Exhibit
      99.3


**MANAGEMENT’S
            DISCUSSION AND ANALYSIS (“MD&A”)**
 
 The
            following discussion and analysis of financial results is dated February
            18,
            2006 and is to be read in conjunction with the audited consolidated financial
            statements as at and for the years ended December 31, 2005 and 2004.
            All amounts
            are stated in Canadian dollars unless otherwise specified. All note references
            relate to the notes included with the consolidated financial statements.
            In
            accordance with Canadian practice, production volumes, reserve volumes
            and
            revenues are reported on a gross basis, before deduction of crown and
            other
            royalties, unless otherwise stated. Where applicable, natural gas has
            been
            converted to barrels of oil equivalent (“BOE”) based on 6 Mcf:1 BOE. The BOE
            rate is based on an energy equivalent conversion method primarily applicable
            at
            the burner tip and does not represent a value equivalent at the wellhead.
            Use of
            BOE in isolation may be misleading.
 
 **NON-GAAP
            MEASURES**
 
 Throughout
            the MD&A, we use the terms funds flow from operations (“funds flow”) and
            cash available for distribution. These terms as presented do not have
            any
            standardized meaning as prescribed by Canadian generally accepted accounting
            principles (“GAAP”), and therefore they may not be comparable with the
            calculation of similar measures for other entities. Funds flow as presented
            is
            not intended to represent operating cash flows or operating profits for
            the
            period nor should it be viewed as an alternative to cash flow from operating
            activities, net earnings or other measures of financial performance calculated
            in accordance with GAAP. Funds flow is used by management to analyze
            operating
            performance, leverage and liquidity. All references to funds flow throughout
            this report are based on cash flow from operating activities before changes
            in
            non-cash working capital. Cash available for distribution is calculated
            using
            funds flow less discretionary amounts of cash withheld for acquisitions,
            capital
            expenditures and debt repayment. Refer to the Cash Available for Distribution
            section of the MD&A for a quantitative reconciliation of “funds flow” to
            cash flow from operating activities.
  **2005
            OVERVIEW**
 
 2005
            was an extremely active year with the acquisitions of TriLoch Resources
            Inc.
            (“TriLoch”) and Lyco Energy Corporation (“Lyco”) occurring throughout our third
            quarter. The acquisition of Lyco was a strategic move into the United
            States and
            has provided further opportunities evidenced by the acquisition of Sleeping
            Giant LLC (“Sleeping Giant”) which closed in the fourth quarter. These
            acquisitions, collectively, added approximately 10,000 BOE/day of production
            and
            42.8 MMBOE of total proved plus probable reserves, replacing approximately
            147%
            of 2005 total production.
 
 Overall
            we achieved our corporate guidance targets for annual production, operating
            costs per BOE and general and administrative (“G&A”) costs per BOE.
            Development capital expenditures were $13.7 million higher than our guidance
            due
            to additional opportunities and increased costs. Our annual production
            increased
            6% year over year due to our capital program and acquisitions. Exit production
            was approximately 85,000 BOE/day based on December’s monthly average, which is
            below our guidance of 86,000 BOE/day due to delays and facility restrictions.
            We
            estimate 3,800 BOE/day associated with 2005 capital spending was delayed
            and is
            expected to come on production early in 2006.
 
 Compared
            to 2004, funds flow from operations increased 47%, net income per trust
            unit
            increased 52% and distributions to unitholders increased 20%. Additional
            production combined with a 28% rise in commodity prices were the main
            contributors to the year-over-year increases which were partially offset
            by a 4%
            increase in operating costs.
 
 **Highlights**
 
 •
                  Our
                      Canadian unitholders realized a 38.2% total return in 2005
                      (representing
                      the appreciation in unit price plus distributions paid during
                      the year).
 •
                  Our
                      U.S. unitholders realized a 42.1% total return in 2005, as
                      the
                      appreciation in the Canadian dollar effectively increased distributions
                      and the unit price when exchanged into U.S. dollars.
 
 •
                  Rising
                      commodity prices and higher production increased funds flow
                      from
                      operations to $794.4 million or $7.28 per trust unit, an increase
                      of 34%
                      per unit.
 •
                  Distributions
                      to unitholders increased by 20% to $511.1 million or 8% per
                      unit to $4.54
                      per unit.
 •
                  Actual
                      monthly distributions per trust unit increased from $0.35 to
                      $0.42 during
                      2005.
 •
                  Average
                      selling price per BOE increased 28% to $52.36 due to strengthening
                      commodity prices.
 •
                  Production
                      averaged 79,727 BOE/day, a new record, which exceeded our annual
                      target of
                      79,000 BOE/day.
 •
                  Total
                      development capital expenditures for the year were $368.7 million.
  
  
 •
                  On
                      July 1, 2005 we closed the acquisition of TriLoch with the
                      issuance of 1.6
                      million trust units for total consideration of $77.4 million.
 •
                  On
                      August 30, 2005 we completed the acquisition of Lyco for total
                      consideration of $501.9 million, our single largest transaction
                      to date
                      and our first acquisition outside of
                      Canada.
 •
                  In
                      connection with the Lyco acquisition we completed an equity
                      offering,
                      issuing 10.6 million trust units for gross proceeds of $492.0
                      million
                      ($466.9 million net of costs).
 •
                  On
                      October 4, 2005 we closed the acquisition of Sleeping Giant
                      for total
                      consideration of $111.9 million, increasing our working interest
                      on
                      existing U.S. properties.
 
 •
                  Net
                      income increased 67% to $432.0 million. On a trust unit basis
                      the increase
                      was 52% to $3.96 per unit reflecting the increase in trust
                      units
                      outstanding.
 •
                  Our
                      payout ratio decreased from 79% to 64% as we retained additional
                      funds
                      flow for development capital
                      opportunities.
 •
                  Operating
                      costs were $7.45/BOE, consistent with our guidance for 2005.
                      This
                      represented a 4% increase from 2004 despite rapidly rising
                      industry
                      costs.
 •
                  Cash
                      G&A costs were in line with our guidance at $1.28/BOE.
 •
                  Our
                      commodity price risk management costs were $142.6 million ($4.90/BOE)
                      during 2005 due to record high commodity prices.
 
 •
                  Drilling
                      efforts resulted in a success rate of over 99% with participation
                      in 393
                      net wells.
 •
                  Our
                      finding, development and acquisition costs (“FD&A”) for the year were
                      $19.55/BOE on a proved basis and $17.18/BOE on a proved plus
                      probable
                      basis including future development
                      capital.
 •
                  Proved
                      reserves increased 12% to 313.2 MMBOE and proved plus probable
                      reserves
                      increased 11% to 449.1 MMBOE.
 •
                  Positive
                      reserve additions from development capital spending and acquisitions
                      replaced 217% of 2005 production on a proved basis, and 247%
                      on a proved
                      plus probable basis.
 •
                  Enerplus’
                      Reserve Life Index (“RLI”) continued to be one of the longest in the
                      sector at 9.9 years on a proved basis and 13.5 years on a proved
                      plus
                      probable basis.
 •
                  Our
                      recycle ratio (operating income divided by FD&A) was 1.8x on a
                      three-year basis and 1.7x for 2005 using proved plus probable
                      reserves.
 •
                  We
                      continue to maintain a conservative balance sheet as evidenced
                      by a net
                      debt to trailing funds flow ratio of 0.8x.
 
 **RESULTS
            OF OPERATIONS**
 
 **Production**
 
 Daily
            production increased 6% during 2005 averaging 79,727 BOE/day, up from
            75,130
            BOE/day in 2004. This increase was primarily due to our development capital
            program and acquisitions. The most significant acquisitions completed
            during the
            year included TriLoch, Lyco and Sleeping Giant.
 
 Average
            production during 2005 was weighted 57% natural gas and 43% liquids on
            a BOE
            basis. Our operations have now expanded into the United States further
            diversifying our production base which already included Alberta, Saskatchewan,
            British Columbia and Manitoba. With operations widely distributed across
            more
            than 300 producing areas we minimize the risk that operational problems
            on a
            given property will materially impact our production or funds flow.
 
 Average
            production volumes for the years ended December 31, 2005 and 2004 are
            outlined
            below:
 
 **Daily
                      Production Volumes**
                  
                  **2005**
                  
                  **2004**
                  
                  **%
                      change**Natural
                      gas (Mcf/day)
                  
                  
                  **274,336**
                  
                  
                  271,091
                  
                  
                  1
                  %Crude
                      oil (bbls/day)
                  
                  
                  **29,315**
                  
                  
                  25,550
                  
                  
                  15
                  %Natural
                      gas liquids (bbls/day)
                  
                  
                  **4,689**
                  
                  
                  4,398
                  
                  
                  7
                  %Total
                      daily sales (BOE/day)
                  
                  
                  **79,727**
                  
                  
                  75,130
                  
                  
                  6
                  %
 
 We
            exited the year with production of approximately 85,000 BOE/day based
            on
            December’s monthly average production, slightly below our target of 86,000
            BOE/day. Our development capital program experienced delays due to pipeline
            curtailment at Bashaw and facility restrictions at Bantry North. As a
            result we
            expect approximately 3,800 BOE/day of production related to 2005 activity
            to
            come on stream early in 2006.
 
 We
            expect 2006 production to average 84,000 BOE/day, weighted 53% natural
            gas and
            47% liquids. In addition, we expect to exit 2006 with production of
            approximately 89,000 BOE/day which is 5% above our 2005 exit rate. This reflects
            our planned development capital program, however does not contemplate
            potential
            acquisitions or dispositions.
   Page
                2 of
                20
 
 **Pricing**
 
 Our
            earnings, funds flow and financial condition are dependent on the prices
            received for our natural gas and crude oil production. The following
            table
            compares our average selling prices for 2005 with those of 2004. It also
            compares the benchmark price indices for the same periods.
 
