**Exhibit
      99.2**





**MANAGEMENT’S
      DISCUSSION AND ANALYSIS (“MD&A”)**





The
      following
      discussion and analysis of financial results is dated February 21, 2007 and
      is
      to be read in conjunction with the audited consolidated financial statements
      as
      at and for the years ended December 31, 2006 and 2005. All amounts are stated
      in
      Canadian dollars unless otherwise specified. All references to GAAP refer to
      Canadian generally accepted accounting principles. 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. Oil and natural gas reserves and production are presented
      on a
      company interest basis which is not a term defined or recognized under NI
      51-101. Therefore, our company interest reserves may not be comparable to
      similar measures presented by other issuers. 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. Certain prior year amounts have been
      restated to reflect current year presentation.





The
      following
      MD&A contains forward-looking information and statements. We refer you to
      the end of the MD&A for our disclaimer on forward-looking
      statements.





**NON-GAAP
      MEASURES**





Historically
      we
      used the non-GAAP measure funds flow from operations (or “funds flow”) to
      analyze operating performance, leverage and liquidity. We are now utilizing
      the
      GAAP measure cash flow from operating activities (“cash flow”) instead of funds
      flow. The difference is that cash flow from operating activities includes
      changes in non-cash working capital and appears on our Consolidated Statements
      of Cash Flows.





We
      also historically used the non-GAAP measure cash available for distribution.
      We
      are now using cash distributions to unitholders (“cash distributions”) which
      also appears on our Consolidated Statements of Cash Flows. Cash available for
      distribution was based on the twelve month production period January through
      December wherein the related distributions were paid with a two month lag or
      March through February respectively. Cash distributions include amounts paid
      or
      declared during the calendar year which relate to the twelve month production
      period December through November wherein the related distributions are paid
      February through January.





Our
      payout ratio
      was previously calculated as cash available for distribution divided by funds
      flow; however, as a result of the above-mentioned changes, our payout ratio
      is
      now calculated as cash distributions divided by cash flow from operating
      activities. This reflects the proportion of cash flow paid out to investors
      and
      not reinvested in the business.


The
      term payout
      ratio does not have a standardized meaning as prescribed by GAAP and therefore
      may not be comparable with the calculation of a similar measure by other
      entities.





Refer
      to the
      Liquidity and Capital Resources section of the MD&A for further information
      on cash flow, cash distributions and payout ratio. ****




**UPDATE
      ON
      CANADIAN GOVERNMENT ANNOUNCEMENT ON INTENTION TO TAX
      TRUSTS**





On
      October 31, 2006, the Canadian federal government (the “Government”) announced
      plans to introduce a tax on publicly traded income trusts. For existing income
      trusts, such as Enerplus, the new tax measures would be effective for 2011,
      provided we comply with the “normal growth” parameters regarding equity growth
      until that time. A “Notice of Ways and Means Motion” was passed in Parliament
      shortly after the Government announcement. This notice was a one-page summary
      of
      the Government’s proposal and it did not identify any specific amendments to the
      Income Tax Act.





On
      December 15, 2006 the Government announced safe harbour guidance regarding
      “normal growth” for equity capital. The safe harbour amount will be measured by
      reference to the individual trust’s market capitalization as of the end of
      trading on October 31, 2006 (which was approximately $7.5 billion for Enerplus).
      For the period from November 1, 2006 to December 31, 2007 a trust’s safe harbour
      amount will be 40 percent of the October 31, 2006 market capitalization
      benchmark and for each of the years 2008 through and including 2010 will be
      20
      percent of the benchmark, cumulatively allowing growth of up to 100 percent
      until 2011. In addition, we understand that trusts will be able to issue equity
      to retire debt existing on October 31, 2006 without eroding their safe harbour
      limits.





On
      December 21, 2006, the government released more detailed draft legislation
      with
      respect to the proposed amendments to the Income Tax Act and requested comments
      from stakeholders. In late January 2007, the House of Commons Standing Committee
      on Finance held special hearings on the proposed tax and the draft legislation.
      At this









rule




time
      we are unable
      to determine the impact, if any, these hearings may have on the proposed
      legislation or the timing of when the proposed legislation could be passed
      in
      Parliament.





Should
      the tax
      legislation become substantially enacted, future income taxes may be adjusted
      to
      include temporary differences between the accounting and tax bases of the
      trust’s assets and liabilities. In addition, reserves reported under NI 51-101
      may be adjusted to include an estimate of the tax effect on our estimated future
      revenues from our reserves. We will assess alternative organizational structures
      during the four-year transition period. We are confident we have the team,
      the
      assets, and the opportunities to prosper regardless of our organizational
      structure.





**2006
      OVERVIEW**





During
      2006 we
      executed our largest capital program to date, spending $491.2 million. The
      increased capital spending resulted in average production of 85,779 BOE/day,
      exceeding our guidance of 85,500 BOE/day. Both general and administrative costs
      (“G&A”) and operating costs were higher than guidance due to cost escalation
      associated with the high level of industry activity.





Compared
      to 2005,
      cash flow increased 11% to $863.7 million, net income increased 26% to $544.8
      million, and cash distributions increased 23% to $614.3 million. Increased
      production, crude oil prices and lower risk management costs were partially
      offset by reduced natural gas prices and increased costs, resulting in the
      year-over-year increases in cash flow and net income. Monthly cash distributions
      remained constant at $0.42 per trust unit throughout 2006.





Our
      trust unit
      price declined in the last quarter of 2006 due to the Government’s proposed tax
      on income trusts and, to a lesser extent, in response to weakening crude oil
      and
      natural gas prices. Our Canadian unitholders realized a negative 0.3% total
      return while our U.S. unitholders realized a 0.1% total return in 2006
      (representing the change in unit price plus distributions paid during the year).





**Highlights**





•
            Cash
                flow
                increased 11% to $863.7 million from $774.6 million in the previous
                year.


•
            Cash
                distributions increased in 2006 by 23% to $614.3 million or 11% per
                unit
                to $5.05 per unit (based on weighted average trust units outstanding)
                compared to 2005.


•
            Actual
                monthly distributions per trust unit remained constant throughout
                2006 at
                $0.42 resulting in annual cash distributions of $5.04 for each
                unitholder.


•
            Average
                selling price per BOE decreased 4% to $50.23 due to weaker natural
                gas
                prices.


•
            Our
                largest
                development capital program to date of $491.2 million was essentially
                in
                line with our target of $485.0 million.


•
            The
                additional development capital spending during 2006 resulted in production
                that averaged 85,779 BOE/day exceeding our annual target of 85,500
                BOE/day.





•
            Net
                income
                increased 26% to $544.8 million. On a trust unit basis this resulted
                in an
                increase of 13% to $4.48 per unit reflecting the increase in trust
                units
                outstanding.


•
            Our
                payout
                ratio increased to 71% from 64% in 2005 as we distributed more of
                our cash
                flow from operating activities to our
                unitholders.


•
            Operating
                costs were $8.02/BOE in 2006, 8% higher than $7.45/BOE in 2005.


•
            G&A
                costs
                were $1.91/BOE, higher than our guidance of $1.85/BOE and 37% higher
                than
                $1.39/BOE in 2005.


•
            Our
                realized
                commodity price risk management cash costs were $34.3 million ($1.10/BOE)
                during 2006, a 76% reduction compared to $142.6 million ($4.90/BOE)
                during
                2005.





•
            Drilling
                efforts resulted in a success rate of over 99% with participation
                in 361
                net wells.


•
            Our
                finding,
                development and acquisition costs (“FD&A”) for the year were
                $23.19/BOE on a proved plus probable basis and $28.82/BOE on a proved
                basis.


•
            Proved
                plus
                probable reserves decreased 1% to 443.3 MMBOE and proved reserves
                decreased 4% to 299.8 MMBOE.


•
            Reserve
                additions from development capital spending and acquisitions replaced
                82%
                of 2006 production on a proved plus probable basis and 57% of production
                on a proved basis.


•
            Our
                Reserve
                Life Index (“RLI”) continued to be one of the longest in the sector at
                14.0 years on a proved plus probable basis and 10.1 years on a proved
                basis, including both conventional and non-conventional
                reserves.


•
            Our
                recycle
                ratio (operating income divided by FD&A) was 1.6x on a three-year
                basis and 1.4x for 2006 using proved plus probable
                reserves.


•
            We
                continue
                to maintain a conservative balance sheet as evidenced by a net debt
                to
                trailing 12 month cash flow ratio of 0.8x.





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  **RESULTS
        OF
        OPERATIONS**


**Production**





Daily
      production
      during 2006 averaged 85,779 BOE/day, slightly above our guidance of 85,500
      BOE/day and 8% higher than 79,727 BOE/day in 2005. The increase was primarily
      due to our U.S. acquisitions in the second half of 2005 which added an
      incremental 8,121 BOE/day of production in 2006 along with our development
      capital program which added an additional 5,633 BOE/day of production in 2006.
      These increases were offset in part by natural reservoir declines experienced
      throughout the year.





Average
      production
      during the year was weighted 53% to natural gas and 47% to liquids on a BOE
      basis. Average production volumes for the years ended December 31, 2006 and
      2005
      are outlined below:





**Daily
                Production Volumes**
            
            
            **2006**
            
            
            2005
            
            
            %
                changeNatural
                gas
                (Mcf/day)
            
            
            **270,972**
            
            
            274,336
            
            
            (1
            %)Crude
                oil
                (bbls/day)
            
            
            **36,134**
            
            
            29,315
            
            
            23
            %Natural
                gas
                liquids (bbls/day)
            
            
            **4,483**
            
            
            4,689
            
            
            (4
            %)Total
                daily
                sales (BOE/day)
            
            
            **85,779**
            
            
            79,727
            
            
            8
            %





We
      exited the year with production of approximately 87,500 BOE/day based on
      December’s production, in line with our target of 88,000 BOE/day.





