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Returns & Value Focused

At Enerplus, we're focused on creating long-term value for our shareholders through a disciplined, returns-based capital allocation strategy and a commitment to safe, responsible operations.

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News Releases


Enerplus announces 2006 year-end results

February 22, 2007
    TSX:  ERF.un
    NYSE: ERF

    CALGARY, Feb. 22 /CNW/ - Enerplus is pleased to announce our 2006 year-
end results with highlights summarized as follows:


    -   Annual average production exceeded our guidance and grew to
        85,779 BOE/day primarily as a result of our internal capital program.
        Our exit rate volumes were in line with expectations at
        87,500 BOE/day.

    -   We executed the largest development capital program in our history
        spending $491.2 million, essentially in line with our target of
        $485.0 million.

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

    -   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 units outstanding.

    -   Cash distributions increased in 2006 by 23% to $614.3 million or
        11% per unit compared to 2005.

    -   Cash distributions to unitholders were maintained at $0.42 per unit
        throughout 2006 resulting in total distributions of $5.04 per unit.

    -   Our payout ratio averaged 71%.

    -   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.

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

    -   We replaced 82% of our production without the benefit of any
        significant acquisitions.

    -   Successful drilling efforts resulted in 361 net wells drilled with a
        success rate of over 99%.

    -   We acquired 3.7 MMBOE of proved plus probable reserves at an
        attractive cost of $14.04/BOE.

    -   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 including future development capital ("FDC"). Excluding
        FDC our proved plus probable FD&A costs were $20.45/BOE and
        $29.13/BOE on a proved basis. Our three-year proved plus probable
        FD&A costs were $14.90/BOE ($11.51/BOE excluding FDC).

    -   Operating costs averaged $8.02/BOE in 2006.

    -   G&A costs were $1.91/BOE, higher than our guidance of $1.85/BOE.

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

    -   Our future opportunity set increased significantly year-over-year to
        over $2 billion in attractive conventional capital projects
        (excluding oil sands).


    SUMMARY FINANCIAL AND OPERATING HIGHLIGHTS

    All amounts are stated in Canadian dollars unless otherwise specified. 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. All reserve figures are calculated based
upon company interest reserves using forecast prices and costs. See "Reserve
Reporting and Determination Methodologies" for additional information. 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. Readers are also urged to review the Management's
Discussion & Analysis (MD&A), Audited Financial Statements and forthcoming
Annual Information Form for more fulsome disclosure on our operations. These
reports can be found on our website at www.enerplus.com, our SEDAR profile at
www.sedar.com and as part of our Form 40-F that will be filed with the SEC and
available on www.sec.gov.

    FINANCIAL HIGHLIGHTS

    For the years ended December 31,                       2006         2005
    -------------------------------------------------------------------------
    Financial (000's)
      Net Income                                    $   544,782  $   432,041
      Cash Flow from Operating Activities               863,696      774,633
      Cash Distributions to Unitholders(1)              614,340      498,205
      Cash Withheld for Acquisitions and
       Capital Expenditures                             249,356      276,428
      Debt Outstanding (net of cash)                    679,650      649,825
      Development Capital Spending                      491,226      368,689
      Acquisitions                                       51,313      704,028
      Divestments                                        21,127       66,511

    Financial per Unit(2)
      Net Income                                    $      4.48  $      3.96
      Cash Flow from Operating Activities                  7.10         7.10
      Cash Distributions to Unitholders(1)                 5.05         4.57
      Cash Withheld for Acquisitions and
       Capital Expenditures                                2.05         2.53

      Payout Ratio(3)                                       71%          64%

    Selected Financial Results per BOE(4)
      Oil & Gas Sales(5)                            $     50.23  $     52.36
      Royalties                                           (9.36)      (10.21)
      Financial Contracts                                 (1.10)       (4.90)
      Operating Costs                                     (8.02)       (7.45)
      General and Administrative                          (1.71)       (1.28)
      Interest and Foreign Exchange                       (0.93)       (0.64)
      Taxes                                               (0.70)       (0.31)
      Restoration and Abandonment                         (0.37)       (0.27)
    -------------------------------------------------------------------------
    Cash Flow from Operating Activities before
     changes in non-cash working capital            $     28.04  $     27.30
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    Weighted Average Number of Trust Units
     Outstanding (thousands)                            121,588      109,083
    Debt/Trailing 12 Month Cash Flow Ratio                 0.8x         0.8x
    -------------------------------------------------------------------------


    OPERATING HIGHLIGHTS

    For the years ended December 31,                       2006         2005
    -------------------------------------------------------------------------