 **Average
                      Selling Price****(1)**
                  
                  **2005**
                  
                  **2004**
                  
                  **%
                      Change**Natural
                      gas (per Mcf)
                  
                  **$**
                  **8.41**
                  
                  $
                  6.56
                  
                  
                  28
                  %Crude
                      oil (per bbl)
                  
                  
                  **55.93**
                  
                  
                  43.80
                  
                  
                  28
                  %Natural
                      gas liquids (per bbl)
                  
                  
                  **47.33**
                  
                  
                  38.14
                  
                  
                  24
                  %Per
                      BOE
                  
                  **$**
                  **52.36**
                  
                  $
                  40.90
                  
                  
                  28
                  %
 (1)
            Net
            of oil and gas transportation costs, but before the effects of commodity
            derivative instruments
 
 **Average
                      Benchmark Pricing**
                  
                  **2005**
                  
                  **2004**
                  
                  **%
                      Change**AECO
                      natural gas - monthly index (CDN$/Mcf)
                  
                  **$**
                  **8.48**
                  
                  $
                  6.79
                  
                  
                  25
                  %AECO
                      natural gas - daily index (CDN$/Mcf)
                  
                  
                  **8.71**
                  
                  
                  6.53
                  
                  
                  33
                  %NYMEX
                      natural gas - monthly NX3 index (US$/Mcf)
                  
                  
                  **8.55**
                  
                  
                  6.09
                  
                  
                  40
                  %NYMEX
                      natural gas - monthly NX3 index: CDN$ equivalent
                      (CDN$/Mcf)
                  
                  
                  **10.30**
                  
                  
                  7.91
                  
                  
                  30
                  %WTI
                      crude oil (US$/bbl)
                  
                  
                  **56.56**
                  
                  
                  41.40
                  
                  
                  37
                  %WTI
                      crude oil: CDN$ equivalent (CDN$/bbl)
                  
                  
                  **68.14**
                  
                  
                  53.77
                  
                  
                  27
                  %CDN$/US$
                      exchange rate
                  
                  **$**
                  **0.83**
                  
                  $
                  0.77
                  
                  
                  8
                  %
  ***Natural
            Gas***
 
 During
            the first half of the year, the monthly AECO benchmark natural gas price
            averaged just over $7.00/Mcf. Late in the summer, prices, climbed to
            over
            $12.00/Mcf in response to hurricane activity and strength in crude oil
            prices.
            Despite disruption in the Gulf Coast area, production during the summer
            injection season was sufficient to fill North American storage. Cold
            weather was
            slow to arrive in the fall of 2005 and as a result demand for natural
            gas
            combined with adequate storage levels caused prices to retreat at year-end
            to
            $10.78/Mcf. Overall, the average price for the AECO monthly index price
            for 2005
            was $8.48/Mcf, up 25% compared to $6.79/Mcf in 2004.
 
 Within
            our sales portfolio of aggregator, downstream and spot gas, we sold
            approximately 40% of our natural gas based on AECO month index, 40% based
            on
            AECO day index and 20% at NYMEX monthly NX3 index prices. With the volatility
            around the weather and supply issues, there can be significant price
            differences
            between the month and day indices.
 
 During
            2005 we realized an average price of $8.41/Mcf (net of transportation)
            on our
            natural gas, an increase of 28% from $6.56/Mcf in 2004. In comparison,
            the AECO
            monthly index price for natural gas increased 25% and the AECO daily
            index
            increased 33%.
 
 As
            indicated by the current market for future prices (the “forward market”), AECO
            natural gas prices are expected to average $8.08/Mcf for 2006. Weather
            continues
            to be a significant factor in the near term volatility of natural gas
            prices.
 
  Page
                3 of
                20
  **Natural
            Gas Prices**
 
 
  ***Crude
            Oil***
 
 The
            crude oil benchmark West Texas Intermediate (“WTI”) price experienced volatility
            throughout 2005. Early in the year, fears concerning the supply demand
            balance
            and the refining infrastructure caused the prices to rise above US$50.00/bbl.
            Mid year unrest in Nigeria combined with the onset of the hurricane season
            pushed prices to peak at approximately US$70.00/bbl. Warmer weather and
            a
            reassessment of inventory levels post hurricane season, caused prices
            to settle
            into the US$60.00/bbl range near the end of the year. Overall, WTI prices
            denominated in U.S. dollars were 37% higher in 2005 compared to 2004.
 
 Our
            average crude oil selling price increased 28% from CDN$43.80 to CDN$55.93
            which
            was comparable to the increase in the Canadian dollar equivalent WTI
            at 27%.
            Furthermore, our additional light sweet production in the United States
            offset
            the effect of increasing Canadian heavy oil differentials on our existing
            production.
 
 Continued
            geopolitical instability throughout the world combined with expected
            steady
            growth in a number of key economies have the current forward crude oil
            price at
            approximately US$64.70/bbl converted to CDN$74.39 using an exchange rate
            of
            US$0.87 for 2006.
 
  Page
                4 of
                20
  **Crude
            Oil Prices**
  
  Throughout
            2005 the Canadian dollar strengthened 8% against the U.S. dollar, reducing
            prices received for our crude oil and a portion of our natural gas. Most
            of
            Canada’s crude oil and natural gas is exported to the U.S. and is priced with
            reference to U.S. dollar denominated benchmarks. The CDN$/US$ exchange
            rate
            entered 2005 at $0.83 and increased throughout the year to $0.86 in
            December.
 
 **Price
            Risk Management**
 
 Our
            commodity price risk management program incurred cash costs of $142.6
            million
            during 2005 compared to $96.2 million during 2004. The increase in cash
            costs
            was primarily due to record high commodity prices exceeding our calls.
            The
            majority of these derivative instruments were contracted in 2003 and
            2004, some
            of which expired on December 31, 2005 with the remaining expiring by
            the end of
            2006.
 
 **Risk
                      Management Cash Costs ($ millions, except per unit
                      amounts)**
                  
                  **2005**
                  
                  **2004**Crude
                      oil
                  
                  **$**
                  **91.0**
                  
                  **$**
                  **8.51/bbl**
                  
                  $
                  76.3
                  
                  $
                  8.16/bblNatural
                      Gas
                  
                  
                  **51.6**
                  
                  **$**
                  **0.52/Mcf**
                  
                  
                  19.9
                  
                  $
                  0.20/McfNet
                      cost
                  
                  **$**
                  **142.6**
                  
                  **$**
                  **4.90/BOE**
                  
                  $
                  96.2
                  
                  $
                  3.50/BOE
 
 We
            continue to review our risk management strategies in response to the
            increasing
            price environment, the economics of our acquisitions and development
            projects
            along with our overall financial position. Recently we have not been
            actively
            hedging commodity prices, however, this strategy may change in the future
            as
            management is constantly comparing the value of hedging with our overall
            requirement for price protection.
 
 The
            following table summarizes the effect that our financial contracts have
            had on
            income for the years ended December 31, 2005 and 2004.
 
 **2005**
                  
                  **2004****Commodity
                      Derivative Instruments**
                  
                  **($
                      millions)**
                  
                  **(Per
                      BOE)**
                  
                  **($
                      millions)**
                  
                  **(Per
                      BOE)**Financial
                      contracts not qualifying as hedges:Change
                      in fair value - other financial contracts
                  
                  **$**
                  **(35.8**
                  **)**
                  **$**
                  **(1.23**
                  **)**
                  $
                  21.3
                  
                  $
                  0.77Amortization
                      of
                      deferred financial assets
                  
                  
                  **3.1**
                  
                  
                  **0.11**
                  
                  
                  17.9
                  
                  
                  0.65Cash
                      costs of financial contracts
                  
                  
                  **115.4**
                  
                  
                  **3.96**
                  
                  
                  78.0
                  
                  
                  2.84**$**
                  **82.7**
                  
                  **$**
                  **2.84**
                  
                  $
                  117.2
                  
                  $
                  4.26Financial
                      contracts qualifying as hedges:Cash
                      costs of financial contracts
                  
                  
                  **27.2**
                  
                  
                  **0.94**
                  
                  
                  18.2
                  
                  
                  0.66Total
                      cost of financial contracts
                  
                  **$**
                  **109.9**
                  
                  **$**
                  **3.78**
                  
                  $
                  135.4
                  
                  $
                  4.92
 
  Page
                5 of
                20
  
 The
            unrealized gain on our financial contracts of $35.8 million for the year
            ended
            December 31, 2005 represents the change in the fair value of financial
            contracts
            not qualifying for hedge accounting and results in a non-cash increase
            to
            earnings.
 
 Effective
            December 31, 2005, we elected to stop designating our commodity financial
            contracts as hedges. As a result we recorded a deferred credit representing
            the
            fair value of these contracts on that day, with an offset recorded as
            a deferred
            financial asset that is amortized to income over the life of the underlying
            contracts. All of these contracts mature during 2006, therefore the deferred
            financial asset will be fully amortized by December 31, 2006. In the
            future,
            non-cash gains or losses on any new commodity contracts will be reflected
            in our
            income statement.
  Funds
            flow remains sensitive to changes as demonstrated by the following
            table:
 
 **Sensitivity
                      Table**
                  
                  **Estimated
                      Effect on 2006**
                    **Funds
                      Flow per Trust Unit**Change
                      of $0.15 per Mcf in the price of AECO natural gas
                  
                  $
                  0.09Change
                      of US$1.00 per barrel in the price of WTI crude oil
                  
                  $
                  0.09Change
                      of 1,000 BOE/day in production
                  
                  $
                  0.14Change
                      of $0.01 in the US$/CDN$ exchange rate
                  
                  $
                  0.11Change
                      of 1% in interest rate
                  
                  $
                  0.06
 
 These
            sensitivities reflect all commodity contracts as described in Note 12
            and are
            based on current forward markets for 2006. To the extent the market price
            of
            crude oil and natural gas change significantly from current levels, the
            above
            sensitivities will no longer be relevant.
 
 **REVENUES**
 
 Crude
            oil and natural gas revenues for the year ended December 31, 2005 were
            $1,523.7
            million ($1,550.6 million, net of $26.9 million transportation) compared
            to
            $1,124.6 million ($1,149.7 million, net of $25.1 million transportation)
            during
            2004. Higher crude oil and natural gas prices, combined with increased
            production from our development capital program and recent acquisitions
            resulted
            in a 35% increase of $399.1 million.
 
 **Analysis
                      of Sales Revenue****(1)****($
                      millions)**
                  
                  **Crude
                      oil**
                  
                  **NGLs**
                  
                  **Natural**
                    **Gas**
                  
                  **Total**2004
                      Sales Revenue
                  
                  $
                  409.5
                  
                  $
                  61.4
                  
                  $
                  653.7
                  
                  $
                  1,124.6Price
                      variance(1)
                  
                  
                  129.8
                  
                  
                  15.7
                  
                  
                  184.6
                  
                  
                  330.1Volume
                      variance
                  
                  
                  59.1
                  
                  
                  3.9
                  
                  
                  6.0
                  
                  
                  69.0**2005
                      Sales Revenue**
                  
                  **$**
                  **598.4**
                  
                  **$**
                  **81.0**
                  
                  **$**
                  **844.3**
                  
                  **$**
                  **1,523.7**
 (1)**** Net
            of oil and gas
            transportation costs, but before the effects of commodity derivative
            instruments.
 