We
      expect 2007 annual production volumes to remain essentially flat year-over-year,
      averaging 85,000 BOE/day, weighted 54% to natural gas and 46% to liquids. As
      a
      result of the timing of our planned development capital program, we expect
      to
      exit 2007 with production of approximately 86,000 BOE/day. This does not
      contemplate any potential acquisitions or dispositions.





**Pricing**





The
      prices received
      for our natural gas and crude oil production directly impact our earnings,
      cash
      flow and financial condition. **** The
      following table
      compares our average selling prices for 2006 with those of 2005. It also
      compares the benchmark price indices for the same periods.





**Average
                Selling Price****(1)**
            
            
            **2006**
            
            
            2005
            
            
            %
                ChangeNatural
                gas
                (per Mcf)
            
            **$**
            **6.81**
            
            $
            8.41
            
            
            (19
            %)Crude
                oil
                (per bbl)
            
            
            **61.80**
            
            
            55.93
            
            
            10
            %Natural
                gas
                liquids (per bbl)
            
            
            **50.90**
            
            
            47.33
            
            
            8
            %Per
                BOE
            
            **$**
            **50.23**
            
            $
            52.36
            
            
            (4
            %)


(1) Net of oil and gas
      transportation costs, but before the effects of commodity derivative
      instruments





**Average
                Benchmark Pricing**
            
            
            **2006**
            
            
            2005
            
            
            %
                ChangeAECO
                natural
                gas - monthly index (CDN$/Mcf)
            
            **$**
            **6.99**
            
            $
            8.48
            
            
            (18
            %)AECO
                natural
                gas - daily index (CDN$/Mcf)
            
            
            **6.53**
            
            
            8.71
            
            
            (25
            %)NYMEX
                natural
                gas - monthly NX3 index (US$/Mcf)
            
            
            **7.26**
            
            
            8.55
            
            
            (15
            %)NYMEX
                natural
                gas - monthly NX3 index: CDN$ equivalent (CDN$/Mcf)
            
            
            **8.25**
            
            
            10.30
            
            
            (20
            %)WTI
                crude oil
                (US$/bbl)
            
            
            **66.22**
            
            
            56.56
            
            
            17
            %WTI
                crude
                oil: CDN$ equivalent (CDN$/bbl)
            
            
            **75.25**
            
            
            68.14
            
            
            10
            %CDN$/US$
                exchange rate
            
            **$**
            **0.88**
            
            $
            0.83
            
            
            6
            %





*Natural
      Gas*





Natural
      gas prices
      were in a downward trend during 2006, influenced initially by demand loss,
      the
      residual high storage inventories after a warm winter, and strong drilling.
      In
      July 2006, prices received some support due to above normal temperatures in
      key
      consuming regions of the United States, and forecasts for a strong hurricane
      season. Year-over-year the natural gas storage surplus continued to build and
      those hurricanes that did develop were moderate. This ultimately drove the
      AECO
      monthly index price to a low for the year of $4.45/Mcf in October, with the
      daily spot price dropping to $3.25/Mcf in the same month. Spot and forward
      prices recovered significantly as winter approached, with spot prices rising
      briefly above $8.00/Mcf before the warmer than normal November and December,
      caused by an El Nino weather pattern, pushed the daily spot price back to
      $6.07/Mcf on December 31, 2006.





Our
      natural gas
      portfolio is comprised of aggregator, AECO, and downstream direct sales. In
      2006
      we sold 42% of our natural gas on the daily AECO market and 42% on the monthly
      AECO market, as well as 16% against the day and month NYMEX indices. During
      2006
      we realized an average price for our natural gas sales of $6.81/Mcf (net of
      transportation costs), a decrease of 19% from the $8.41/Mcf realized in 2005.
      This reduction is comparable to the price decreases realized in each of: the
      AECO daily index which decreased by 25% year over year; the AECO




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rule




monthly
      index which
      decreased by 18%; and the NYMEX monthly index (converted to CDN$/Mcf) which
      decreased by 20%.





*Natural
      Gas
      Prices*










*Crude
      Oil*





World
      crude prices
      continued to be influenced by a tight supply-demand balance through the first
      half of 2006, continuing the upward trend in prices experienced during 2005.
      WTI
      spot prices peaked in July during the Israel-Hezbollah conflict at US$77.03/bbl.
      With strong inventories, forecasts for warmer than normal conditions for the
      winter, and a strengthening supply picture, prices fell thereafter through
      the
      second half of 2006. The WTI spot price hit a low of US$55.81/bbl in November,
      representing a 28% reduction from the July high.





Our
      crude oil
      portfolio in 2006 was approximately 70% light/medium and 30% heavy. The average
      price received for our crude oil (net of transportation costs) was $61.80/bbl
      during 2006, a 10% increase over 2005. Similarly, the West Texas Intermediate
      (“WTI”) crude oil benchmark price, after adjusting for the change in the US$
      exchange rate, also increased by 10% year over year. Although we added more
      light sweet crude oil to our portfolio in 2006 compared to 2005, this benefit
      was offset by widening heavy crude oil differentials during the
      year.





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          4 of
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rule




Crude
      Oil Prices










The
      Canadian dollar
      strengthened 6% against the U.S. dollar during 2006 compared to 2005 based
      on
      the annual average exchange rate. As most of our crude oil and a portion of
      our
      natural gas are priced in reference to U.S. dollar denominated benchmarks,
      this
      movement in the exchange rate reduced the Canadian dollar prices that we would
      have otherwise realized.





**Price
      Risk
      Management**





While
      the overall
      energy outlook remains generally bullish long term, there remains uncertainty
      as
      to the direction prices might move in 2007. Both natural gas and crude oil
      prices have the potential to fall further in 2007 given current levels of
      inventory, aggressive drilling in the U.S. for gas and across the globe for
      crude oil and some uncertainty with respect to the world economy.




We
      have developed a
      price risk management framework to respond to the volatile price environment
      in
      a prudent manner. Consideration is given to our overall financial position
      together with the economics of our acquisitions and capital development program.
      Consideration is also given to the upfront costs of our risk management program
      as we seek to limit our exposure to price downturns while maintaining
      participation should commodity prices increase.





Given
      our price
      risk management framework we have entered into additional commodity contracts
      during the fourth quarter and subsequent to year end. These contracts are
      designed to protect a portion of our natural gas revenue for the period January
      2007 through March 2008 and to protect a portion of our crude oil revenue for
      the period January 2007 through December 2007. We have also hedged electricity
      volumes for the period January 2007 through September 2008 to protect against
      rising electricity costs in the Alberta power market. See Note 10 for a detailed
      list of our current price risk management positions.





The
      following is a
      summary of the physical and financial contracts in place at February 13, 2007
      as
      a percentage of our forecasted net production volumes:


Page
          5 of
          25










**Natural
                Gas****(CDN$/Mcf)**
            
            
            **Crude
                Oil**
              **(US$/bbl)****January
                1, 2007 - March 31, 2007**
            
            
            **April
                1, 2007- October 31, 2007**
            
            
            **November
                1, 2007 - March 31, 2008**
            
            
            
            **January
                1, 2007 - December 31, 2007**Floor
                Protection Price
            
            $
            7.53
            
            $
            7.32
            
            $
            8.13
            
            
            $
            68.93%
                (net of
                royalties)
            
            
            21
            %
            
            32
            %
            
            3
            %
            
            
            34
            %Upside
                Capped
                Price
            
            $
            10.64
            
            $
            9.07
            
            $
            10.31
            
            
            $
            -%
                (net of
                royalties)
            
            
            14
            %
            
            28
            %
            
            3
            %
            
            
            -
            %Fixed
                Price
            
            $
            -
            
            $
            7.58
            
            $
            8.70
            
            
            $
            66.24%
                (net of
                royalties)
            
            
            -
            %
            
            12
            %
            
            2
            %
            
            
            8
            %


Based
      on weighted
      average price, before premiums, and average production of 85,000
      BOE/day.


Assumes
      production
      mix of 54% gas, 42% oil and 4% NGL.





*Accounting
      for
      Price Risk Management*





During
      2006, our
      commodity price risk management positions incurred cash costs of $27.2 million
      on crude oil contracts and $7.1 million on natural gas contracts compared to
      cash costs of $91.0 million and $51.6 million respectively during 2005. The
      decrease in crude oil cash costs is due to the expiration of contracts on June
      30, 2006 that had ceiling prices between US$35.35/bbl and US$45.80/bbl on 4,500
      bbls/day. The decrease in natural gas cash costs is the result of lower natural
      gas prices experienced during 2006 and the expiration of old contracts.





The
      unrealized gain
      on our financial contracts of $81.0 million for the year ended December 31,
      2006
      represents the change in the fair value of financial contracts since December
      31, 2005. As the forward markets for natural gas and crude oil fluctuate, and
      new contracts are executed and existing contracts are realized, changes in
      fair
      value are reflected as a non-cash charge or increase to earnings. At December
      31, 2006 the fair value of our financial contracts net of premiums is $23.6
      million and is recorded on the balance sheet as a deferred financial asset.
      See
      Note 2 for details.





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.
      These costs of $49.9 million are fully amortized at December 31, 2006. See
      Note
      2 for details.





The
      following table
      summarizes the effects of our financial contracts on income for the years ended
      December 31, 2006 and 2005.





