uncertainties
      due
      to a variety of factors that are beyond the Trust’s control. Factors influencing
      oil and natural gas prices include the level of global demand for crude oil,
      the
      foreign supply of oil and natural gas, the establishment of and compliance
      with
      production quotas by oil exporting countries, weather conditions which determine
      the demand for natural gas, the price and availability of alternative fuels
      and
      overall economic conditions. It is impossible to predict future oil and natural
      gas prices with any degree of certainty. Sustained weakness in oil and natural
      gas prices may adversely affect the Trust’s financial condition and results of
      operations, and may also reduce the amount of oil and natural gas reserves
      that
      the Trust can produce economically. Any reduction in the Trust’s oil and natural
      gas reserves, including reductions due to price fluctuations, can have an
      adverse affect on the Trust’s ability to obtain capital for our development
      activities. Similarly, any improvements in oil and natural gas prices can have
      a
      favorable impact on the Trust’s financial condition, results of operations and
      capital resources. If the WTI oil price were to change by US$1.00 per bbl,
      the
      impact on earnings would be approximately $1.8 million and the impact on cash
      flow would be approximately $2.9 million. If natural gas prices were to change
      by US$0.50 per mcf, the impact on earnings would be approximately $1.4 million
      and the impact on cash provided by operating activities would be approximately
      $2.3 million.




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





**Interest
      Rate Risk**


Interest
      rate risk exists principally with respect to indebtedness that bears interest
      at
      floating rates. At December 31, 2005, the Trust had $95.5 million of
      indebtedness bearing interest at floating rates. If interest rate were to change
      by one full percentage point, the net impact on earnings would be approximately
      $0.6 million and the net impact on our cash provided by operating activities
      would be approximately $1.0 million.





Summarized
      below are the Trust’s sensitivities to various risks, based on its 2005
      operations:





**Sensitivity**
            
            **Estimated
                2006 Impact On: (‘000s)****Net
                Earnings**
            
            **Cash
                Flow**Crude
                oil - US$1.00/bbl change in WTI
            
            $
            1,822
            
            $
            2,921Natural
                gas - US$0.50/mcf change
            
            $
            1,447
            
            $
            2,320Foreign
                exchange - $0.01 change in U.S. to Cdn dollar
            
            $
            1,888
            
            $
            1,178Interest
                rate - 1% change
            
            $
            595
            
            $
            955





**MANAGEMENT’S
      EVALUATION OF DISCLOSURE CONTROLS AND PROCEDURES**





As
        at the
        financial year ended December 31, 2005, an evaluation was carried out under
        the
        supervision of and with the participation of the Trust’s management, including
        the CEO and CFO, of the effectiveness of the Trust’s disclosure controls and
        procedures. Based on that evaluation, the CEO and the CFO concluded that
        the
        design and operation of these disclosure controls and procedures were effective
        as at December 31, 2005 to provide reasonable assurance that material
        information relating to the Trust would be made known to them by others within
        the Trust.





**CRITICAL
      ACCOUNTING ESTIMATES**





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





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





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





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




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





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





**CHANGE
      IN ACCOUNTING POLICY**





On
      January 19, 2005, the CICA issued EIC-151 “Exchangeable Securities Issued by
      Subsidiaries of Income Trusts” that states that equity interests held by third
      parties in subsidiaries of an income trust should be reflected as either
      non-controlling interest or debt in the consolidated balance sheet unless they
      meet certain criteria. EIC-151 requires that the shares be nontransferable
      to be
      classified as equity. The Trust's exchangeable shares are transferable and,
      in
      accordance with EIC-151, have been reclassified to non-controlling interest
      on
      the consolidated balance sheets.





Since
      the
      exchangeable shares of the Trust were not initially recorded at fair value,
      subsequent exchanges for trust units are measured at the fair value of the
      trust
      units issued. The excess amounts are allocated to property, plant and equipment
      and to goodwill. In addition, a portion of consolidated earnings before
      non-controlling interest is reflected as a reduction to such earnings in the
      Trust’s consolidated statements of earnings and accumulated earnings. Prior
      periods have been retroactively restated as required by the new accounting
      standard.





The
      following tables illustrate the impact of the new accounting policy on the
      consolidated balance sheet as at December 31, 2004 presented for comparative
      purposes:




December
                31, 2004
            
            As
                reported
            
            Change
                upon adoption
              of
                EIC-151
            
            As
                restatedProperty,
                plant and equipment
            
            $
            146,910
            
            $
            1,548
            
            $
            148,458Goodwill
            
            
            29,991
            
            
            19,279
            
            
            49,270Future
                income tax liability
            
            
            21,526
            
            
            602
            
            
            22,128Non-controlling
                interest
            
            
            -
            
            
            3,349
            
            
            3,349Unitholders'
                capital
            
            
            111,653
            
            
            20,554
            
            
            132,207Exchangeable
                shares
            
            
            3,273
            
            
            (3,273
            )
            
            -Accumulated
                earnings
            
            
            27,903
            
            
            (405
            )
            
            27,498





The
      following table illustrates the impact of the new accounting policy on 2004
      net
      earnings and net earnings per trust unit:


Q1
            
            Q2
            
            Q3
            
            Q4
            
            2004Net
                earnings before change in accounting policy
            
            $
            2,562
            
            $
            4,647
            
            $
            4,138
            
            $
            3,417
            
            $
            14,764Increase
                in depletion, net of taxes
            
            
            (63
            )
            
            (94
            )
            
            (83
            )
            
            (89
            )
            
            (329
            )Non-controlling
                interest
            
            
            (103
            )
            
            (98
            )
            
            (134
            )
            
            (73
            )
            
            (408
            )Net
                earnings after change in accounting policy
            
            $
            2,396
            
            $
            4,455
            
            $
            3,921
            
            $
            3,256
            
            $
            14,027Net
                earnings per trust unit, as reportedBasic
                and diluted
            
            $
            0.12
            
            $
            0.21
            
            $
            0.17
            
            $
            0.13
            
            $
            0.63Net
                earnings per trust unit, as restatedBasic
                and diluted
            
            $
            0.12
            
            $
            0.21
            
            $
            0.17
            
            $
            0.12
            
            $
            0.62





**ADDITIONAL
      INFORMATION**





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




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