 **ROYALTIES**
 
 Royalties
            are paid to various government entities and other land and mineral rights
            owners. Royalties in 2005 and 2004 were approximately 19% and 20% of
            oil and gas
            sales, net of transportation, respectively. Overall royalties were $297.0
            million compared to $231.0 million during 2004 which is consistent with
            our
            increase in revenue. We expect royalties to remain at approximately 19%
            for
            2006.
 
 **OPERATING
            EXPENSES**
 
 Operating
            expenses for the year ended December 31, 2005 were on target with our
            guidance
            at $7.45/BOE or $216.8 million. This represented a 4% increase from $7.14/BOE
            or
            $196.5 million in 2004. As expected, we experienced increased cost pressures
            due
            to industry activity levels and higher utility rates. We also incurred
            additional well servicing costs as we focused on production enhancement
            initiatives. We expect cost pressures to continue in 2006 and estimate
            annual
            operating costs will be approximately $7.95/BOE, representing an increase
            of 7%
            per BOE compared to 2005.
 
 **GENERAL
            AND ADMINISTRATIVE EXPENSES**
 
 G&A
            expenses were $1.39/BOE or $40.4 million for the year ended December
            31, 2005
            compared to $1.23/BOE or $33.9 million for 2004.
 
 Cash
            G&A costs of $1.28/BOE or $37.4 million were in line with our guidance
            of
            $1.27/BOE and higher than costs of $1.06/BOE or $29.2 million experienced
            during
            2004. The increase from the prior year can be attributed to recruiting
            and
            retaining skilled professional and technical staff along with increased
            infrastructure and information technology to support and enhance our
            expanded
            operations.
 
  Page
                6 of
                20
  Non-cash
            charges for our trust unit rights incentive plan for the year ended December
            31,
            2005 were $3.0 million or $0.11/BOE compared to $4.7 million or $0.17/BOE
            for
            2004. Based on recent discussions about the accounting for stock based
            compensation with the securities commissions we have determined it is
            appropriate to retroactively adopt the fair value method of accounting
            for our
            trust unit rights incentive plan to January 1, 2003. The impact of the
            adoption
            on our 2003 and 2004 reported earnings is not material and therefore
            prior
            period financial statements have not been restated. Our fourth quarter
            compensation expense in 2005 includes a non-cash recovery of $10.6 million.
            This
            recovery represents the difference between the unit based compensation
            expense
            related to 2005 originally calculated under the intrinsic method compared
            to the
            expense calculated using the fair value method. This change had no impact
            on
            funds flow from operations. See Notes 2 and 10.
 
 The
            following table summarizes the cash and non-cash expenses recorded in
            G&A:
 
 **General
                      and Administrative Costs**
                    **($
                      millions)**
                  
                  **2005**
                  
                  **2004**Cash
                  
                  **$**
                  **37.4**
                  
                  $
                  29.2Trust
                      unit rights incentive plan (non-cash)
                  
                  
                  **3.0**
                  
                  
                  4.7Total
                      G&A
                  
                  **$**
                  **40.4**
                  
                  $
                  33.9
 
 **(Per
                      BOE)**
                  
                  **2005**
                  
                  **2004**Cash
                  
                  **$**
                  **1.28**
                  
                  $
                  1.06Trust
                      unit rights incentive plan (non-cash)
                  
                  
                  **0.11**
                  
                  
                  0.17Total
                      G&A
                  
                  **$**
                  **1.39**
                  
                  $
                  1.23
 
 For
            2006 we expect total G&A costs to be approximately $1.70/BOE, including
            non-cash G&A costs of approximately $0.15/BOE. The forecasted increase
            reflects rising costs within a very competitive market place and our
            expanded
            operations in the United States.
 
 **INTEREST
            EXPENSE**
 
 Annual
            interest expense was $25.8 million compared to $20.7 million in 2004.
            This
            increase is due to higher debt levels and rising interest rates during
            2005. At
            December 31, 2005, 21% of our debt was based on fixed interest rates
            while 79%
            was floating. These instruments are more fully described in Note 12.
 
 **FOREIGN
            EXCHANGE**
 
 We
            experienced a foreign exchange loss of $1.7 million during the year ended
            December 31, 2005 compared to a gain of $5.0 million in 2004. A loss
            on foreign
            exchange contracts that were used to secure purchase price economics
            on the
            acquisition of Lyco was partially offset by gains on our US$54 million
            debentures. See Note 9 for further information.
 
 **CAPITAL
            EXPENDITURES**
 
 During
            the year ended December 31, 2005
            we spent $1,010.5 million on capital expenditures and acquisitions net of dispositions compared to
            $813.6
            million in 2004. As discussed in Notes 6 and 7, our most significant
            acquisitions during 2005 were TriLoch, Lyco, and Sleeping Giant. Our
            capital
            expenditures were financed through bank borrowing, the issuance of trust
            units
            and funds flow.
 
 **Capital
                      Expenditures ($ millions)**
                  
                  **2005**
                  
                  **2004**Development
                      expenditures
                  
                  **$**
                  **272.2**
                  
                  $
                  157.7Plant
                      and facilities
                  
                  
                  **96.5**
                  
                  
                  49.1Development
                      Capital
                  
                  
                  **368.7**
                  
                  
                  206.8Office
                  
                  
                  **4.3**
                  
                  
                  2.2Sub-total
                  
                  
                  **373.0**
                  
                  
                  209.0Acquisitions
                      of oil and gas properties
                  
                  
                  **119.9**
                  
                  
                  505.8Corporate
                      acquisitions
                  
                  
                  **584.1**
                  
                  
                  130.5Dispositions
                      of oil and gas properties
                  
                  
                  **(66.5**
                  **)**
                  
                  (31.7
                  )Total
                      Net Capital Expenditures
                  
                  **$**
                  **1,010.5**
                  
                  $
                  813.6Total
                      Capital Expenditures financed with funds flow
                  
                  **$**
                  **283.3**
                  
                  $
                  113.3Total
                      Capital Expenditures financed with debt and equity
                  
                  **$**
                  **727.2**
                  
                  $
                  700.3
 
 
  Page
                7 of
                20
  The
            following is a summary by major property of our largest development capital
            expenditures during 2005 and 2004.
 
 **($
                      millions)**
                  
                  **Development
                      Type**
                  
                  **2005**
                  
                  **2004**Bantry
                  
                  Conventional
                    oil and shallow gas
                  
                  **$**
                  **42.0**
                  
                  $
                  12.0Joslyn
                  
                  SAGD
                    oil
                  
                  
                  **33.2**
                  
                  
                  8.3Sleeping
                      Giant
                  
                  Conventional
                    oil
                  
                  
                  **29.1**
                  
                  
                  -Pembina
                      5-Way
                  
                  Oil
                    waterflood
                  
                  
                  **19.8**
                  
                  
                  8.8Hanna/Garden
                      Plains
                  
                  Shallow
                    gas
                  
                  
                  **18.5**
                  
                  
                  11.4Joarcam
                  
                  Oil
                    waterflood
                  
                  
                  **16.9**
                  
                  
                  9.0Joffre
                  
                  Coalbed
                    methane
                  
                  
                  **15.9**
                  
                  
                  4.7Bashaw
                  
                  Coalbed
                    methane
                  
                  
                  **14.9**
                  
                  
                  2.2Deep
                      Basin
                  
                  Natural
                    gas
                  
                  
                  **11.6**
                  
                  
                  13.9Medicine
                      Hat
                  
                  Oil
                    waterflood and shallow gas
                  
                  
                  **11.0**
                  
                  
                  12.4Other
                  
                  Oil
                    and gas
                  
                  
                  **155.8**
                  
                  
                  124.1Total
                  
                  
                  
                  
                  **$**
                  **368.7**
                  
                  $
                  206.8
 
 Total
            development capital expenditures in 2006 are expected to be approximately
            $485
            million. We plan to spend approximately $74 million on shallow natural
            gas
            development, $78 million on waterflood development, $89 million on Bakken
            oil
            development at our U.S. properties, $31 million on oil sands development
            and $49
            million with respect to coalbed methane. Other conventional development
            costs
            are expected to be approximately $164 million during 2006.
 
 In
            2005, we sold $66.5 million worth of non-core properties and we expect
            to
            continue the process of acquiring new properties and rationalizing marginal
            properties in 2006. At this time we have no significant divestment program
            planned for 2006.
 
 **ASSET
            RETIREMENT OBLIGATIONS**
 
 We
            have
            estimated total future asset retirement obligations based on our net
            ownership
            interest in wells and facilities, estimated costs to abandon and reclaim
            the
            wells and facilities and the estimated timing of the costs to be incurred
            in
            future periods. Our asset retirement obligation was $110.6 million at
            December
            31, 2005 compared to $106.0 million at December 31, 2004. The increase
            of $4.6
            million was due to our acquisition and development activity during the
            year
            combined with changes in estimated future liabilities, offset by our
            dispositions of non-core properties. The remainder of the change was
            due to
            retirement costs incurred offset by accretion expense for the year. See
            Note
            4.
 
 **DEPLETION,
            DEPRECIATION, AMORTIZATION AND ACCRETION (“DDA&A”)**
 
 DDA&A
            of property, plant and equipment (“PP&E”) is recognized using the
            unit-of-production method based on proved reserves. For the year ended
            December
            31, 2005, DDA&A increased to $13.27/BOE compared to $11.87/BOE during the
            year ended December 31, 2004. The increase is due to rising FD&A costs
            experienced over the last couple of years.
 
 No
            impairment existed at December 31, 2005 using year-end reserves and management’s
            estimates of future prices. Our future price estimates are more fully
            discussed
            in Note 5.
 
 **TAXES**
 
 *Future
            Income Taxes*
 
 Future
            income taxes arise from differences between the accounting and tax bases
            of the
            operating companies’ assets and liabilities. The future income tax liability
            associated with Canadian assets recorded on the balance sheet is recovered
            through earnings over time.
 
 For
            the
            year ended December 31, 2005, a future income tax expense of $15.3 million
            was
            recorded in income compared to a future income tax recovery of $76.8
            million in
            2004. The change from 2004 to 2005 was due to the combination of a future
            tax
            expense with respect to U.S. operations, amended tax pool balances, and
            a
            reduced payout ratio. Our expected future income tax rate incorporating
            these
            changes is approximately 34% which is the same as 2004.
 