**Risk
                Management (Gains)/Losses**
              **($
                millions, except per unit amounts)**
            
            **2006**
            2005Cash
                (gains)/losses:Crude
                oil
            
            **$**
            **27.2**
            
            $
            2.06/bbl
            
            $
            91.0
            
            $
            8.51/bblNatural
                Gas
            
            
            **7.1**
            
            $
            0.07/Mcf
            
            
            51.6
            
            $
            0.52/McfTotal
                Cash
                losses
            
            **$**
            **34.3**
            
            $
            1.10/BOE
            
            $
            142.6
            
            $
            4.90/BOENon-cash
                (gains)/losses:Change
                in fair
                value - financial contracts
            
            **$**
            **(81.0**
            **)**
            $
            (2.59)/BOE
            
            $
            (35.8
            )
            $
            (1.23)/BOEAmortization
                of
                deferred financial assets
            
            
            **49.9**
            
            $
            1.59/BOE
            
            
            3.1
            
            $
            0.11/BOETotal
                Non-cash gains
            
            **$**
            **(31.1**
            **)**
            $
            (0.99)/BOE
            
            $
            (32.7
            )
            $
            (1.12)/BOETotal
                losses
            
            **$**
            **3.2**
            
            $
            0.11/BOE
            
            $
            109.9
            
            $
            3.78/BOE





*Cash
      Flow
      Sensitivity*





The
      sensitivities
      below reflect all commodity contracts as described in Note 10 and are based
      on
      current forward markets for 2007 at February 13, 2007. To the extent the market
      price of crude oil and natural gas change significantly from current levels,
      the
      sensitivities will no longer be relevant as the effect of our commodity
      contracts will change.





**Sensitivity
                Table**
            
            
            **Estimated
                Effect on 2007**
              **Cash
                Flow per Trust Unit****(1)**Change
                of
                $0.15 per Mcf in the price of AECO natural gas
            
            $
            0.08Change
                of
                US$1.00 per barrel in the price of WTI crude oil
            
            $
            0.05Change
                of
                1,000 BOE/day in production
            
            $
            0.13Change
                of
                $0.01 in the US$/CDN$ exchange rate
            
            $
            0.12Change
                of 1%
                in interest rate
            
            $
            0.06




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(1) Assumes constant
      working capital and 123,151,000 units outstanding.


The
      impact of a
      change in one factor may be compounded or offset by changes in other factors.
      This table does not consider the impact of any inter-relationship among the
      factors.





**Revenues**





Crude
      oil and
      natural gas revenues for the year ended December 31, 2006 were $1,572.7 million
      ($1,595.3 million, net of $22.6 million of transportation costs) compared to
      $1,523.7 million ($1,550.6 million, net of $26.9 million of transportation
      costs) during 2005. Increased crude oil volumes from our 2005 acquisitions
      along
      with higher realized oil prices were offset primarily by the decrease in natural
      gas prices. The result was an increase of 3% or $49.0 million in revenue net
      of
      transportation costs.





**Analysis
                of Sales Revenue****(1)****($
                millions)**
            
            
            **Crude
                oil**
            
            
            **NGLs**
            
            
            **Natural
                Gas**
            
            
            **Total**2005
                Sales
                Revenue
            
            $
            598.4
            
            $
            81.0
            
            $
            844.3
            
            $
            1,523.7Price
                variance(1)
            
            
            77.4
            
            
            5.9
            
            
            (159.6
            )
            
            (76.3
            )Volume
                variance
            
            
            139.2
            
            
            (3.6
            )
            
            (10.3
            )
            
            125.3**2006
                Sales Revenue**
            
            **$**
            **815.0**
            
            **$**
            **83.3**
            
            **$**
            **674.4**
            
            **$**
            **1,572.7**


(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 2006 and 2005 were approximately 19% of oil and gas sales, net
      of
      transportation costs. Overall, royalties decreased marginally in 2006 to $293.2
      million compared to $297.0 million during 2005 primarily as a result of the
      decrease in natural gas prices experienced over the period.





For
      2007 we expect
      royalties to remain at approximately 19% of oil and gas sales, net of
      transportation costs, however this may change as a result of the Alberta
      government’s stated intention to review the oil and gas royalty regime. Alberta
      royalties represented approximately 70% of our total royalties incurred during
      2006 (2005 - 87%).





**Operating
      Expenses**





Operating
      expenses
      for the year ended December 31, 2006 were $8.02/BOE or $251.2 million. This
      represents a 3% increase over our guidance of $7.80/BOE and an 8% increase
      from
      $7.45/BOE in 2005. Cost pressures associated with the high level of industry
      activity have increased operating costs during 2006. The areas that were most
      impacted by these activity levels included scheduled facility maintenance and
      well servicing.





During
      the fourth
      quarter we experienced increases as a result of the timing of certain well
      servicing and facility maintenance programs. As well, we experienced higher
      natural gas processing fees at certain facilities.





We
      anticipate continued increases in operating costs in 2007 due to general cost
      escalation. As a result, we expect costs to average $8.45/BOE, representing
      an
      increase of 5% per BOE compared to 2006. Although we are seeing evidence that
      the cost inflation in our industry has moderated, it is too soon to tell if
      this
      trend is sustainable.




**General
      and
      Administrative Expenses**





G&A
      expenses
      were $1.91/BOE or $59.9 million for the year ended December 31, 2006. On a
      BOE
      basis G&A was 3% higher than our guidance of $1.85/BOE and 37% higher than
      $1.39/BOE 2005.





The
      highly
      competitive marketplace resulted in challenges to recruit and retain skilled
      professionals. For the year ended December 31, 2006 compensation and long-term
      incentives increased approximately $14.0 million or $0.45/BOE compared to the
      same period in 2005. Other increases included additional technology and
      information systems, our commitment to education funding for SAIT Polytechnic,
      along with ongoing regulatory compliance requirements.





For
      the year ended
      December 31, 2006, our G&A expenses included non-cash charges for our trust
      unit rights incentive plan of $6.3 million or $0.20/BOE compared to $3.0 million
      or $0.11/BOE for 2005. These amounts are determined using a binomial lattice
      option-pricing model. The increased volatility of our trust unit
      price combined with the increased number of rights outstanding, as a result of an
      increase in the number of employees, have impacted the non-cash cost of the
      plan.





The
      following table
      summarizes the cash and non-cash expenses recorded in G&A:


Page
          7 of
          25








**General
                and Administrative Costs**
              **($
                millions)**
            
            
            **2006**
            
            
            2005Cash
            
            **$**
            **53.6**
            
            $
            37.4Trust
                unit
                rights incentive plan (non-cash)
            
            
            **6.3**
            
            
            3.0Total
                G&A
            
            **$**
            **59.9**
            
            $
            40.4





**(Per
                BOE)**
            
            
            **2006**
            
            
            2005Cash
            
            **$**
            **1.71**
            
            $
            1.28Trust
                unit
                rights incentive plan (non-cash)
            
            
            **0.20**
            
            
            0.11Total
                G&A
            
            **$**
            **1.91**
            
            $
            1.39





In
      2007 we expect total G&A costs to be approximately $2.40/BOE, including
      non-cash G&A costs of approximately $0.30/BOE. The forecasted increase
      reflects cost pressures to recruit and retain a technically skilled labour
      force. It also includes increased costs associated with ongoing regulatory
      compliance and costs associated with planning and responding to the proposed
      tax
      on trusts.





**Interest
      Expense**





Annual
      interest
      expense increased by $6.4 million to $32.2 million compared to $25.8 million
      in
      2005. This increase is due to higher average debt outstanding and rising
      interest rates during 2006. Our average borrowing rate, before the effects
      of
      hedging, for 2006 was 4.8% compared to 3.4% for 2005. At December 31, 2006,
      20%
      of our debt was based on fixed interest rates while 80% was floating. These
      instruments are more fully described in Note 10.





**Capital
      Expenditures**





During
      the year
      ended December 31, 2006
      we spent $491.2 million on development
      capital and facilities, our largest capital program to date. This was $6.2
      million higher than our guidance of $485.0 million and $122.5 million or 33%
      higher than the $ 368.7 million
      spent in
      2005. We achieved a 99% success rate with our drilling program as 361 net wells
      were drilled during 2006. Development in 2006 focused primarily on Bakken oil,
      shallow gas, coalbed methane, waterfloods, and our Joslyn oil sands
      property.





Property
      acquisitions were $51.3 million for the year ended December 31, 2006 compared
      to
      $119.9 million in 2005. Acquisitions during 2006 included $16.0 million for
      assets in the U.S., as well as $11.9 million and $11.7 million for properties
      at
      Copton and Gleneath respectively. There were no corporate acquisitions during
      2006 whereas in 2005 we spent $584.1 million for the acquisitions of Lyco Energy
      Corporation and TriLoch Resources Inc. Property dispositions were $21.1 million
      for the year ended December 31, 2006 compared to $66.5 million for 2005. The
      majority of our 2006 divestments related to the sale of a 1% working interest
      in
      the Joslyn property in the amount of $19.7 million compared to the 2005 non-core
      divestment program which raised $66.5 million.








**Capital
                Expenditures ($ millions)**
            
            
            **2006**
            
            
            2005Development
                expenditures
            
            **$**
            **380.5**
            
            $
            272.2Plant
                and
                facilities
            
            
            **110.7**
            
            
            96.5Development
                Capital
            
            
            **491.2**
            
            
            368.7Office
            
            
            **5.0**
            
            
            4.3Sub-total
            
            
            **496.2**
            
            
            373.0Acquisitions
                of oil and gas properties(1)
            
            
            **51.3**
            
            
            119.9Corporate
                acquisitions
            
            
            **-**
            
            
            584.1Dispositions
                of oil and gas properties(1)
            
            
            **(21.1**
            **)**
            
            (66.5
            )Total
                Net
                Capital Expenditures
            
            **$**
            **526.4**
            
            $
            1,010.5Total
                Capital
                Expenditures financed with cash flow
            
            **$**
            **249.4**
            
            $
            276.4Total
                Capital
                Expenditures financed with debt and equity
            
            
            **296.5**
            
            
            734.1Total
                non-cash consideration for 1% sale of Joslyn project
            
            
            **(19.5**
            **)**
            
            -Total
                Net
                Capital Expenditures
            
            **$**
            **526.4**
            
            $
            1,010.5


(1) Net
      of post-closing
      adjustments.








The
      following is a
      summary by major property of our largest development capital expenditures during
      2006 and 2005.