    Average Daily Production
      Natural gas (Mcf/day)                             270,972      274,336
      Crude oil (bbls/day)                               36,134       29,315
      NGLs (bbls/day)                                     4,483        4,689
    -------------------------------------------------------------------------
      Total (BOE/day) (6:1)                              85,779       79,727

      % Natural gas                                         53%          57%

    Average Selling Price(5)
      Natural gas (per Mcf)                         $      6.81  $      8.41
      Crude oil (per bbl)                                 61.80        55.93
      NGLs (per bbl)                                      50.90        47.33
      US$ exchange rate                                    0.88         0.83

    Net Wells drilled                                       361          393
    Success Rate                                            99%          99%

    Proved Reserves (MMBOE)(6)                            299.8        313.2
    Probable Reserves (MMBOE)(6)                          143.5        135.9
    -------------------------------------------------------------------------
    Total Proved plus Probable Reserves (MMBOE)(6)        443.3        449.1

    FD&A Cost per BOE, excluding Future
     Development Capital(7)                         $     20.45  $     13.98
    FD&A Cost per BOE, including Future
     Development Capital(7)                         $     23.19  $     17.18
    Recycle Ratio(7)                                       1.4x         1.7x

    Proved Reserve Life Index (years)                      10.1          9.9
    Proved plus Probable Reserve Life Index (years)        14.0         13.5
    -------------------------------------------------------------------------
         In some circumstances, presentation has been changed to minimize the
         use of non-GAAP measures.

    (1)  Calculated based on distributions paid or payable. 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.
    (2)  Based on annual weighted average trust units outstanding.
    (3)  Calculated as Cash Distributions to Unitholders divided by Cash Flow
         from Operating Activities.
    (4)  Non-cash amounts have been excluded.
    (5)  Net of oil and gas transportation costs, but before the effects of
         commodity derivative instruments.
    (6)  Reserve figures are calculated based upon company interest reserves
         using forecast prices and costs.
    (7)  Based upon proved plus probable company interest reserves.


                                                   TSX - ERF.un   NYSE - ERF
    -------------------------------------------------------------------------
    Trust Unit Trading Information                        ($CDN)        ($US)
      High                                                66.00        59.45
      Low                                                 43.86        38.50
      Close                                               50.68        43.61
      Volume (000's)                                     82,120       81,677
    -------------------------------------------------------------------------


    OPERATIONS REVIEW

    2006 Production

    In 2006, we were able to grow the production from our assets as a result
of strong base performance and the successful execution of the largest
development capital program in our history. Daily production averaged
85,800 BOE/day, a new high for Enerplus and slightly ahead of our guidance of
85,500 BOE/day. Strong base production performance from our U.S. and Canadian
operations and production additions from our capital program resulted in an
increase in our year-over-year exit rate from 85,000 in 2005 to 87,500 BOE/day
in 2006, demonstrating our ability to grow production through internal
development without the benefit of any significant acquisition activity.
    Approximately 50% of our average daily production volumes are attributed
to resource plays, with the Sleeping Giant project in Montana now our single
largest producing property. We continue to operate approximately 64% of our
daily production volumes.
    We expect 2007 average production to remain essentially flat at
85,000 BOE/day with a reduced capital program of $410 million. We expect to
exit 2007 with production of 86,000 BOE/day as a result of the timing of our
capital expenditures which are back-end loaded this coming year. These targets
are exclusive of any acquisition or divestment activity that may occur as a
normal part of our business during the course of 2007.

    2006 Capital Spending

    Development capital spending of $491 million during 2006 was in line with
our guidance of $485 million despite inflationary pressures. Through this
spending, we added approximately 21,400 BOE/day of initial production at an
attractive on-stream cost of $23,000/BOE/day which is significantly better
than our on-stream cost in 2005 and was slightly better than forecast. We
achieved these results due to the strength of our opportunity set and our
ability to allocate capital to our most attractive projects. Our capital high-
grading in 2006 included increasing our Bakken oil spending and deferring some
of our shallow gas and waterflood projects.

    Key attributes of our 2006 capital program include:

    -   We achieved better than expected capital efficiencies despite
        inflationary pressures. Inflation averaged approximately 15%,
        meaningfully higher than anticipated. As a result we chose to defer
        approximately 10% of our planned activity to manage our capital
        spending while maintaining attractive capital efficiencies.

    -   Approximately 57% of our capital was directed to oil development
        while 43% was directed to natural gas opportunities reflecting the
        strength of the oil markets and the attractiveness of our Bakken oil
        development in the U.S.

    -   64% of our capital spending was focused on resource plays which are
        marked by relatively predictable decline rates with low geologic
        risk.