  Page
                8 of
                20
 *Current
            Income Taxes*
 
 In
            our
            current structure, payments are made between the Canadian operating entities
            and
            the Fund, ultimately transferring both income and future income tax liability
            to
            our unitholders. Therefore, no cash income taxes have been paid by our
            Canadian
            operating entities.
 
 Our
            U.S. operations incurred taxes (income and withholding) in the amount
            of $2.8
            million. The amount of tax was lower than originally projected due to
            increased
            development capital spending combined with additional tax pools.
 
 In
            2006, we expect current and withholding taxes to be approximately 20%
            of U.S.
            funds flow from operations.
 
 *Capital
            Taxes*
  Capital
            taxes of $6.5 million decreased slightly in 2005 compared to 2004. The
            decrease
            is due to a reduction in the tax rate for Federal Large Corporations
            Tax.
            Capital taxes are expected to be **** $6.5
            million **** in
            2006.
 
 **SELECTED
            FINANCIAL RESULTS**
 
 **Per
                      BOE of production (6:1)**
                  
                  **2005**
                  
                  **2004**Production
                      per day
                  
                  
                  **79,727**
                  
                  
                  75,130Weighted
                      average sales price(1)
                  
                  **$**
                  **52.36**
                  
                  $
                  40.90Royalties
                  
                  
                  **(10.21**
                  **)**
                  
                  (8.40
                  )Financial
                      contracts
                  
                  
                  **(3.78**
                  **)**
                  
                  (4.92
                  )Add
                      back / (deduct): Non-cash financial contracts
                  
                  
                  **(1.12**
                  **)**
                  
                  1.42Operating
                      costs
                  
                  
                  **(7.45**
                  **)**
                  
                  (7.14
                  )General
                      and administrative
                  
                  
                  **(1.39**
                  **)**
                  
                  (1.23
                  )Add
                      back: Non-cash G&A expense (trust unit rights)
                  
                  
                  **0.11**
                  
                  
                  0.17Interest
                      expense, net of interest and other income
                  
                  
                  **(0.51**
                  **)**
                  
                  (0.68
                  )Foreign
                      exchange (loss) gain
                  
                  
                  **(0.06**
                  **)**
                  
                  0.18Deduct:
                      Non-cash foreign exchange loss
                  
                  
                  **(0.07**
                  **)**
                  
                  (0.17
                  )Capital
                      taxes
                  
                  
                  **(0.22**
                  **)**
                  
                  (0.24
                  )Current
                      income tax
                  
                  
                  **(0.09**
                  **)**
                  
                  -Restoration
                      and abandonment cash costs
                  
                  
                  **(0.27**
                  **)**
                  
                  (0.25
                  )Funds
                      flow from operations
                  
                  
                  **27.30**
                  
                  
                  19.64Restoration
                      and abandonment cash costs
                  
                  
                  **0.27**
                  
                  
                  0.25Non-cash
                      items:Depletion,
                      depreciation, amortization and accretion
                  
                  
                  **(13.27**
                  **)**
                  
                  (11.87
                  )Financial
                      contracts
                  
                  
                  **1.12**
                  
                  
                  (1.42
                  )G&A
                      expense (trust unit rights)
                  
                  
                  **(0.11**
                  **)**
                  
                  (0.17
                  )Foreign
                      exchange
                  
                  
                  **0.07**
                  
                  
                  0.17Future
                      income tax expense
                  
                  
                  **(0.53**
                  **)**
                  
                  2.79Total
                      net income per BOE
                  
                  **$**
                  **14.85**
                  
                  $
                  9.39
 (1) Net
            of oil and gas
            transportation costs, but before the effects of commodity derivative
            instruments
  **SELECTED
            CANADIAN AND U.S. FINANCIAL RESULTS**
 
 The
            following table provides a geographical analysis of key financial results
            for
            2005. Prior period information has not been presented as we only had
            operations
            in Canada prior to 2005.
 
 **($
                      millions, except per unit amounts)**
                  
                  **Canada**
                  
                  **U.S.**
                  
                  **Total****Daily
                      Production Volumes**Natural
                      gas (Mcf/day)
                  
                  
                  272,754
                  
                  
                  1,582
                  (1)
                  
                  274,336Crude
                      oil (bbls/day)
                  
                  
                  26,432
                  
                  
                  2,883
                  (1)
                  
                  29,315Natural
                      gas liquids (bbls/day)
                  
                  
                  4,689
                  
                  
                  -
                  
                  
                  4,689Total
                      Daily Sales (BOE/day)
                  
                  
                  76,580
                  
                  
                  3,147
                  (1)
                  
                  79,727**Pricing****(2)**Natural
                      gas (per Mcf)
                  
                  $
                  8.39
                  
                  $
                  12.58
                  
                  $
                  8.41Crude
                      oil (per bbl)
                  
                  
                  54.58
                  
                  
                  68.25
                  
                  
                  55.93Natural
                      gas liquids (per bbl)
                  
                  
                  47.33
                  
                  
                  -
                  
                  
                  47.33**Revenues**Oil and
                      gas sales(2)
                  
                  $
                  1,444.6
                  
                  $
                  79.1
                  
                  $
                  1,523.7Royalties
                  
                  
                  (281.9
                  )
                  
                  (15.1
                  )(3)
                  
                  (297.0
                  )Financial
                      Contracts - Qualified Hedges
                  
                  
                  (27.2
                  )
                  
                  -
                  
                  
                  (27.2
                  )Other
                      Financial Contracts
                  
                  
                  (83.1
                  )
                  
                  0.4
                  
                  
                  (82.7
                  )**Expenses**Operating
                  
                  $
                  214.7
                  
                  $
                  2.1
                  
                  $
                  216.8General
                      and Administrative
                  
                  
                  39.1
                  
                  
                  1.3
                  
                  
                  40.4Depletion,
                      depreciation, amortization and accretion
                  
                  
                  354.7
                  
                  
                  31.8
                  
                  
                  386.5Current
                      income taxes
                  
                  
                  -
                  
                  
                  2.8
                  
                  
                  2.8
 (1)  United
            States
            production per day (BOE/day) represents four months of Enerplus’ production
            commencing with the closing of the Lyco acquisition on August 30, 2005
            (9,415
            BOE/day expressed on an annualized basis).
 (2) 
            Net
            of oil
            and gas transportation costs, but before the effects of commodity derivative
            instruments.
 (3) 
            Royalties
            include U.S. state production tax.  Page
                  9 of
                  20
 **NET
            INCOME AND FUNDS FLOW FROM OPERATIONS**
 
 Increased
            production volumes and commodity prices resulted in increased oil and
            gas sales,
            net income and funds flow from operations during the last three years.
            The
            following table provides a summary of net income, funds flow from operations
            and
            other key measures.
 
 **($
                      millions, except per unit amounts)**
                  
                  **2005**
                  
                  **2004**
                  
                  **2003**Oil
                      and Gas Sales(1)
                  
                  **$**
                  **1,523.7**
                  
                  $
                  1,124.6
                  
                  $
                  935.8Net
                      Income
                  
                  
                  **432.0**
                  
                  
                  258.3
                  
                  
                  248.0Per
                      unit (Basic)
                  
                  
                  **3.96**
                  
                  
                  2.60
                  
                  
                  2.88Per
                      unit (Diluted)
                  
                  
                  **3.95**
                  
                  
                  2.60
                  
                  
                  2.87Funds
                      flow from operations
                  
                  
                  **794.4**
                  
                  
                  540.0
                  
                  
                  413.2Per
                      unit (Basic)
                  
                  
                  **7.28**
                  
                  
                  5.44
                  
                  
                  4.79Cash
                      available for distribution
                  
                  
                  **511.1**
                  
                  
                  426.7
                  
                  
                  379.1Per
                      unit (Basic)
                  
                  
                  **4.54**
                  
                  
                  4.20
                  
                  
                  4.32Payout
                      ratio
                  
                  
                  **64**
                  **%**
                  
                  79
                  %
                  
                  92
                  %Total
                      assets
                  
                  
                  **4,130.6**
                  
                  
                  3,180.7
                  
                  
                  2,661.8Long-term
                      debt, net of cash
                  
                  
                  **649.8**
                  
                  
                  585.0
                  
                  
                  257.7
 (1) Net
            of oil and gas
            transportation costs, but before the effects of commodity derivative
            instruments
 
 Funds
            flow from operations for the year ended December 31, 2005 was $794.4
            million or
            $7.28 per trust unit compared to $540.0 million or $5.44 per trust unit
            for
            2004. Net income for the year ended December 31, 2005 was $432.0 million
            or
            $3.96 per trust unit compared to $258.3 million or $2.60 per trust unit
            for
            2004. The increase in both funds flow from operations and net income was
            a
            result of higher commodity prices and production during 2005 compared
            to 2004.
            These increases were offset partially by cash losses on our commodity
            price risk
            management program and increased operating expenses.
 
 **QUARTERLY
            FINANCIAL INFORMATION**
 
 Overall
            oil and gas sales have increased due to higher commodity prices and production
            as well as through development capital activity and acquisitions throughout
            the
            last two years. Net income has been affected by rising oil and gas sales,
            increased risk management costs, the strengthening Canadian dollar, higher
            operating costs, changes in future tax recovery and changes to accounting
            policies adopted during 2005.
 