Page
          8 of
          25





**($
                millions)**
              **Property**
            
            
            **Development
                Type**
            
            
            **2006**
            
            
            2005Sleeping
                Giant
            
            
            Bakken
                oil
            
            **$**
            **116.7**
            
            $
            29.1Joslyn
                and
                oil sands
            
            
            Oil
                sands
            
            
            **39.1**
            
            
            33.2Bantry
            
            
            Conventional
                oil and shallow gas
            
            
            **21.7**
            
            
            42.0Joarcam
            
            
            Oil
                waterflood
            
            
            **20.2**
            
            
            16.9Pembina
                5-Way
            
            
            Oil
                waterflood
            
            
            **15.7**
            
            
            19.8Medicine
                Hat
            
            
            Oil
                waterflood and shallow gas
            
            
            **14.9**
            
            
            11.0Shackleton
            
            
            Shallow
                gas
            
            
            **12.7**
            
            
            5.6Hanna/Garden
                Plains
            
            
            Shallow
                gas
            
            
            **12.5**
            
            
            18.5Joffre
            
            
            Coalbed
                methane
            
            
            **12.5**
            
            
            15.9Deep
                Basin
            
            
            Natural
                gas
            
            
            **12.4**
            
            
            11.6Other
            
            
            Oil
                and gas
            
            
            **212.8**
            
            
            165.1Total
            
            
            
            
            **$**
            **491.2**
            
            $
            368.7





We
      expect total development capital expenditures in 2007 to be approximately $410
      million. We plan to spend approximately $70 million on Bakken oil development,
      $65 million on waterflood development, $43 million on shallow natural gas and
      coalbed methane development and $40 million on oil sands development. We expect
      other conventional development costs to be approximately $192 million during
      2007.




**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, 2006 DDA&A increased to $15.38/BOE compared to $13.27/BOE during the
      year ended December 31, 2005. The increase was due to the inclusion of a full
      year of operations from our U.S. properties which were acquired in the latter
      half of 2005.





No
      impairment existed at December 31, 2006 using year-end reserves and management’s
      estimates of future prices. Our future price estimates are more fully discussed
      in Note 3.





**Asset
      Retirement Obligations**





We
      have estimated our 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 $123.6 million
      at December 31, 2006 compared to $110.6 million at December 31, 2005. The
      increase of $13.0 million was due to our acquisition and development activity
      during the year combined with changes in estimated future liabilities. The
      remainder of the change was due to retirement costs incurred offset by accretion
      expense for the year. See Note 4.





The
      following chart
      compares the amortization of the asset retirement cost, accretion of the asset
      retirement obligation, and asset retirement obligations settled.





**($
                millions)**
            
            
            **2006**
            
            
            2005Amortization
                of the asset retirement cost
            
            **$**
            **12.6**
            
            $
            10.6Accretion
                of
                the asset retirement obligation
            
            
            **6.2**
            
            
            6.3Total
                Amortization and Accretion
            
            **$**
            **18.8**
            
            $
            16.9Asset
                Retirement Obligations Settled
            
            **$**
            **11.5**
            
            $
            7.8




Actual
      asset
      retirement costs will be incurred at different times compared to the recording
      of amortization and accretion charges. Actual asset retirement costs will be
      incurred over the next 66 years with the majority between 2036 and 2045. For
      accounting purposes, the asset retirement cost is amortized using a
      unit-of-production method based on proved reserves before royalties while the
      asset retirement obligation accretes until the time the obligation is settled.





**Taxes**





*Future
      Income
      Taxes*





Future
      income taxes
      arise from differences between the accounting and tax bases of the operating
      companies’ assets and liabilities. Net income of the operating companies and the
      tax recovery fluctuate based on the royalty and interest payments to the Fund.
      Therefore, the future income tax that is recorded on the balance sheet is
      expected to be recovered through earnings over time.





Page
          9 of
          25




rule




For
      the year ended
      December 31, 2006, a future income tax recovery of $112.0 million was recorded
      in income compared to a future income tax expense of $15.3 million in 2005.
      The
      change year-over-year was mainly due to a lower effective tax rate for
      2006, a change in discretionary tax deductions in prior years resulting in
      a $21.4 million recovery and recognition of a tax rate reduction for future
      years resulting in a $35.5 million recovery. See Note 9 for more
      details.





On
      October 31, 2006, the Government announced plans to introduce a tax on publicly
      traded income trusts, effective for 2011. A “Notice of Ways and Means Motion”
was passed in parliament shortly after the government announcement. This notice
      was a one-page summary of the government’s proposal and it did not identify any
      specific amendments to the Income Tax Act. On December 21, 2006, draft
      legislative proposals to implement the tax were released for comment. If the
      tax
      legislation becomes substantively enacted as proposed, future income taxes
      may
      be adjusted to include temporary differences between the accounting and tax
      bases of the trust’s assets and liabilities.





*Current
      Income
      Taxes*





In
      our current structure, payments are made between the operating entities and
      the
      Fund which ultimately transfers both income and future income tax liability
      to
      our unitholders. As a result, no cash income taxes have been paid by our
      Canadian operating entities.





For
      the year ended
      December 31, 2006 our U.S. operations incurred income related taxes in the
      amount of $18.2 million compared to $2.8 million for the year ended December
      31,
      2005. The increase is primarily a result of a full year of U.S. operations
      in
      2006.





The
      amount of
      current taxes recorded throughout the year is dependent upon the level of U.S.
      cash flow as well as the timing of both capital expenditures and repatriation
      of
      the funds to Canada. Our U.S. taxes as a percentage of cash flow, assuming
      constant working capital, were 9% for the year ended December 31, 2006 as
      compared to our guidance of 15%. The reduction is mainly due to funds being
      retained in the U.S. for the 2007 development capital program and acquisitions
      (see Note 13 describing the acquisition of gross overriding royalty interests
      in
      the Jonah natural gas field in Wyoming). We expect the current income and
      withholding taxes to average approximately 15% of cash flow from U.S. operations
      in 2007 assuming all funds are repatriated to Canada after U.S. development
      capital spending.





*Tax
      Pools*





We
      estimate our tax pools at December 31, 2006 to be as follows:





**Pool
                Type ($ millions)**
            
            
            **Trust**
            
            
            **Operating
                entities**
            
            
            **Total**COGPE
            
            **$**
            **450**
            
            **$**
            **100**
            
            **$**
            **550**CDE
            
            
            **-**
            
            
            **300**
            
            
            **300**UCC
            
            
            **-**
            
            
            **500**
            
            
            **500**Tax
                losses
                and other
            
            
            **50**
            
            
            **400**
            
            
            **450**Foreign
                tax
                pools
            
            
            **-**
            
            
            **100**
            
            
            **100**Total
            
            **$**
            **500**
            
            **$**
            **1,400**
            
            **$**
            **1,900**





**Net
      Income**





Net
      income for the
      year ended December 31, 2006 was $544.8 million or $4.48 per trust unit compared
      to $432.0 million or $3.96 per trust unit for the year ended December 31, 2005.
      The $112.8 million increase in net income was primarily due to
      a $49.0 million increase in oil and gas sales (net of transportation costs),
      reduced risk management costs of $106.7 million and an increased future income
      tax recovery of $127.4 million, partially offset by increased DDA&A charges
      of $95.1 million, operating costs of $34.4 million and G&A costs of $19.6
      million .





**Cash
      Flow
      from Operating Activities**





Cash
      flow from
      operating activities for the year ended December 31, 2006 was $863.7 million
      or
      $7.10 per trust unit compared to $774.6 million or $7.10 per trust unit for
      2005. Cash flow increased during the year as a result of higher oil and gas
      sales and reduced cash risk management costs, offset in part by increases in
      operating costs and G&A expenses.





Page
          10 of
          25










**Selected
      Financial Results**





**Per
                BOE of production (6:1)**
            
            
            **2006**
            
            
            2005Production
                per day
            
            
            **85,779**
            
            
            79,727Weighted
                average sales price(1)
            
            **$**
            **50.23**
            
            $
            52.36Royalties
            
            
            **(9.36**
            **)**
            
            (10.21
            )Financial
                contracts
            
            
            **(0.11**
            **)**
            
            (3.78
            )Deduct:
                Non-cash financial contract gain
            
            
            **(0.99**
            **)**
            
            (1.12
            )Operating
                costs
            
            
            **(8.02**
            **)**
            
            (7.45
            )General
                and
                administrative
            
            
            **(1.91**
            **)**
            
            (1.39
            )Add
                back:
                Non-cash G&A expense (trust unit rights)
            
            
            **0.20**
            
            
            0.11Interest
                expense, net of interest and other income
            
            
            **(0.95**
            **)**
            
            (0.51
            )Foreign
                exchange gain (loss)
            
            
            **0.02**
            
            
            (0.06
            )Deduct:
                Non-cash foreign exchange gain
            
            
            **-**
            
            
            (0.07
            )Capital
                taxes
            
            
            **(0.11**
            **)**
            
            (0.22
            )Current
                income tax
            
            
            **(0.59**
            **)**
            
            (0.09
            )Asset
                retirement obligations settled
            
            
            **(0.37**
            **)**
            
            (0.27
            )Cash
                flow
                before changes in non-cash working capital
            
            
            **28.04**
            
            
            27.30Asset
                retirement obligations settled
            
            
            **0.37**
            
            
            0.27Non-cash
                items:Depletion,
                depreciation, amortization and accretion
            
            
            **(15.38**
            **)**
            
            (13.27
            )Financial
                contracts
            
            
            **0.99**
            
            
            1.12G&A
                expense (trust unit rights)
            
            
            **(0.20**
            **)**
            
            (0.11
            )Foreign
                exchange gain
            
            
            **-**
            
            
            0.07Future
                income
                tax recovery/(expense)
            
            
            **3.58**
            
            
            (0.53
            )Total
                net
                income per BOE
            
            **$**
            **17.40**
            
            $
            14.85


(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 2006.