    -   We also invested approximately $89 million (18% of our total capital)
        in longer-term opportunities in oil sands, land, seismic and higher
        risk drilling activities which did not add production or cash flow in
        the current year but positions us to add significant production and
        reserves over the next few years.

    -   Operated capital spending accounted for 73% of the total which is
        higher than last year due to higher spending on our U.S. Bakken oil
        projects.

                          2006 Initial              2006 Cost of        2007
                            Production         2006   Production   Estimated
                           Additions(*)     Capital    Additions     Capital
    Play type                 (BOE/day)  ($millions)  ($/BOE/day) ($millions)
    ---------------------------------------------- --------------------------
    Shallow Gas & CBM            3,200    $      94  $    29,400  $       43
    Waterflood                   1,600           66       41,250          65
    Bakken Oil                   7,800          117       15,000          70
    Oil Sands (SAGD/mine)            -           39          n/a          40
    Other Conventional
     Oil & Gas                   8,800          175       19,900         192
    -------------------------------------------------------------------------
    Total                       21,400    $     491  $    23,000  $      410
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    (*) 2006 production was not recorded for Joslyn as the operation has not
        reached commercial production levels. Initial production based on
        first month production rates.


    2007 Capital Spending

    We expect to reduce capital spending to $410 million for 2007 based on
our current commodity price outlook. Should commodity prices change and/or if
we experience better success, our capital budget could increase or decrease.
Our spending will continue to be focused on resource play development. We also
expect to spend $84 million (20%) on longer-term opportunities in oil sands,
land, seismic and higher risk drilling.
    The most significant reductions in our program will occur in our shallow
gas/CBM program and U.S. Bakken spending. The shallow gas/CBM program was
deferred given potential risks we see with near-term gas prices although with
continued gas price strength, these programs could be increased. Currently, we
plan to continue with a base level program concentrating on our most
profitable opportunities in this area as it is a core activity for us and
represents a significant percentage of our future opportunity. The reduction
in our U.S. Bakken spending reflects the completion of a majority of our
drilling program of two wells per section. We are currently testing the
benefits of a third well per section, exploring other zones in the area as
well as extending the Bakken play into North Dakota. With success in these
areas, we could increase our U.S. spending.

    2006 Drilling Activity

    In 2006, we participated in the drilling of 360.9 net wells,
significantly less than our original guidance of 550 net wells, while
maintaining our success rate of 99%. During the course of the year, we elected
to defer a portion of our drilling program as a result of industry
inflationary pressures and lower natural gas prices. We deferred the drilling
of approximately 140 net shallow gas and CBM wells and approximately 30 net
waterflood wells. Funds from these programs offset the inflationary pressures
on the remainder of the drilling program and ensured the execution of other
more profitable drilling programs such as those in our Bakken oil and other
conventional drilling programs. In total we drilled 275.1 net natural gas
wells and 85.8 net crude oil wells in 2006.

    Bakken Oil Development

    As our single largest producing property, the Sleeping Giant project
represents approximately 13% of our production and 9% of our proved plus
probable reserves. During 2006 we invested $117 million to drill 41 gross
wells (26.5 net) to add 7,800 BOE/day of incremental production at an
attractive on-stream cost of $15,000/BOE/day. As part of our 2006 activities,
we initiated an increased density drilling program by drilling 6 gross wells
(4 net) at 3 wells per section. Based upon results to date, 10 additional
increased density wells have been planned for 2007. Continued success may lead
to additional increased density wells.
    To date, we have drilled 56 development wells with a 100% success rate
and executed a successful re-fracture program resulting in production growth
from 8,700 BOE/day upon acquisition to over 11,500 BOE/day at year-end 2006.
These results are far better than we anticipated at the time of the
acquisitions.
    In 2007, we plan to invest $70 million to drill 26 gross (17 net) oil
wells and re-fracture stimulate 12 gross (8 net) wells. This year's
development activity will complete the second well per section program in the
primary Bakken field area and focus on identifying and proving up new
opportunities in the general area. We own 120,000 net acres of undeveloped
land in Montana and North Dakota, portions of which we plan to test in 2007.
The primary target on the undeveloped lands is the Bakken formation, however
the lands are also prospective for the Ratcliffe, Mission Canyon, Birdbear,
Duperow and Red River geological formations.

    Oil Sands

    Enerplus and Total E&P Canada ("Total"), the operator of the Joslyn
project, are continuing to review the lease development plans given the
flexibility which exists for both SAGD and mining operations. Although
meaningful progress was made in 2006, the complexities of determining the
optimal development plan have extended the expected timeline. An extensive
lease development plan is anticipated in 2007 and is not expected to impact
current SAGD operations or the startup timing of the initial phase of the
mine. The development plan will also provide an update of estimates relating
to the future development capital associated with the mine development.
    A summary of the expected production and timing for the various projects
on the Joslyn lease are included in the table below. Not all dates are
available given the uncertainty around the final full lease development plan.