 **Oil
                      and****Quarterly
                      Financial Information**
                  
                  **Gas**
                  
                  
                  
                  **Net
                      Income Per Trust Unit****($
                      millions, except per trust unit amounts)**
                  
                  **Sales****(1)**
                  
                  **Net
                      Income**
                  
                  **Basic**
                  
                  **Diluted****2005**Fourth
                      Quarter
                  
                  $
                  503.2
                  
                  $
                  161.5
                  
                  $
                  1.38
                  
                  $
                  1.37Third
                      Quarter
                  
                  
                  398.7
                  
                  
                  100.3
                  
                  
                  0.91
                  
                  
                  0.91Second
                      Quarter
                  
                  
                  320.0
                  
                  
                  108.0
                  
                  
                  1.03
                  
                  
                  1.03First
                      Quarter
                  
                  
                  301.8
                  
                  
                  62.2
                  
                  
                  0.60
                  
                  
                  0.59Total
                  
                  **$**
                  **1,523.7**
                  
                  **$**
                  **432.0**
                  
                  **$**
                  **3.96**
                  
                  **$**
                  **3.95****2004**Fourth
                      Quarter
                  
                  $
                  317.5
                  
                  $
                  114.5
                  
                  $
                  1.10
                  
                  $
                  1.10Third
                      Quarter
                  
                  
                  302.2
                  
                  
                  50.6
                  
                  
                  0.49
                  
                  
                  0.49Second
                      Quarter
                  
                  
                  265.6
                  
                  
                  48.0
                  
                  
                  0.51
                  
                  
                  0.51First
                      Quarter
                  
                  
                  239.3
                  
                  
                  45.2
                  
                  
                  0.48
                  
                  
                  0.48Total
                  
                  **$**
                  **1,124.6**
                  
                  **$**
                  **258.3**
                  
                  **$**
                  **2.60**
                  
                  **$**
                  **2.60**
 (1) Net
            of oil and gas
            transportation costs, but before the effects of commodity derivative
            instruments
 
  Page
                10 of
                20
  **SUMMARY
            FOURTH QUARTER INFORMATION**
 
 In
            comparing the fourth quarter of 2005 with the same period in 2004:
 •
                  Net
                      income increased 41% to $161.5
                      million.
 •
                  Funds
                      flow from operations increased 95% to $291.2 million and 87%
                      on a BOE
                      basis as a result of increased production and rising commodity
                      prices.
 •
                  Average
                      daily production increased 4%due to our successful development capital program as well as
                      our recentacquisitions.
 •
                  The
                      average selling price per BOE increased 52% due to stronger
                      crude oil and
                      natural gas prices.
 •
                  Operating
                      expenses increased 5%to
                      $7.29/BOE mainly due to higher power and utility
                      rates.
 •
                  G&A
                      expenses decreased 81% to$0.30/BOE,
                      as thefourth
                      quarter of 2005 includes a $10.6 million non-cash recovery
                      related to the
                      adoption of the fair value method of accounting for our trust
                      unit rights
                      incentive plan (see Note 2).
 •
                  Development
                      capital spending increased 86% due to our expanded development
                      program in
                      2005.
 
 **Summary
                      Fourth Quarter Information**
                    **($
                      millions, except per unit amounts)**
                  
                  **Three
                      Months**
                    **Ended**
                    **December
                      31,**
                    **2005**
                  
                  **Three
                      Months**
                    **Ended**
                    **December
                      31,**
                    **2004**
                  
                  **%
                      Change****Daily
                      Production Volumes**Natural
                      gas (Mcf/day)
                  
                  
                  **269,443**
                  
                  
                  292,671
                  
                  
                  (8
                  %)Crude
                      oil (bbls/day)
                  
                  
                  **35,167**
                  
                  
                  28,752
                  
                  
                  22
                  %Natural
                      gas liquids (bbls/day)
                  
                  
                  **5,045**
                  
                  
                  4,157
                  
                  
                  21
                  %Total
                      daily sales (BOE/day)
                  
                  
                  **85,119**
                  
                  
                  81,688
                  
                  
                  4
                  %**Average
                      Selling Price****(1)**Natural
                      gas (per Mcf)
                  
                  **$**
                  **11.65**
                  
                  $
                  6.59
                  
                  
                  77
                  %Crude
                      oil (per bbl)
                  
                  
                  **58.41**
                  
                  
                  46.20
                  
                  
                  26
                  %Natural
                      gas liquids (per bbl)
                  
                  
                  **50.56**
                  
                  
                  45.46
                  
                  
                  11
                  %Per
                      BOE
                  
                  
                  **64.26**
                  
                  
                  42.25
                  
                  
                  52
                  %**Revenue****(1)**
                  
                  
                  **503.2**
                  
                  
                  317.5
                  
                  
                  58
                  %Per
                      BOE
                  
                  
                  **64.26**
                  
                  
                  42.25
                  
                  
                  52
                  %**Operating
                      Expenses**
                  
                  
                  **57.1**
                  
                  
                  52.1
                  
                  
                  10
                  %Per
                      BOE
                  
                  
                  **7.29**
                  
                  
                  6.93
                  
                  
                  5
                  %**General
                      and Administrative Expenses**
                  
                  
                  **2.3**
                  (2)
                  
                  11.9
                  
                  
                  (81
                  %)Per
                      BOE
                  
                  
                  **0.30**
                  (2)
                  
                  1.59
                  
                  
                  (81
                  %)**Net
                      Income**
                  
                  
                  **161.5**
                  
                  
                  114.5
                  
                  
                  41
                  %Per
                      BOE
                  
                  
                  **20.62**
                  
                  
                  15.24
                  
                  
                  35
                  %**Funds
                      Flow from Operations**
                  
                  
                  **291.2**
                  
                  
                  149.4
                  
                  
                  95
                  %Per
                      BOE
                  
                  
                  **37.19**
                  
                  
                  19.88
                  
                  
                  87
                  %**Development
                      Capital Spending**
                  
                  
                  **139.1**
                  
                  
                  74.9
                  
                  
                  86
                  %**Acquisitions**
                  
                  
                  **112.5**
                  
                  
                  14.5
                  
                  
                  676
                  %**Divestments**
                  
                  **$**
                  **0.4**
                  
                  $
                  12.7
                  
                  
                  (97
                  %)
 (1) Net
            of oil and gas
            transportation costs, but before the effects of commodity
            derivatives.
 (2) The
              entire non-cash
              recovery related to the adoption of the fair value method of accounting
              for our
              trust unit rights incentive plan has been recorded in the fourth quarter
              of
              2005.
  **CASH
            AVAILABLE FOR DISTRIBUTION**
 
 Our
            payout ratio for the year ended December 31, 2005 was 64%, compared to
            a payout
            ratio of 79% for the year ended December 31, 2004. During 2005, we funded
            over
            $1 billion in acquisitions and development capital spending through a
            combination of equity issuance, cash retained by the business, increased
            bank
            debt, and proceeds from divestments.
 
 We
            continually monitor our distribution payout with respect to forecasted
            funds
            flows, debt levels and spending plans. The level of cash retained typically
            varies between 10% and 40% of annual funds flow. This range has increased
            over
            the last two years. Recently we have been funding a greater portion of
            our
            development capital and acquisition programs with cash generated by the
            business, rather than through new equity issuance or increased debt.
            We are
            prepared to adjust the payout levels in an effort to balance the investor’s
            desire for distributions with the Fund’s requirement to maintain a prudent
            capital structure. The actual amount of funds flow withheld is dependant
            upon
            our current levels of production, the prevailing commodity price environment
            and
            is at the discretion of our Board of Directors.
 
  Page
                11 of
                20
  The
            following table reconciles Enerplus’ funds flow from operations with the cash
            available for distribution to
            unitholders.
 
 **Reconciliation
                      of Cash Available for Distribution**
                    **($
                      millions, except per unit amounts)**
                  
                  **2005**
                  
                  **2004**Cash
                      flow from operating activities
                  
                  **$**
                  **774.6**
                  
                  $
                  555.1Change
                      in non cash working capital
                  
                  
                  **19.8**
                  
                  
                  (15.1
                  )Funds
                      flow from operations
                  
                  
                  **794.4**
                  
                  
                  540.0Cash
                      withheld for acquisitions, capital expenditures and debt
                      repayment(1)
                  
                  
                  **(283.3**
                  **)**
                  
                  (113.3
                  )Cash
                      available for distribution(2)
                  
                  **$**
                  **511.1**
                  
                  $
                  426.7Cash
                      available for distribution per trust unit
                  
                  **$**
                  **4.54**
                  
                  $
                  4.20Payout
                      ratio
                  
                  
                  **64**
                  **%**
                  
                  79
                  %
 (1) Cash
            withheld for
            acquisitions, capital expenditures and debt repayment is a discretionary
            amount
            and represents the difference between cash flow from operations less
            distributions.
 (2) Cash
            available for
            distribution will differ from Cash Distributions to Unitholders on the
            Consolidated Statements of Cash Flows due to the timing of distribution
            announcements and the number of trust units outstanding on the record
            dates.
 
 **LIQUIDITY
            AND CAPITAL RESOURCES**
 
 Long-term
            debt, net of cash, at December
            31, 2005 was $649.8 million ,
            an
            increase of $64.8 million from December 31, 2004. Long-term debt at December
            31,
            2005 is comprise d
            of $328.6 m illion
            of bank indebtedness and $331.3 million of senior unsecured notes.
 
 Our
            working capital at December 31, 2005 decreased compared to December 31,
            2004.
            Current liabilities increased due to significant development capital
            spending
            late in the year, which more than offset increased current assets, including
            receivables for oil and gas sales.
 
 We
            continue to maintain a conservative balance sheet as demonstrated
            below:
 
 **Financial
                      Leverage and Coverage**
                  
                  **Year
                      ended**
                    **Dec.
                      31, 2005**
                  
                  **Year
                      ended**
                    **Dec.
                      31, 2004**Long-term
                      debt to trailing funds flow
                  
                  
                  **0.8**
                  **x**
                  
                  1.1
                  xFunds
                      flow to interest expense
                  
                  
                  **30.8**
                  **x**
                  
                  26.0
                  xLong-term
                      debt to long-term debt plus equity
                  
                  
                  **21**
                  **%**
                  
                  23
                  %
 Long-term
            debt is
            measured net of cash.
 Funds
            flow and
            interest expense are 12-months trailing (calculated based on the last
            12 months
            after adjusting for acquisitions).
 
 Enerplus
            has an $850 million bank credit facility (the “Bank Credit Facility”) through
            its wholly-owned subsidiary EnerMark Inc. The Bank Credit Facility is
            an
            unsecured, covenant-based, three-year committed credit agreement with
            nine North
            American banks. We have the ability to extend the facility each year
            or repay
            the entire balance at the end of the three-year term. At December 31,
            2005, we
            had $521.4 million of available borrowing capacity under this facility,
            which
            currently extends to November, 2008. This bank debt carries floating
            interest
            rates that are expected to range between 60.0 and 115.0 basis points
            over
            Bankers Acceptance rates, depending on Enerplus’ ratio of senior debt to
            earnings before interest, taxes and non-cash items.
 
 Payments
            with respect to the bank facilities, senior unsecured notes and other
            third
            party debt have priority over claims of and future distributions to the
            unitholders. Unitholders have no direct liability should funds flow be
            insufficient to repay this indebtedness. The agreements governing these
            bank
            facilities and senior unsecured notes stipulate that if we default or
            fail to
            comply with certain covenants, the ability of the operating companies
            to make
            payments to the Fund and consequently the Fund’s ability to make distributions
            to the unitholders may be restricted.
 