**($
                millions, except per unit amounts)**
            
            
            **Canada**
            
            
            **U.S.**
            
            
            **Total****Daily
                Production Volumes**Natural
                gas
                (Mcf/day)
            
            
            265,019
            
            
            5,953
            
            
            270,972Crude
                oil
                (bbls/day)
            
            
            25,858
            
            
            10,276
            
            
            36,134Natural
                gas
                liquids (bbls/day)
            
            
            4,483
            
            
            -
            
            
            4,483Total
                daily
                sales (BOE/day)
            
            
            74,511
            
            
            11,268
            
            
            85,779**Pricing****(1)**Natural
                gas
                (per Mcf)
            
            $
            6.79
            
            $
            7.78
            
            $
            6.81Crude
                oil (per
                bbl)
            
            
            59.36
            
            
            67.93
            
            
            61.80Natural
                gas
                liquids (per bbl)
            
            
            50.90
            
            
            -
            
            
            50.90**Capital**Development
                capital and office
            
            $
            378.5
            
            $
            117.7
            
            $
            496.2Acquisitions
                of
                oil and gas properties
            
            
            35.3
            
            
            16.0
            
            
            51.3Dispositions
                of
                oil and gas properties
            
            
            (21.1
            )
            
            -
            
            
            (21.1
            )**Revenues**Oil
                and gas
                sales(1)
            
            $
            1,301.0
            
            $
            271.7
            
            $
            1,572.7Royalties
            
            
            (241.0
            )
            
            (52.2)
            (2)
            
            (293.2
            )Other
                financial
                contracts
            
            
            (3.2
            )
            
            -
            
            
            (3.2
            )**Expenses**Operating
            
            $
            243.8
            
            $
            7.4
            
            $
            251.2General
                and
                administrative
            
            
            51.4
            
            
            8.5
            
            
            59.9Depletion,
                depreciation, amortization and accretion
            
            
            369.6
            
            
            112.0
            
            
            481.6Current
                income
                taxes
            
            
            -
            
            
            18.2
            
            
            18.2


(1)  Net
      of oil and gas
      transportation costs, but before the effects of commodity derivative
      instruments.


(2)  Royalties
      include
      U.S. state production tax.








Page
          11 of
          25


rule




**Quarterly
      Financial Information**





Overall
      oil and gas
      sales increased during 2005 due to higher crude oil production and higher crude
      oil and natural gas prices, and decreased during 2006 due to lower gas prices.
      Net income has been affected by fluctuating oil and gas prices and risk
      management costs, the fluctuating Canadian dollar, higher operating and G&A
      costs, changes in future tax provisions as well as changes to accounting
      policies adopted during 2005. Furthermore, changes in the fair value of our
      financial contracts, which are impacted by future prices, continue to cause
      net
      income to fluctuate between quarters.





**Quarterly
              Financial
              Information**
            
            
            **Oil
              and Gas**
            
            
            
            
            
            **Net
              Income Per Trust Unit****($
                millions, except per trust unit amounts)**
            
            
            **Sales****(1)**
            
            
            **Net
                Income**
            
            
            **Basic**
            
            
            **Diluted****2006**Fourth
                Quarter
            
            $
            369.5
            
            $
            110.2
            
            $
            0.90
            
            $
            0.89Third
                Quarter
            
            
            398.0
            
            
            161.3
            
            
            1.31
            
            
            1.31Second
                Quarter
            
            
            403.5
            
            
            146.0
            
            
            1.19
            
            
            1.19First
                Quarter
            
            
            401.7
            
            
            127.3
            
            
            1.08
            
            
            1.07Total
            
            **$**
            **1,572.7**
            
            **$**
            **544.8**
            
            **$**
            **4.48**
            
            **$**
            **4.47****2005**Fourth
                Quarter
            
            $
            503.2
            
            $
            150.9
            
            $
            1.29
            
            $
            1.28Third
                Quarter
            
            
            398.7
            
            
            107.1
            
            
            0.97
            
            
            0.97Second
                Quarter
            
            
            320.0
            
            
            108.8
            
            
            1.04
            
            
            1.04First
                Quarter
            
            
            301.8
            
            
            65.2
            
            
            0.63
            
            
            0.62Total
            
            $
            1,523.7
            
            $
            432.0
            
            $
            3.96
            
            $
            3.95


(1)  Net
      of oil and gas
      transportation costs, but before the effects of commodity derivative
      instruments








**Summary
      Fourth Quarter Information**





In
      comparing the
      fourth quarter of 2006 with the same period in 2005:


•  Net
      income
      decreased 27% to $110.2 million due to decreased natural gas prices and
      increased operating and G&A costs, partially offset by reduced risk
      management costs.


•  Cash
      flow decreased
      25% to $207.1 million in 2006 compared to $277.9 million in 2005.


•  Average
      daily
      production increased 2 % due to our
      development capital program.


•  The
      average selling
      price per BOE decreased 28% due to weaker natural gas prices.


•  Operating
      expenses
      increased 17% on a BOE basis to
      $8.52/BOE. Due to the timing of well servicing and facility maintenance programs
      additional costs were recorded in the fourth quarter of 2006.


•  G&A
      expenses
      increased 29% on a BOE basis to $2.13 /BOE
      due to
      compensation costs.


•  Development
      capital
      spending decreased 12% compared to the fourth quarter of 2005 as a result of
      2005 capital spending being weighted towards the fourth quarter while 2006
      capital spending was evenly weighted between all four quarters.





**Summary
                Fourth Quarter Information**
              **($
                millions, except per unit amounts)**
            
            
            **Three
                Months Ended**
              **December
                31, 2006**
            
            
            Three
                Months Ended
              December
                31, 2005
            
            
            %
                Change**Daily
                Production Volumes**Natural
                gas
                (Mcf/day)
            
            
            **277,715**
            
            
            269,443
            
            
            3
            %Crude
                oil
                (bbls/day)
            
            
            **36,339**
            
            
            35,167
            
            
            3
            %Natural
                gas
                liquids (bbls/day)
            
            
            **4,467**
            
            
            5,045
            
            
            (11
            %)Total
                daily
                sales (BOE/day)
            
            
            **87,092**
            
            
            85,119
            
            
            2
            %**Average
                Selling Price****(1)**Natural
                gas
                (per Mcf)
            
            **$**
            **6.58**
            
            $
            11.65
            
            
            (44
            %)Crude
                oil
                (per bbl)
            
            
            **54.53**
            
            
            58.41
            
            
            (7
            %)Natural
                gas
                liquids (per bbl)
            
            
            **46.15**
            
            
            50.56
            
            
            (9
            %)Per
                BOE
            
            
            **46.11**
            
            
            64.26
            
            
            (28
            %)**Revenue****(1)**
            
            
            **369.5**
            
            
            503.2
            
            
            (27
            %)Per
                BOE
            
            
            **46.11**
            
            
            64.26
            
            
            (28
            %)**Operating
                Expenses**
            
            
            **68.3**
            
            
            57.1
            
            
            20
            %Per
                BOE
            
            
            **8.52**
            
            
            7.29
            
            
            17
            %**General
                and Administrative Expenses**
            
            
            **17.1**
            
            
            12.9(2)
            
            
            33
            %Per
                BOE
            
            
            **2.13**
            
            
            1.65(2)
            
            
            29
            %






Page
          12 of
          25







**Net
                Income**
            
            
            **110.2**
            
            
            150.9
            
            
            (27
            %)Per
                BOE
            
            
            **13.75**
            
            
            19.27
            
            
            (29
            %)**Cash
                flow**
            
            
            **207.1**
            
            
            277.9
            
            
            (25
            %)Per
                BOE
            
            
            **25.85**
            
            
            35.49
            
            
            (27
            %)**Development
                Capital Spending**
            
            
            **123.1**
            
            
            139.1
            
            
            (12
            %)Acquisitions
            
            
            **4.8**
            
            
            112.5
            
            
            (96
            %)Divestments
            
            
            **0.1**
            
            
            0.4
            
            
            (75
            %)


(1)  Net
      of oil and gas
      transportation costs, but before the effects of commodity derivative
      instruments.


(2)  Certain
      prior year
      amounts have been restated to conform with current year
      presentation.








**Three
      Year
      Summary of Key Measures**





Overall,
      increased
      production volumes have resulted in higher oil and gas sales, net income and
      cash flow from operating activities over the last three years. The rise in
      crude
      oil and natural gas prices during 2004 and 2005 contributed to higher oil and
      gas sales and cash flow, however the growth of these measures moderated in
      2006
      as a result of lower natural gas prices. The following table provides a summary
      of net income, cash flow and other key measures.





**($
                millions, except per unit amounts)**
            
            
            **2006**
            
            
            2005
            
            
            2004Oil
                and gas
                sales(1)
            
            **$**
            **1,572.7**
            
            $
            1,523.7
            
            $
            1,124.6Net
                income
            
            
            **544.8**
            
            
            432.0
            
            
            258.3Per
                unit
                (Basic)(2)
            
            
            **4.48**
            
            
            3.96
            
            
            2.60Per
                unit
                (Diluted)
            
            
            **4.47**
            
            
            3.95
            
            
            2.60Cash
                flow
                from operating activities
            
            
            **863.7**
            
            
            774.6
            
            
            555.1Per
                unit
                (Basic)(2)
            
            
            **7.10**
            
            
            7.10
            
            
            5.59Cash
                distributions
            
            
            **614.3**
            
            
            498.2
            
            
            423.3Per
                unit
                (Basic)(2)
            
            
            **5.05**
            
            
            4.57
            
            
            4.26Payout
                ratio
            
            
            **71**
            **%**
            
            64
            %
            
            76
            %Total
                assets
            
            
            **4,203.8**
            
            
            4,130.6
            
            
            3,180.7Long-term
                debt, net of cash
            
            
            **679.7**
            
            
            649.8
            
            
            585.0


(1)  Net
      of oil and gas
      transportation costs, but before the effects of commodity derivative
      instruments.


(2) Based on weighted
      average trust units outstanding. Cash distributions to unitholders per unit
      will
      not correspond to the actual monthly distributions of $5.04 as a result of
      using
      the annual weighted average trust units outstanding.








**Liquidity
      and Capital Resources**





*Sustainability
      of our Distributions and Asset Base*





As
      an oil and gas trust we have a declining asset base and therefore rely on
      acquisitions and ongoing development activities to replace production and add
      additional reserves. Our future oil and natural gas production and reserves
      are
      highly dependent on our success in exploiting our asset base and acquiring
      additional reserves. To the extent we are unsuccessful in these activities
      our
      cash distributions could be reduced.





Acquisitions
      and
      development activities may be funded internally by withholding a portion of
      cash
      flow or through external sources of capital such as debt or the issuance of
      equity. To the extent that we withhold cash flow to finance these activities,
      the amount of cash distributions will be reduced. Should external sources of
      capital become limited or unavailable, our ability to make the necessary
      acquisitions and development expenditures to maintain or expand our asset base
      may be impaired and the amount of cash distributions may be reduced.





*Distribution
      Policy*





The
      amount of cash
      distributions is proposed by management and approved by the Board of Directors.
      We continually assess distribution levels with respect to forecasted cash flows,
      debt levels and capital spending plans. The level of cash withheld has
      historically varied between 10% and 40% of annual cash flow from operating
      activities and is dependent upon numerous factors, the most significant of
      which
      are the prevailing commodity price environment, our current levels of
      production, debt obligations, our access to equity markets and funding
      requirements for our development capital program. Although we intend to continue
      to make cash distributions to our unitholders, these distributions are not
      guaranteed.




Page
          13 of
          25


rule




*Cash
      Flow from
      Operating Activities, Cash Distributions and Payout Ratio*





Cash
      flow from
      operating activities and cash distributions are reported on the Consolidated
      Statements of Cash Flows.





During
      2006 cash
      distributions of $614.3 million were funded entirely through cash flow of $863.7
      million. Our payout ratio, which is calculated as cash distributions divided
      by
      cash flow, was 71% for 2006 compared to 64% in 2005.





After
      consideration
      of cash distributions, the balance of our 2006 cash flow of $249.4 million
      was
      used to fund approximately 47% of our net capital expenditures. Our remaining
      net capital expenditures of $296.5 million were financed from the proceeds
      of
      our March 2006 equity issue and through additional debt. For more information,
      refer to the Capital Expenditures section of the MD&A.





In
      aggregate, our 2006 cash distributions of $614.3 million and our net capital
      expenditures of $526.4 million totaled $1,140.7 million, or approximately 132%
      of our cash flow of $863.7 million. We rely on access to capital markets to
      the
      extent cash distributions and net capital expenditures exceed cash flow. Over
      the long term we would expect to support our distributions and capital
      expenditures with our cash flow; however, we would continue to fund acquisitions
      and growth through additional debt and equity. There will be years, especially
      when we are investing capital in opportunities that do not immediately generate
      cash flow (such as our Joslyn oil sands project) that this relationship will
      vary. In the oil and gas sector, because of the nature of reserve reporting,
      the
      natural reservoir declines and the risks involved in capital investment, it
      is
      difficult to distinguish between capital spent on maintaining productive
      capacity and capital spent on growth opportunities. Therefore we do not disclose
      maintenance capital separate from development capital spending.





For
      the year ended
      December 31, 2006 our cash distributions exceeded our net income by $69.5
      million (2005 - $66.2 million). Net income includes $318.9 million of non-cash
      items (2005 - $342.6 million) such as DDA&A and future income taxes that do
      not reduce our cash flow from operations. Charges such as DDA&A are not a
      good proxy for the cost of maintaining our productive capacity as they are
      based
      on the historical costs of our PP&E and not the fair market value of
      replacing those assets within the context of the current commodity price
      environment. Future income taxes can fluctuate from period to period as a result
      of changes in tax rates, or based on the royalty, interest and dividends from
      our operating subsidiaries to the Fund, all of which are not indicative of
      the
      productive capacity of our entity. The level of investment in a given period
      may
      not be sufficient to replace productive capacity given the natural declines
      associated with oil and natural gas assets. In these instances a portion of
      the
      cash distributions paid to unitholders may represent a return of the
      unitholders’ capital.





The
      following table
      compares cash distributions to cash flow and net income.





**($
                millions, except per unit amounts)**
            
            
            **2006**
            
            
            2005Cash
                flow
                from operating activities:
            
            **$**
            **863.7**
            
            $
            774.6Use
                of cash
                flow:Cash
                distributions
            
            **$**
            **614.3**
            
            $
            498.2Capital
                expenditures
            
            
            **249.4**
            
            
            276.4**$**
            **863.7**
            
            $
            774.6Excess
                of
                cash flow over cash distributions
            
            **$**
            **249.4**
            
            $
            276.4Net
                income
            
            **$**
            **544.8**
            
            $
            432.0Shortfall
                of
                net income over cash distributions
            
            **$**
            **(69.5**
            **)**
            $
            (66.2
            )Cash
                distributions per weighted average trust unit
            
            **$**
            **5.05**
            
            $
            4.57Payout
                ratio(1)
            
            
            **71**
            **%**
            
            64
            %


(1) Based
      on cash
      distributions divided by cash flow from operating activities.





*Asset
      Retirement Costs*





Actual
      asset
      retirement costs incurred in the period are deducted for purposes of calculating
      cash flow. Differences between actual site restoration costs incurred and the
      amortization of the capitalized asset retirement cost and accretion of the
      asset
      retirement obligation are discussed in the Asset Retirement Obligations section
      of the MD&A and Note 4.


Page
          14 of
          25





*Long-Term
      Debt*





Long-term
      debt, net
      of cash, at December
      31, 2006 was $679.7 million ,
      an increase of
      $29.8 million from December 31, 2005. Long-term debt at December 31, 2006 is
      comprise d
      of $348.5 m illion
      of bank
      indebtedness and $331.3 million of senior unsecured notes.





Our
      working
      capital, excluding cash, at December 31, 2006 increased $46.1 million compared
      to December 31, 2005. Current liabilities were higher in 2005 primarily due
      to
      the recording of our commodity financial instruments at fair value.




We
      continue to maintain a conservative balance sheet as demonstrated
      below:





**Financial
                Leverage and Coverage**
            
            
            **Year
                ended**
              **Dec.
                31, 2006**
            
            
            Year
                ended
              Dec.
                31, 2005Long-term
                debt to trailing cash flow
            
            
            **0.8
                x**
            
            
            0.8
                xCash
                flow****to
                interest
                expense
            
            
            **26.8
                x**
            
            
            30.0
                xLong-term
                debt to long-term debt plus equity
            
            
            **20**
            **%**
            
            21
            %


Long-term
      debt is
      measured net of cash.


Cash
      flow and
      interest expense are 12-months trailing.





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, 2006 we had $501.5
      million of available borrowing capacity under this facility, which currently
      extends to November, 2009. This bank debt carries floating interest rates that
      are expected to range between 55.0 and 110.0 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 cash 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. As at December 31, 2006 we are in compliance with our debt
      covenants. Refer to our 2006 Annual Information Form for a detailed description
      of these covenants.





Principal
      payments
      on Enerplus’ senior unsecured notes are required commencing in 2010 and 2011 and
      are more fully discussed in Note 7.





We
      anticipate that we will continue to have adequate liquidity to fund planned
      development capital spending during 2007 through a combination of cash flow
      retained by the business and debt. A portion of our $410.0 million development
      capital budget for 2007 is discretionary and could be revised downward in the
      event of a commodity price downturn or similar economic event.





**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 $6.4 million in
      2007.





Approximately
      35%
      of our current gas production is dedicated to 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.





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 $6.7 million in 2007. The Fund’s commitments, contingencies, and
      guarantees are more fully described in Note 11.





Enerplus
      has the
      following minimum annual commitments including long-term debt:


Page
          15 of
          25





Minimum
                Annual Commitment Each Year
            
            
            Total
                Committed**($
                millions)**
            
            
            **Total**
            
            
            2007
            
            
            2008
            
            
            2009
            
            
            2010
            
            
            2011
            
            
            after
              2011Bank
                credit
                facility
            
            **$**
            **348.5****(1)**
            
            $
            -
            
            $
            -
            
            $
            348.5
            
            $
            -
            
            $
            -
            
            $
            -Senior
                unsecured notes
            
            
            **331.3****(1)**
            
            
            -
            
            
            -
            
            
            -
            
            
            53.7
            
            
            66.3
            
            
            211.3Pipeline
                commitments
            
            
            **28.5**
            
            
            6.4
            
            
            5.8
            
            
            3.0
            
            
            2.4
            
            
            2.2
            
            
            8.7Office
                lease
            
            
            **20.9**
            
            
            6.7
            
            
            6.8
            
            
            6.7
            
            
            0.6
            
            
            0.1
            
            
            -Total
                commitments(2)
            
            **$**
            **729.2**
            
            $
            13.1
            
            $
            12.6
            
            $
            358.2
            
            $
            56.7
            
            $
            68.6
            
            $
            220.0


(1) Interest payments
      have not been included since future debt levels and interest rates are not
      known
      at this time.


(2)  Crown
      and surface
      royalties, lease rentals, mineral taxes, and abandonment and reclamation costs
      (hydrocarbon production rights) have not been included as amounts paid depend
      on
      future ownership, production, prices and the legislative
      environment.





**Accumulated
      Deficit**





We
      have
      historically paid cash distributions in excess of accumulated earnings as cash
      distributions are based on cash flow generated in the period whereas accumulated
      earnings are based on net income which includes non-cash items such as DDA&A
      charges, financial contract gains and losses, unit based compensation charges
      and future income tax provisions.





**Trust
      Unit
      Information**





We
      had 123,151,000 trust units outstanding at December 31, 2006 compared to
      117,539,000 trust units at December 31, 2005. The weighted average number of
      trust units outstanding during 2006 was 121,588,000 (2005 - 109,083,000). At
      February 10, 2007 we had 123,253,000 trust units outstanding.





On
      March 20, 2006 we closed an equity offering of 4,370,000 units at a price of
      $58.00 per unit for gross proceeds of $253,460,000 ($240,287,000 net of issuance
      costs).