 Principal
            payments on Enerplus’ senior unsecured notes are required commencing in 2010 and
            2011 and are more fully discussed in Note 8.
 
 We
            anticipate that we will continue to have adequate liquidity to fund planned
            development capital spending during 2006 through a combination of funds
            flow
            from operations and debt. Most of our $485 million capital budget for
            2006 is
            discretionary and can be revised downward in the event of a commodity
            price
            downturn or similar economic event.
 
  Page
                12 of
                20
  **COMMITMENTS**
 
 We
            have
            contracted to transport natural gas with various pipelines totaling 35.3
            MMcf/day until 2008; of this amount 5 MMcf/day extends until 2015. We
            also have
            a contract to transport a minimum of 2,480 bbls/day of crude oil until
            2010.
            These transportation contracts will cost approximately $6.0 million in
            2006.
 
 Our
            office lease commitments expire between November 2009 and January 2011.
            Annual
            costs of these lease commitments, which include rent and operating fees,
            amount
            to approximately $5.7 million. The Fund’s commitments, contingencies, and
            guarantees are more fully described in Note 13.
 
 We
            must
            continue to pay crown and surface royalties, lease rentals, mineral taxes
            along
            with abandonment and reclamation costs with respect to our ongoing ownership
            of
            hydrocarbon production rights. The amounts paid with respect to these
            burdens
            will depend on the future ownership, production, prices and legislative
            environment at the time.
 
 Approximately
            28% of our current gas production is dedicated to certain aggregator
            sales
            arrangements. Under these arrangements, we receive a price based on the
            average
            netback price of the pool, net of transportation costs incurred by the
            aggregator for the life of the reserves.
 
 Enerplus
            has the following minimum annual commitments including long-term
            debt:
 
 **Total****Committed****Minimum
                      Annual Commitment Each Year**
                  
                  **after****($
                      millions)**
                  
                  **Total**
                  
                  **2006**
                  
                  **2007**
                  
                  **2008**
                  
                  **2009**
                  
                  **2010**
                  
                  **2010**Bank
                      credit facility
                  
                  **$**
                  **328.6**
                  **(1)**
                  $
                  -
                  
                  $
                  -
                  
                  $
                  328.6
                  
                  $
                  -
                  
                  $
                  -
                  
                  $
                  -Senior
                      unsecured notes
                  
                  
                  **331.3**
                  **(1)**
                  
                  -
                  
                  
                  -
                  
                  
                  -
                  
                  
                  -
                  
                  
                  53.7
                  
                  
                  277.6Pipeline
                      commitments
                  
                  
                  **33.9**
                  
                  
                  6.0
                  
                  
                  6.0
                  
                  
                  5.6
                  
                  
                  3.0
                  
                  
                  2.4
                  
                  
                  10.9Office
                      lease
                  
                  
                  **23.4**
                  
                  
                  5.7
                  
                  
                  5.7
                  
                  
                  5.7
                  
                  
                  5.6
                  
                  
                  0.6
                  
                  
                  0.1Total
                      commitments
                  
                  **$**
                  **717.2**
                  
                  **$**
                  **11.7**
                  
                  **$**
                  **11.7**
                  
                  **$**
                  **339.9**
                  
                  **$**
                  **8.6**
                  
                  **$**
                  **56.7**
                  
                  **$**
                  **288.6**
 **(1)**Interest
            payments
            have not been included since future debt levels and rates are not known
            at this
            time.
 
 **TRUST
            UNIT INFORMATION**
 
 We
            had
            117,539,000 trust units outstanding at December 31, 2005 compared to
            104,124,000
            trust units at December 31, 2004. The weighted average basic number of
            trust
            units outstanding during 2005 was 109,083,000 (2004 - 99,273,000). At
            February
            10, 2006 we had 117,689,000 trust units outstanding.
 
 On
            July
            1, 2005 the Fund acquired all of the issued and outstanding shares of
            TriLoch in
            exchange for 1,632,516 trust units. The trust units exchanged were valued
            at
            $42.32 per unit, which was the weighted average trading price of the
            Fund’s
            trust units on the Toronto Stock Exchange during the five day trading
            period
            surrounding the announcement of the TriLoch transaction, for a recorded
            value of
            approximately $69.1 million after issuance costs.
 
 On
            August 9, 2005 the Fund announced the closing of its subscription receipt
            financing related to the Lyco acquisition. A total of 10,637,500 subscription
            receipts were issued at a price of CDN$46.25 per receipt for gross proceeds
            of
            approximately $492.0 million. With the closing of the Lyco acquisition
            on August
            30, 2005, subscription receipt holders received one trust unit for each
            subscription receipt held along with the August 2005 cash distribution
            of $0.37
            per trust unit. The distribution paid to subscription receipt holders
            has been
            included in cash distributions to unitholders. During 2004, units with
            a value
            of $287.2 million, net of transaction costs, were issued to acquire corporate
            and property interests.
 
 In
            addition 1,144,000 trust units (2004 - 950,000) were issued pursuant
            to the
            Trust Unit Monthly Distribution Reinvestment and Unit Purchase Plan (“DRIP”) and
            the trust unit rights plans, net of redemptions. This resulted in $40.4
            million
            (2004 - $28.1 million) of additional equity to the Fund.
 
 **INCOME
            TAXES**
 
 The
            following is a general discussion of the Canadian and U.S. tax consequences
            of
            holding Enerplus trust units as capital property. The summary is not
            exhaustive
            in nature and is not intended to provide legal or tax advice. Investors
            or
            potential unitholders should consult their own legal or tax advisors
            as to their
            particular tax consequences.
 
  Page
                13 of
                20
  **Canadian
            Unitholders**
 
 The
            Fund qualifies as a mutual fund trust under the Income Tax Act (Canada)
            and
            accordingly, trust units of the Fund are qualified investments for RRSPs,
            RRIFs,
            RESPs, and DPSPs. Each year, the Fund is required to file an income tax
            return
            and any taxable income in the Fund is allocated to the unitholders.
 
 In
            computing income, unitholders are required to include their pro-rata
            share of
            any taxable income earned by the Fund in that year. An investor’s adjusted cost
            base (“ACB”) in a trust unit equals the purchase price of the trust unit less
            any non-taxable cash distributions received from the date of acquisition.
            To the
            extent a unitholder’s ACB is reduced below zero, such amount will be deemed to
            be a capital gain to the unitholder and the unitholder’s ACB will be brought to
            $nil.
 
 We
            paid
            $4.47 per trust unit in cash distributions to unitholders on record during
            2005.
            For Canadian tax purposes, approximately 10% of these distributions,
            or $0.43
            per trust unit was a tax deferred return of capital, approximately 90%
            or $4.02
            per trust unit was taxable to unitholders as other income, and less than
            1% or
            $0.02 per trust unit was taxable dividend income.
 
 For
            2006, we estimate that 95% of cash distributions may be taxable and 5%
            may be a
            tax deferred return of capital. Actual taxable amounts may vary depending
            on
            actual distributions which are dependent upon production, commodity prices
            and
            funds flow experienced throughout the year.
 
 **U.S.
            Unitholders**
 
 U.S.
            unitholders who received cash distributions were subject to at least
            a 15%
            Canadian withholding tax. The withholding tax is applied to both the
            taxable
            portion of the distribution as computed under Canadian tax law, and the
            non-taxable portion of the distribution. U.S. taxpayers may be eligible
            for a
            foreign tax credit with respect to Canadian withholding taxes paid.
 
 The
            taxable portion of the cash distribution for U.S. tax purposes is determined
            by
            Enerplus in relation to its current and accumulated earnings and profits
            using
            U.S. income tax principles. The taxable portion determined is considered
            to be a
            dividend for U.S. tax purposes. For most U.S. taxpayers, this should
            be a
“Qualified Dividend” eligible for the reduced tax rate. We believe Enerplus
            should not be classified as a Passive Foreign Investment Company for
            U.S. income
            tax purposes for 2005 and 2004.
 
 The
            non-taxable portion of the cash distribution is a return of the cost
            (or other
            basis). The cost (or other basis) is reduced by this amount for computing
            any
            gain or loss arising from disposition. However, if the full amount of
            the cost
            (or other basis) has been recovered, any further non-taxable distributions
            should be reported as gains.
 
 We
            paid
            US$3.63 per trust unit to U.S. residents during the 2005 calendar year,
            of which
            7% or US$0.25 per trust unit was a tax deferred return of capital and
            93% or
            US$3.38 per unit was a taxable qualified dividend.
 
 For
            2006, we estimate that 95% of cash distributions will be taxable to most
            U.S.
            investors and 5% will be a tax deferred return of capital. Actual taxable
            amounts may vary depending on actual distributions which are dependant
            upon
            production, commodity prices and funds flow experienced throughout the
            year.
 
 **CRITICAL
            ACCOUNTING POLICIES**
 
 The
            financial statements have been prepared in accordance with GAAP. A summary
            of
            significant accounting policies is presented in Note 1. A reconciliation
            of
            differences between Canadian and United States GAAP is presented in Note
            15.
            Most accounting policies are mandated under GAAP. However, in accounting
            for oil
            and gas activities, we have a choice between two acceptable accounting
            policies:
            the full cost and the successful effort methods of accounting.
 
 The
            Fund follows the full cost method of accounting for oil and natural gas
            activities. Using the full cost method of accounting, all costs of acquiring,
            exploring and developing oil and natural gas properties are capitalized,
            including unsuccessful drilling costs and administrative costs associated
            with
            acquisitions and development. Under the successful efforts method of
            accounting,
            all exploration costs, except costs associated with drilling successful
            exploration wells, are expensed in the period in which they are incurred.
            The
            difference between these two methodologies is not expected to be significant
            to
            the Fund’s net income or net income per unit as the majority of the Fund’s
            drilling activity is in low risk development drilling that has traditionally
            achieved high success rates.
 
 Under
            the full cost method of accounting, an impairment test is applied to
            the overall
            carrying value of property, plant and equipment, on a country by country
            cost
            centre basis with the reserves valued using estimated future commodity
  Page
                14 of
                20
  prices
            at period end. Under the successful efforts method of accounting, the
            costs are
            aggregated on a property-by-property basis. The carrying value of each
            property
            is subject to an impairment test. Each policy may generate a different
            carrying
            value of property, plant and equipment and a different net income depending
            on
            the circumstances at period end.
 