On
      August 9, 2005 we announced the closing of a 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.





On
      July 1, 2005 we acquired all of the issued and outstanding shares of TriLoch
      in
      exchange for 1,633,000 trust units, a value of approximately $69.1 million
      after
      issuance costs.





In
      addition 1,242,000 trust units (2005 - 1,144,000) 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 $55.9 million
      (2005 - $40.4 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, as well as consider the Government’s proposal to implement a tax
      on trusts.





*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 has historically transferred all of its taxable income
      to
      the unitholders by way of distributions.





In
      computing income, unitholders are required to include the taxable portion of
      distributions received 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 $5.04 per trust unit in cash distributions to unitholders on record during
      2006. For Canadian tax purposes, approximately 4% of these distributions, or
      $0.22 per trust unit was a tax deferred return of capital, approximately 95%
      or
      $4.81 per trust unit was taxable to unitholders as other income, and less than
      1% or $0.01 per trust unit was taxable eligible dividend income.





Page
          16 of
          25


rule




For
      2007, 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, among other things, production,
      commodity prices and cash 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 2006 and 2005.





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$4.42 per trust unit to U.S. residents during the 2006 calendar year,
      of
      which 10% or US$0.42 per trust unit was a tax deferred return of capital and
      90%
      or US$4.00 per unit was a taxable qualified dividend.





For
      2007, we
      estimate that 90% of cash distributions will be taxable to most U.S. investors
      and 10% will be a tax deferred return of capital. Actual taxable amounts may
      vary depending on actual distributions which are dependent upon production,
      commodity prices and cash 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 14. 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 efforts 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 not
      exploration in nature and is more focused on 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 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 method 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.





Page
          17 of
          25


rule




*Reserves*





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.





*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.





*Business
      Combinations*





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 NI 51-101 reserve
      standards, and (b) future prices of oil and gas.





*Commodity
      Prices*





Management’s
      estimates of future crude oil and natural gas prices are 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.





*Trust
      Unit
      Rights*





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.





*Derivative
      Financial Instruments*





Management
      uses
      derivative financial instruments to manage its exposure to market risks relating
      to commodity prices, foreign currency exchange rates and interest rates. Fair
      values of derivative contracts are subject to fluctuation depending on the
      underlying commodity prices, foreign currency exchange rates and interest
      rates.








**RECENT
      CANADIAN ACCOUNTING AND RELATED PRONOUNCEMENTS**





**Convergence
      of Canadian GAAP with International Financial Reporting Standards**





In
      2006, Canada’s Accounting Standards Board ratified a strategic plan that will
      result in Canadian GAAP, as used by public entities, being converged with
      International Financial Reporting Standards over a transitional period. The
      Accounting Standards Board is expected to develop and publish a detailed
      implementation plan with a transition period expected to be approximately five
      years. This convergence initiative is in its early stages as of the date of
      these annual consolidated financial statements and the Fund also has the option
      to adopt U.S. GAAP at any time prior to the expected conversion date.
      Accordingly, it would be premature to assess the impact of the initiative,
      if
      any, on the Fund at this time.





**Financial
      Instruments, Comprehensive Income and Hedges**





The
      Accounting
      Standards Board (AcSB) has issued five new accounting standards relating to
      the
      recognition, measurement, disclosure and presentation of financial instruments.
      The new standards comprise five handbook sections:


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***CICA
      Section 3855*** **- *Financial
      Instruments - Recognition and Measurement***





This
      standard
      establishes the criteria for recognizing and measuring financial assets,
      financial liabilities and non-financial derivatives. It also specifies how
      financial instrument gains and losses are to be presented. Financial liabilities
      will be classified as either held-for-trading or other. Held-for-trading
      instruments will be recorded at fair value with realized and unrealized gains
      and losses reported in net income. Other instruments will be accounted for
      at
      amortized cost with gains and losses reported in net income in the period that
      the liability is settled.





Derivatives
      will be
      classified as held-for-trading unless designated as hedging instruments. All
      derivatives, including embedded derivatives that must be separately accounted
      for, will be recorded at fair value on the consolidated balance sheet. For
      derivatives that hedge the changes in fair value of an asset or liability,
      changes in the derivatives’ fair value will be reported in net income and will
      be substantially offset by changes in the fair value of the hedged asset or
      liability attributable to the risk being hedged. For derivatives that hedge
      variability in cash flows, the effective portion of the changes in the
      derivatives’ fair value will be initially recognized in other comprehensive
      income and the ineffective portion will be recorded in net income. The amounts
      temporarily recorded in other comprehensive income will subsequently be
      reclassified to net income in the periods when net income is affected by the
      variability in the cash flows of the hedged item.





***CICA
      Section 3865*** **- *Hedges***





This
      standard
      provides optional alternative treatment to Section 3855 for entities which
      choose to designate qualifying transactions as hedges for accounting purposes.
      It will replace Accounting Guideline 13 (AcG 13) - *Hedging
      Relationships* ,
      and build on
      Section 1560 - *Foreign
      Currency Translation* ,
      by specifying how
      hedge accounting is applied and what disclosures are necessary when it is
      applied. Retroactive application of this Section is not permitted.





***CICA
      Section 1530*** **- *Comprehensive
      Income***





This
      standard
      introduces a new requirement to temporarily present certain gains and losses
      as
      part of a new earnings measurement called comprehensive income.





***CICA
      Section 3862*** **- *Financial
      Instruments - Disclosures***





This
      standard
      requires entities to provide disclosures in their financial statements that
      enable users to evaluate the significance of financial instruments to the
      entity's financial position and performance. It also requires that entities
      disclose the nature and extent of risks arising from financial instruments
      and
      how the entity manages those risks.





***CICA
      Section 3863*** **- *Financial
      Instruments - Presentation***





This
      standard
      establishes presentation guidelines for financial instruments and non-financial
      derivatives and deals with the classification of financial instruments, from
      the
      perspective of the issuer, between liabilities and equity, the classification
      of
      related interest, dividends, losses and gains, and the circumstances in which
      financial assets and financial liabilities are offset.





CICA
      sections 3855,
      3865 and 1530 are effective for annual and interim periods in fiscal years
      beginning on or after October 1, 2006. At this time we are unable to quantify
      the impact these sections will have on Enerplus. These sections will result
      in
      the following upon adoption:




•
            Our
                interest
                rate and power swaps will be recorded on the balance sheet at fair
                value
                with the offset recorded to opening retained
                earnings.




•
            Our
                cross
                currency and interest rate swap will be recorded on the balance sheet
                at
                fair value with the offset recorded to opening retained earnings.
                The
                underlying US$175,000,000 senior notes will be translated to Canadian
                dollars with the offset recorded to opening retained
                earnings.




•
            Our
                investments in publicly traded marketable securities will be recorded
                on
                the balance sheet at fair value with the offset recorded to opening
                accumulated other comprehensive
                income.




•
            Amounts
                previously recorded in the cumulative translation adjustment will
                be
                reclassified into accumulated other comprehensive income.






CICA
      sections 3862
      and 3863 are effective for annual and interim periods beginning on or after
      October 1, 2007.




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**Accounting
      changes**





The
      AcSB issued
      CICA Section 1506, *Accounting
      Changes* .
      The standard
      prescribes the criteria for changing accounting policies, together with the
      accounting treatment and disclosure of changes in accounting policies and
      estimates, and correction of errors. The standard requires the retrospective
      application to prior periods’ financial statements of changes in accounting
      principle, unless it is impractical to determine either the period-specific
      effects or the cumulative effect of the change. Application is on a prospective
      basis and is effective for changes in accounting policies and estimates and
      correction of errors made in fiscal years beginning on or after January 1,
      2007.





We
      do not expect the adoption of this standard will have any material impact on
      our
      results of operations or financial position.





**Variable
      Interest Entities**





The
      Emerging Issues
      Committee (EIC) issued EIC Abstract 163 - Determining the Variability to be
      Considered in Applying AcG 15. This Abstract, which is harmonized with the
      equivalent United States FASB Staff Position (FSP) FIN 46(R) - 6 - Determining
      the Variability to be Considered in Applying FASB Interpretation No. 46(R),
      provides guidance on how an entity should determine the variability to be
      considered in applying AcG 15 - Consolidation of Variable Interest Entities.
      The
      Abstract is to be applied prospectively to all entities with which an enterprise
      first becomes involved and to all entities previously required to be analyzed
      under AcG 15 when a reconsideration event has occurred beginning the first
      day
      of the first reporting period beginning on or after January 1, 2007.





We
      do not expect the adoption of this standard will have any material impact on
      our
      results of operations or financial position.





**RISK
      FACTORS AND RISK MANAGEMENT**





Enerplus
      investors
      are participating in the net cash flow from a portfolio of crude oil and natural
      gas producing properties. As such, the cash distributions 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:





**Canadian
      Government Announcement on Intention to Tax Trusts**





On
      October 31, 2006
      Canada’s Finance Minister announced a proposal to tax publicly traded income
      trusts. For existing income trusts, such as Enerplus, the Government’s proposal
      includes a four-year transition period which would result in the tax measures
      being effective for 2011. For more details, see the Update on Canadian
      Government Announcement at the beginning of this MD&A.





**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. Refer to the price risk management
      section.*





**Oil
      and Gas
      Reserves Risk**





The
      value of our
      trust units are 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.





*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.*





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*Each
      year,
      independent engineers evaluate a significant portion of our proved and probable
      reserves.*


*Sproule
      Associates Limited (“Sproule”) evaluated 90% of the total proved plus probable
      value (discounted at 10%) of our 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 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 and constant price and
      cost assumptions as of December 31, 2006 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.*





**Operational
      Inflation Risk**





Over
      the last few
      years we have experienced inflationary pressures on both our development capital
      costs and our operating costs. Higher costs decrease the amount of cash flow
      from our operating activities which may affect the amount of distributions
      to
      unitholders.