 **CRITICAL
            ACCOUNTING ESTIMATES**
 
 The
            preparation of financial statements in accordance with GAAP requires
            management
            to make certain judgments and estimates. Due to the timing of when activities
            occur compared to the reporting of those activities, management must
            estimate
            and accrue operating results and capital spending. Changes in these judgments
            and estimates could have a material impact on our financial results and
            financial condition.
 
 The
            process of estimating reserves is critical to several accounting estimates.
            It
            requires significant judgments based on available geological, geophysical,
            engineering and economic data. These estimates may change substantially
            as data
            from ongoing development and production activities becomes available,
            and as
            economic conditions impacting oil and gas prices, operating costs and
            royalty
            burdens change. Reserve estimates impact net income through depletion,
            the
            determination of asset retirement obligations and the application of
            an
            impairment test. Revisions or changes in the reserve estimates can have
            either a
            positive or a negative impact on net income and the asset retirement
            obligation.
 
 Management
            calculates the asset retirement obligation based on estimated costs to
            abandon
            and reclaim its net ownership interest in all wells and facilities and
            the
            estimated timing of the costs to be incurred in future periods. The fair
            value
            estimate is capitalized to PP&E as part of the cost of the related asset and
            amortized over its useful life.
 
 Management
            makes various assumptions in determining the fair values of any acquired
            company’s assets and liabilities in a business combination. The most significant
            assumptions and judgments made relate to the estimation of the fair value
            of the
            oil and gas properties. To determine the fair value of these properties,
            we
            estimated (a) oil and gas reserves in accordance with our reserve standards,
            and
            (b) future prices of oil and gas.
 
 Management’s
            estimates of oil and natural gas prices are also critical as these prices
            are
            used to determine the carrying amount of PP&E, amounts recorded for
            depletion, impairment in the cost centre, and the change in fair value
            of
            financial contracts that do not qualify for hedge accounting.
 
 Management
            calculates the fair value of rights granted under our trust unit rights
            incentive plan using a binomial lattice option pricing model. This process
            involves the use of significant estimates and assumptions, which may
            change over
            time. The values calculated under the option pricing model may not reflect
            the
            actual value realized by trust unit rights holders.
 
 **RECENT
            CANADIAN** **ACCOUNTING
            AND RELATED** **PRONOUNCEMENTS**
  **Non-Monetary
            Transactions**
 
 In
            June
            2005, the Accounting Standards Board (“AcSB”) issued Section 3831, *Non-Monetary
            Transactions* ,
            which
            replaces Section 3830 and requires all non-monetary transactions to be
            measured
            at fair value unless:
  •
                  The
                      transaction lacks commercial
                      substance.
 •
                  The
                      transaction is an exchange of a product or property held for
                      sale in the
                      ordinary course of business for a product or property to be
                      sold in the
                      same line of business to facilitate sales to customers other
                      than the
                      parties to the exchange.
 •
                  Neither
                      the fair value of the assets or services received nor the fair
                      value of
                      the assets or services given up is reliably
                      measurable.
 •
                  The
                      transaction is a non-monetary, non-reciprocal transfer to owners
                      that
                      represent a spin-off or other form of restructuring or
                      liquidation.
 
 The
            new
            requirements apply to non-monetary transactions initiated in periods
            beginning
            on or after January 1, 2006. Earlier adoption is permitted beginning
            on or after
            July 1, 2005. We do not expect the adoption of this standard will have
            any
            material impact on our results of operations or financial position.
 
  Page
                15 of
                20
  **Financial
            Instruments - Recognition and Measurement, Hedges, and Comprehensive
            Income**
 
 The
            AcSB has issued three sections on financial instruments; Section 1530, *Comprehensive
            Income* ,
            Section 3855, *Financial
            Instruments - Recognition and Measurement* ,
            and
            Section 3865, *Hedges* .
            These
            three sections will apply to interim and annual financial statements
            relating to
            fiscal years beginning on or after October 1, 2006. They will require
            the
            following:
 •
                  all
                      trading financial instruments will be recognized on the balance
                      sheet and
                      will be fair valued through the income statement;
 •
                  all
                      remaining financial assets will be recorded at cost and amortized
                      through
                      the financial statements;
 •
                  a
                      new statement for comprehensive income that will include certain
                      gains and
                      losses on translation of assets and liabilities;
                      and
 •
                  an
                      update to Accounting Guideline 13 to incorporate the fair value
                      changes
                      currently recorded in the income statement to be recorded through
                      the
                      comprehensive income statement.
 
 We
            have
            not assessed the future impact on the financial statements of the Fund
            at this
            time.
  **RISK
            FACTORS AND RISK MANAGEMENT**
 
 Enerplus
            investors are participating in the net funds flow from a portfolio of
            crude oil
            and natural gas producing properties. As such, the funds flow paid to
            investors
            and the value of Enerplus units are subject to numerous risk factors.
            These risk
            factors, many of which are associated with the oil and gas industry,
            include,
            but are not limited to, the following influences:
  **Commodity
            Price Risk**
 
 Enerplus’
            operating results and financial condition are dependent on the prices
            we receive
            for our crude oil and natural gas production. These prices may fluctuate
            widely
            in response to a variety of factors including global and domestic economic
            conditions, weather conditions, the supply and price of imported oil
            and
            liquefied natural gas, the production and storage levels of North American
            natural gas, political stability, transportation facilities, the price
            and
            availability of alternative fuels and government regulations.
 
 *We
            may use financial derivative instruments and other hedging mechanisms
            to help
            limit the adverse effects of natural gas and oil price volatility. However,
            we
            do not hedge all of our production and expect there will always be a
            portion
            that remains unhedged. Furthermore, we may use financial instruments
            that offer
            only limited protection within selected price ranges. To the extent price
            exposure is hedged, we may forego the benefits that would otherwise be
            experienced if commodity prices increase.*
  **Operational
            Risk and Cost Control**
  The
            value of Enerplus trust units is based on the underlying value of the
            oil and
            gas reserves. Geological and operational risks can affect the quantity
            and
            quality of reserves and the cost of ultimately recovering those reserves.
            Lower
            oil and natural gas prices may increase the risk of write-downs of our
            oil and
            gas property investments. Regulatory changes to reserve reporting practices
            can
            also result in reserve write-downs. As activity levels in the industry
            increase,
            upward pressure is placed on administrative and operating costs. Higher
            costs
            will decrease the amount of funds flow received by the Fund and therefore,
            reduce distributions to unitholders.
 
 *We
            strive to acquire low risk, mature properties with a high proportion
            of proved
            reserves, positive operating metrics, long reserve lives and predictable
            production. Similarly, we generally participate in lower-risk development
            projects, while farming out or monetizing higher risk exploratory
            prospects.*
 
 *Each
            year, independent engineers evaluate a significant portion of our proved
            and
            probable reserves.*
 *Sproule
            Associates Limited (“Sproule”) evaluated 89% of the total proved plus probable
            value (discounted at 10%) of the Fund’s Canadian conventional year-end reserves,
            in keeping with NI 51-101 and has reviewed the remainder of the reserves
            internally evaluated by Enerplus. GLJ Petroleum Consultants Ltd. (“GLJ”)
            evaluated the Joslyn SAGD bitumen reserves as they have previously performed
            such evaluations for the operator of the Joslyn project. DeGolyer and
            MacNaughton (“D&M”) of Dallas, Texas, evaluated the reserves attributed to
            our assets in the United States. Both GLJ and D&M evaluated 100% of the
            reserves in their respective areas. Both GLJ and D&M utilized Sproule’s
            forecast price and cost assumptions as of December 31, 2005 in their
            evaluations
            to maintain consistency. The Reserves Committee of the Board of Directors
            has
            reviewed and approved the reserve reports of the independent
            evaluators.*
 
  Page
                16 of
                20
  *We
            strive to control costs through incentive-based compensation plans that
            reward
            employees for such things as cost control and value-added initiatives.
            We
            attempt to minimize costs by exploiting our purchasing strength with
            suppliers.
            We use detailed budgeting and accounting practices to monitor costs.
            Multi-functional teams regularly perform integrated field reviews designed
            to
            reduce costs and increase revenues from our properties.*
 
 *Despite
            these efforts, it can be difficult to control costs in the oil and gas
            industry,
            especially in periods of high commodity prices when the demand for goods
            and
            services is strong. Oil and gas production involves a significant amount
            of
            fixed costs that are difficult to reduce without decreasing production.
            In
            addition, approximately 35% of Enerplus’ production is operated by third
            parties. We have limited ability to influence costs on partner-operated
            properties.*
  **Production
            Replacement Risk**
 
 Oil
            and
            natural gas reserves naturally deplete as they are produced over time.
            Our
            ability to replace production depends on our success in acquiring new
            reserves
            and developing existing reserves. Acquisitions of oil and gas assets
            depend on
            Enerplus’ assessment of value at the time of acquisition. Incorrect assessments
            of value can adversely affect distributions to unitholders and the value
            of the
            trust units.
 
 *Acquisitions
            are subject to investment guidelines, due diligence and review. Major
            acquisitions are approved by the Board of Directors and where appropriate,
            independent reservoir engineer evaluations are obtained.*
  **Non-Resident
            Ownership and Mutual Fund Trust Status**
 
 Since
            our listing on the New York Stock Exchange in November of 2000, we have
            seen
            increased trading volumes and levels of ownership by non-residents of
            Canada.
            Based on information received from our transfer agent and financial
            intermediaries in February 2006, an estimated 73% of our outstanding
            trust units
            are held by non-residents. However, this estimate may not be accurate
            as it is
            based on certain assumptions and data from the security industry that
            does not
            have a well-defined methodology to determine the residency of beneficial
            holders
            of securities.
 
 Enerplus
            currently meets the requirements of a Mutual Fund Trust as defined in
            the Income
            Tax Act (Canada). Our trust indenture does not have a specific limit
            on the
            percentage of trust units that may be owned by non-residents.
 
 *At
            this time, management does not anticipate any legislative changes that
            would
            affect our status as a mutual fund trust, however, we have implemented
            provisions in our trust indenture to allow the Board of Directors to
            adopt
            non-resident ownership constraints if required in order to ensure Enerplus
            maintains its mutual fund trust status.*
 
 **Regulatory
            Risk**
 
 Government
            royalties, income tax laws, environmental laws and regulatory requirements
            can
            have a significant financial and operational impact on Enerplus. Our
            U.S.
            operations expose us to possible regulatory changes by the U.S. government.
            As
            an oil and gas producer, we are subject to a broad range of regulatory
            requirements. Similarly, as a mutual fund trust, Enerplus has a unique
            structure
            that is vulnerable to changes in legislation or income tax law.
 