*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 36% of our 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
      our
      assessment of value at the time of acquisition. Incorrect assessments of value
      can adversely affect distributions to unitholders and the value of our 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 reserve 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
      January 2007, an estimated 70% 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 securities 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. Canada ratified
      the Kyoto Protocol in late 2002, which requires countries to reduce their
      emissions of carbon dioxide and other greenhouse gases. Although the Canadian
      federal government has not released details of any implementation plan, it
      has
      stated that it intends to set targets to limit emissions for the industry and
      regulate the cost of emission credits, which could result in increased capital
      expenditures and operating costs.





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Our
      operations
      expose us to possible regulatory changes by both Canadian and U.S. governments.
      As an oil and gas producer, we are subject to a broad range of regulatory
      requirements. Similarly, as a mutual fund trust, we have a unique structure
      that
      is vulnerable to changes in legislation or income tax law.





*Although
      we
      have no control over these regulatory risks, we continuously monitor changes
      in
      these areas through such activities as participating in industry organizations
      and conferences, the exchange of information with third party experts and
      employing qualified individuals to assess the impact of such changes on our
      financial and operating results.*





**Access
      to
      Capital Markets**





Our
      access to
      capital has allowed us to fund a portion of our acquisitions and development
      capital program through equity and debt, and as a result distribute the majority
      of our cash flow to our unitholders. 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. To the extent the cash
      flow retained by the Fund together with new equity and debt financing is not
      sufficient to cover required capital expenditures then cash distributions to
      unitholders may be reduced.





*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 cash flow for capital
      spending and utilizing the equity markets when deemed
      appropriate.*





*Continued
      access to capital is dependent 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
      health 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 our 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. We carry insurance to cover
      a portion of our property losses, liability and business interruption. EHS
      risks
      are reviewed regularly by the EHS committee comprised of members 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
      20% 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. Our U.S. operations are
      directly exposed to fluctuations in the U.S. dollar when translated to our
      Canadian dollar denominated financial statements.





We
      also have indirect exposure to fluctuations in foreign currency as our crude
      oil
      sales and a portion of our 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.





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*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 and principal 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. We maintain 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 2005 to provide
      statutory protection for unitholders similar to the protection afforded
      shareholders in a corporation. Three other provinces (Ontario, Quebec, and
      Manitoba) also have 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.*





**Recruitment
      and Retention of Qualified Personnel**





There
      is strong
      competition in all aspects of the oil and gas industry. Enerplus competes with
      a
      substantial number of other organizations for capital, acquisitions of reserves,
      undeveloped lands, access to drilling rigs, service rigs and other equipment,
      access to processing facilities, pipeline and refining capacity and in all
      other
      aspects of our operations. Other organizations may have greater technical and
      financial resources than Enerplus which leads to increased competition. Another
      rising challenge is the recruitment and retention of qualified professional
      staff at all levels in the organization. Increased activity within the oil
      and
      gas sector and current high commodity prices can create a competitive
      marketplace which presents challenges in recruiting and retaining key personnel.





*In
      order to
      attract and retain qualified personnel we offer competitive compensation
      including performance based plans.*





**Corporate
      Governance Practices**





*Similar
      to a
      corporation, Enerplus has in place an active Board of Directors which is
      responsible for the overall governance of the Fund. The board is comprised
      of
      nine directors, eight of whom are considered independent, with the remaining
      non-independent director being the Chief Executive Officer. The Board
      continually reviews our practices and procedures and monitors the evolution
      of
      corporate governance practices in both Canada and the United States to ensure
      we
      are in compliance with all the requirements of the TSX, the NYSE and the
      relevant securities administrators. The Board of Directors is further supported
      by a number of Board committees, including an Audit and Risk Management
      Committee, a Corporate Governance and Nominating Committee, an Environment,
      Health and Safety Committee, a Compensation and Human Resources Committee and
      a
      Reserves Committee. In addition to the Board committees, we have formed an
      internal committee, the Management Disclosure and Oversight Committee, to
      enhance and ensure that we meet our increasing disclosure obligations.*





**SUMMARY
      2007 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 2007 outlook should
      be taken within the context of the current commodity price
      environment.





The
      following
      summarizes Enerplus’ 2007 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 flow or cash distributions. Readers are encouraged to apply their
      own price expectations to the following factors to arrive at an expected cash
      distribution.




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**Summary
                of 2007 Expectations**
            
            
            **Target**
            
            
            **Comments**Average
                annual production
            
            
            85,000
                BOE/day
            
            
            Assumes
                no new acquisitions or dispositionsExit
                rate
                December 2007 production
            
            
            86,000
                BOE/day
            
            
            Assumes
                $410 million development capital spending2007
                production mix
            
            
            54%
                gas, 42% oil, 4% NGLAverage
                royalty rate
            
            
            19%
            
            
            Percentage
                of gross unhedged salesOperating
                costs
            
            $
            8.45/BOEG&A
                costs
            
            $
            2.40/BOE
            
            
            Includes
                non-cash charges of $0.30/BOE (unit rights plan
            )U.S.
                income
                and withholding tax - cash costs
            
            
            15%
            
            
            Applied
                to net cash flow generated by U.S. operations and assumes repatriation
                of
                the funds to Canada after U.S. development capital
                spendingAverage
                interest cost
            
            
            5.0%
            
            
            Based
                on current fixed rates and forward marketPayout
                ratio
            
            
            60%
                -90%Development
                capital spending
            
            $
            410
                million
            
            
            Based
                on current plans and price environment





Over
      time we have
      reduced our reliance on acquisitions to supplement production declines by
      focusing our efforts on development capital opportunities within our existing
      asset base. We expect to be able to essentially maintain production in 2007
      through internally generated development efforts without relying on new
      acquisitions.





We
      expect our 2007 development capital spending to be $410 million, which is 17%
      lower than our 2006 spending. We plan to continue to withhold a portion of
      our
      cash flow to finance this capital program and we expect the payout ratio to
      be
      within our 60-90% guidance range. We believe it is important to maintain a
      conservative balance sheet as a defense against commodity price changes and
      to
      be positioned to capture acquisition opportunities.




We
      will continue to
      focus on low-risk development opportunities and review our risk management
      strategies in response to changing prices and the economics of our acquisition
      and development projects.




For
      2007, we
      estimate that 95% of cash distributions will be taxable and 5% will be a
      tax-deferred return of capital for our Canadian unitholders. For our U.S.
      unitholders, we estimate that 90% of cash distribution will be taxable and
      10%
      will be a tax-deferred return of capital.





We
      are encouraged by the results from our 2005 acquisitions which have been fully
      integrated with our existing staff and systems. The establishment of an office
      in Denver continues to enhance our growing presence in the U.S. oil and gas
      market.





**DISCLOSURE
      CONTROLS AND PROCEDURES**





Under
      the
      supervision of our Chief Executive Officer and Chief Financial Officer we have
      evaluated the effectiveness of our disclosure controls and procedures as of
      the
      end of the period covered by this report and concluded that our disclosure
      controls and procedures are effective. There were no changes in our internal
      control over financial reporting during the quarter ended December 31, 2006
      that
      have materially affected, or are reasonably likely to materially affect, our
      internal control over financial reporting.





**Additional
      Information**





Additional
      information relating to Enerplus Resources Fund, including our Annual
      Information Form, is available under our profile on the SEDAR website at
      www.sedar.com, on the EDGAR website at www.sec.gov and at www.enerplus.com .





**FORWARD-LOOKING
      INFORMATION AND STATEMENTS**





This
      management's
      discussion and analysis ("MD&A") contains certain forward-looking
      information and statements within the meaning of applicable securities laws.
      The
      use of any of the words "expect", "anticipate", "continue", "estimate",
      "objective", "ongoing", "may", "will", "project", "should", "believe", "plans",
      "intends" and similar expressions are intended to identify forward-looking
      information or statements. In particular, but without limiting the foregoing,
      this MD&A contains forward-looking information and statements pertaining to
      the following: the amount, timing and tax treatment of cash distributions to
      unitholders; future payout ratios; future tax treatment of income trusts such
      as
      the Fund; the volumes and estimated value of the Fund's oil and gas reserves;
      the volume and product mix




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of
      the Fund's oil and gas production; future oil and natural gas prices and the
      Fund's commodity risk management programs; the amount of future asset retirement
      obligations; future liquidity and financial capacity; future results from
      operations, cost estimates and royalty rates; future development, exploration,
      and acquisition and development activities and related expenditures, including
      with respect to both our conventional and oil sands activities.





The
      forward-looking
      information and statements contained in this MD&A reflect several material
      factors and expectations and assumptions of the Fund including, without
      limitation: that the Fund will continue to conduct its operations in a manner
      consistent with past operations; the general continuance of current industry
      conditions; the continuance of existing (and in certain circumstances, proposed)
      tax and royalty regimes; the accuracy of the estimates of the Fund's reserve
      volumes; and certain commodity price and other cost assumptions. The Fund
      believes the material factors, expectations and assumptions reflected in the
      forward-looking information and statements are reasonable but no assurance
      can
      be given that these factors, expectations and assumptions will prove to be
      correct.





The
      forward-looking
      information and statements included in this MD&A are not guarantees of
      future performance and should not be unduly relied upon. Such information and
      statements involve known and unknown risks, uncertainties and other factors
      that
      may cause actual results or events to differ materially from those anticipated
      in such forward-looking information or statements including, without limitation:
      changes in commodity prices; unanticipated operating results or production
      declines; changes in tax or environmental laws or royalty rates; increased
      debt
      levels or debt service requirements; inaccurate estimation of the Fund's oil
      and
      gas reserves volumes; limited, unfavourable or no access to capital markets;
      increased costs; the impact of competitors; and certain other risks detailed
      from time to time in the Fund's pubic disclosure documents (including, without
      limitation, those risks identified in this MD&A and in the Fund's annual
      information form).





The
      forward-looking
      information and statements contained in this MD&A speak only as of the date
      of this MD&A, and none of the Fund or its subsidiaries assumes any
      obligation to publicly update or revise them to reflect new events or
      circumstances, except as may be required pursuant to applicable
      laws.








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