 *In
            2004, the Canadian government announced that it was studying the taxation
            of
            trusts. Included in this review were issues such as imposing restrictions
            on
            non-resident ownership and imposing taxation at the trust level. After
            a
            consultative process, the government announced in November 2005 that
            it would
            not make changes to the tax regulations. In the January 2006 election,
            the
            Canadian Liberal government was replaced by a Conservative government.
            Both
            parties are on record as stating that they do not intend to change the
            tax
            treatment of trusts. Nevertheless, there is always a risk that the Canadian
            government may reconsider its position and propose changes to the tax
            regime
            that could negatively impact the Fund.*
  **Access
            to Capital Markets**
 
 Since
            Enerplus distributes the majority of net funds flow to unitholders, we
            must
            finance a large portion of our acquisition and development activity with
            equity
            and debt capital markets. As such, we are dependent on continued access
            to the
            capital markets to fund our activities directed towards maintaining and
            increasing value for our
            unitholders.
 
 *Enerplus
            has listings on the Toronto and New York stock exchanges and maintains
            an active
            investor* *relations
            program.*
 
 *We
            maintain a prudent capital structure by retaining a portion of funds
            flow for
            capital spending and utilizing the equity markets when deemed
            appropriate.*
 
  Page
                17 of
                20
  *Continued
            access to capital is dependant on our ability to maintain our track record
            of
            performance and to demonstrate the advantages of the acquisition or development
            program that we are financing at the time.*
 
 **Environmental,
            Health and Safety Risk (“EHS”)**
 
 Environmental
            and safety risks influence the workforce, operating costs and the establishment
            of
 regulatory
            standards.
 
 *We
            have established an EHS Management System designed to:*
 
 •
                  *provide
                      staff with the training and resources needed to complete work
                      safely and
                      effectively;*
 •
                  *incorporate
                      hazard assessment and risk management as an integral part of
                      everyday
                      business;*
 •
                  *monitor
                      performance to ensure that Enerplus operations comply with
                      legal
                      obligations and the standards we set for ourselves; and*
 •
                  *identify
                      and manage environmental liabilities associated with our existing
                      asset
                      base and potential *acquisitions.**
 
 *We
            have a site inspections program and a corrosion risk management program
            designed
            to ensure compliance with environmental laws and regulations. Enerplus
            carries
            insurance to cover a portion of our property losses, liability and business
            interruption. EHS risks are reviewed regularly by a committee of the
            Board of
            Directors.*
  **Interest
            Rate Exposure**
 
 The
            Fund has exposure to movements in interest rates. Changing interest rates
            can
            affect borrowing costs and the trust unit price of yield-based investments
            such
            as Enerplus.
 
 *We
            monitor the interest rate forward market and have fixed the interest
            rate on
            approximately 21% of our debt through our senior unsecured notes and
            interest
            rate swaps.*
 
 **Foreign
            Currency Exposure**
 
 Enerplus
            has exposure to fluctuations in foreign currency as a result of the issuance
            of
            senior unsecured notes denominated in U.S. dollars.
 
 Enerplus
            also has indirect exposure to fluctuations in foreign currency as crude
            oil
            sales and a portion of natural gas sales are based on U.S. dollar indices.
            Our
            oil and gas revenues are negatively impacted as the Canadian dollar strengthens
            relative to the U.S. dollar. Enerplus now has operations in the United
            States
            with direct exposure to fluctuations in the U.S. dollar on translation
            to our
            Canadian dollar denominated financial statements.
 
 *We
            have hedged
            our foreign currency exposure on US$175 million of senior unsecured notes
            using
            financial swaps that convert the U.S. denominated debt to Canadian dollar
            debt
            with Canadian dollar interest obligations. We have not hedged our foreign
            exchange exposure with respect to the US$54 million of senior unsecured
            notes
            issued in October 2003 which have U.S. dollar interest payment
            obligations.*
 
 *We
            have not entered into any foreign currency derivatives with respect to
            oil and
            gas sales or our U.S. operations.*
  **Counterparty
            Risk**
 
 We
            assume customer credit risk associated with oil and gas sales, financial
            hedging
            transactions and joint
 venture
            participants.
 
 *We
            have established credit policies and controls designed to mitigate the
            risk of
            default or non-payment with respect to oil and gas sales, financial hedging
            transactions and joint venture participants. Enerplus maintains a diversified
            sales customer base and we review our single-entity exposure on a regular
            basis.*
 
 **Unitholder
            Liability**
 
 In
            the
            past, there has been some concern that trust unitholders might be held
            personally liable for the indebtedness of the Fund.
 
 *Enerplus
            is registered in Alberta, which passed legislation in June 2004 to provide
            statutory protection for unitholders similar to the protection afforded
            shareholders in a corporation. Two other provinces (Ontario and Quebec)
            also
            have*
  Page
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  *statutory
            protection for unitholders. Our bank credit agreement and our debenture
            agreements do not allow the creditors to extend recourse to unitholders
            beyond
            the unitholders’ equity investment in the Fund.*
 
 **SUMMARY
            2006 OUTLOOK**
 
 Enerplus
            offers investors the benefits of owning a large, diversified portfolio
            of
            producing oil and natural gas properties within Canada and the United
            States. As
            such, our business prospects are closely linked to the opportunities
            and
            challenges associated with oil and natural gas production. In particular,
            we are
            strongly influenced by the price of crude oil and natural gas, both of
            which
            have been volatile in recent years. Our comments with respect to our
            2006
            outlook should be taken within the context of the current commodity price
            environment.
 
 The
            following summarizes Enerplus’ 2006 guidance as provided throughout this
            MD&A. We do not attempt to forecast commodity prices, and as a result, we
            do
            not forecast future cash distributions to unitholders. Readers are encouraged
            to
            apply their own price expectations to the following factors to arrive
            at an
            expected cash distribution.
 
 **Summary
                      of 2006 Expectations**
                  
                  **Target**
                  
                  **Comments**Average
                      Annual Production
                  
                  84,000
                      BOE/day
                  
                  Assumes
                      no new acquisitions or dispositionsExit
                      rate December 2006 production
                  
                  89,000
                      BOE/day
                  
                  Assumes
                      $485 million development capital spending2006
                      production mix
                  
                  53%
                      gas, 43% oil, 4% NGLAverage
                      royalty rate
                  
                  19%
                  
                  Percentage
                      of gross unhedged salesOperating
                      Expenses
                  
                  $7.95/BOEG&A
                      costs
                  
                  $1.70/BOE
                  
                  Includes
                      non-cash charges of $0.15BOE (unit rights plan)Capital
                      taxes
                  
                  $6.5
                      million
                  
                  Based
                      on current capital structureU.S.
                      income and withholding tax - cash costs
                  
                  20%
                  
                  Applied
                      to net funds flow generated by U.S. operationsAverage
                      interest cost
                  
                  4.5%
                  
                  Based
                      on current fixed rates and forward marketPayout
                      ratio
                  
                  60%
                      -90%Development
                      capital spending
                  
                  $485
                      million
                  
                  Based
                      on current plans and price
                      environment
 
 We
            have
            made progress towards sustainability by reducing our reliance on acquisitions
            to
            supplement production declines and focusing our efforts on development
            capital
            opportunities within our existing assets. This progress is supported
            by our
            ability to maintain reserves and production per debt-adjusted trust unit.
            We
            expect to be able to increase our production in 2006 through internally
            generated development efforts without relying on new acquisitions. We
            anticipate
            that our average 2006 annual production will be 5% higher than 2005,
            and our
            2006 exit rate will be 5% higher than our 2005 exit rate. Furthermore,
            we expect
            to increase our reserves during 2006 by replacing production with new
            reserve
            additions from our development program.
 
 Our
            2006 development capital spending is expected to be $485 million, which
            is 32%
            higher than our 2005 spending, reflecting a robust opportunity set and
            continued
            cost escalation in the sector. We plan to continue to withhold a portion
            of our
            funds flow to finance this capital program and we expect the payout ratio
            to
            trend towards the lower end of our 60-90% guidance range. We believe
            it is
            important to maintain a conservative balance sheet as a defense for commodity
            price volatility.
  We
            will
            continue to focus on low-risk development opportunities and review our
            risk
            management strategies in response to increasing prices and the economics
            of our
            acquisitions and development projects. Recently, we have not been actively
            hedging commodity prices, however, this strategy may change in the future
            as
            management is constantly comparing the value of hedging with our overall
            requirement for price protection.
  For
            2006, we estimate that 95% of cash distributions will be taxable and
            5% will be
            a tax-deferred return of capital for both our Canadian and U.S. unitholders.
 
 We
            are
            encouraged by the results from our recent acquisitions and our efforts
            to
            integrate these operations with our existing staff and systems. The
            establishment of an office in Denver will enhance our growing presence
            in the
            U.S. oil and gas market.
 
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  **DISCLOSURE
            CONTROLS AND PROCEDURES**
 
 The
            Chief Executive Officer and Chief Financial Officer have evaluated the
            effectiveness of the Fund’s disclosure controls and procedures as of December
            31, 2005 and concluded that the Fund’s disclosure controls and procedures were
            effective.
 
 **ADDITIONAL
            INFORMATION**
 
 Additional
            information relating to Enerplus Resources Fund, including the Fund’s Annual
            Information Form, is available under the Fund’s profile on the SEDAR website at
            www.sedar.com and at www.enerplus.com.
 
 **FORWARD-LOOKING
            STATEMENTS**
 
 This
            discussion and analysis contains certain forward-looking statements and
            forward-looking information which are based on Enerplus' current internal
            expectations, estimates, projections, assumptions and beliefs. The use
            of any of
            the words "anticipate", "continue", "estimate", "expect", "may", "will",
            "project", "plan", "should", "believe" and similar expressions are intended
            to
            identify forward-looking statements and forward-looking information.
            These
            statements are not guarantees of future performance and involve known
            and
            unknown risks, uncertainties and other factors that may cause actual
            results or
            events to differ materially from those anticipated in such forward-looking
            statements or information. Enerplus believes the expectations reflected
            in those
            forward-looking statements and information are reasonable but no assurance
            can
            be given that these expectations will prove to be correct, and such
            forward-looking statements and information included in this discussion
            and
            analysis should not be unduly relied upon. Such forward-looking statements
            and
            information speak only as of the date of this discussion and analysis
            and
            Enerplus does not undertake any obligation to publicly update or revise
            any
            forward-looking statements or information, except as required by applicable
            laws.
  
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