    Joslyn Project Development

                     Project         Net       Future
                  Production  Production  Development                   Full
                Throughput(1) Throughput    Capital(2)     Start  Production
                   (bbls/day)  (bbls/day)  ($millions)      Up(3)         (4)
    -------------------------------------------------------------------------
    Phase I
     & II SAGD        10,000       1,500           31       2006        2008
    Phase III
     SAGD             15,000       2,250          284        TBD         TBD
    North Mine       100,000      15,000          TBD       2013        2014
    South Mine       100,000      15,000          TBD       2016        2017
    -------------------------------------------------------------------------
    (1)  All production estimates are those of the Operator.
    (2)  Future development capital for SAGD based on independent third party
         reserve report dated December 31, 2006. Future development capital
         for mining is currently under full review by the Operator as the
         project definition advances and new investment estimates are
         anticipated toward the end of 2007.
    (3)  Start up for SAGD refers to first steam. Start up for mining refers
         to initial extraction.
    (4)  Full production refers to full project production throughput.


    In addition to our Joslyn lease, Enerplus has assembled an internal oil
sands team with significant experience in SAGD development. We are actively
pursuing an operated SAGD project in which to deploy this team. Through our
joint venture with Laricina Energy Ltd., we have invested approximately
$3 million to acquire working interest in several land positions with SAGD
potential.

    Reserves

    Independent reserves evaluation of the Joslyn lease indicates total
proved reserves of 8.7 million BOE, and total proved plus probable reserves of
56.7 million BOE net to Enerplus in the SAGD area for Phases I - III.
Independent contingent resource estimates for the North Mine indicate a "best
estimate" of approximately 140 million BOE net to Enerplus, or over
900 million BOE gross. This is consistent with numbers filed in the North Mine
regulatory application by the Operator. In addition, third party assessments
estimate significant additional mining resources outside the North Mine area.
Please see our 2006 Annual Information Form for further information on the
resource disclosure including risks and uncertainties associated with our
resource estimates associated with the mining potential contained within the
Joslyn lease.
    If current development plans are modified and a decision is made to mine
some of the currently identified SAGD areas, existing SAGD Phase III probable
reserve bookings could be impacted. Although mining typically provides about
twice the recovery of the original bitumen in place versus SAGD projects,
there could be timing differences between reserves bookings associated with
the existing SAGD Phase III development plans versus possible expansion of
mine development plans. Although timing of the expected booking may extend
through 2007, depending on the progress made over the next year, we may be in
a position to book probable reserves associated with the North Mine at year-
end.

    2006 Capital Investment

    In regard to the Joslyn lease, spending in 2006 reached $36 million to
advance both the SAGD ($33 million) and the mining options ($3 million). In
addition, $3 million was spent to acquire lands in conjunction with Laricina,
resulting in a total oil sands investment of $39 million in 2006. This capital
included the drilling of close to 280 gross additional delineation wells over
both SAGD and mining areas and the 4.5 gross sections of land acquired in late
2005. Capital investment to progress the SAGD development included the
completion of central plant facilities, the commissioning and start-up of the
water treatment system, the initiation of steam injection into SAGD well
pairs, and the completion of a 40 kilometre pipeline from Joslyn to the
Athabasca Terminal. Total continues to expect Phase II to reach peak
production of 10,000 bbls/day gross (1,500 bbls/day net to Enerplus) in 2008,
however due to reduced operating pressures, this may require additional wells
and capital in 2007 and 2008. We currently do not have any production volumes
associated with this project included in our 2007 production estimates as
commercial volumes are not expected until 2008. Investment on the mining side
supported the application for regulatory approval of the North Mine,
representing 100,000 bbls/day of potential gross bitumen production
(15,000 bbls/day net to Enerplus).

    2007 Oil Sands Capital Spending Outlook

    Total capital spending on oil sands is expected to increase to
approximately $40 million including:

    -   Joslyn SAGD development of $21 million, which includes the continued
        start-up and ramp-up of Phase II well pairs, and the possible
        addition of 10 new well pairs late in the year. The regulatory
        approval process continues for SAGD Phase III with approvals
        expected in the first quarter of 2007 assuming no change in the base
        development plan. Currently Phase III represents a 15,000 bbl/day
        expansion of the existing facilities to a potential of
        25,000 bbls/day of gross SAGD production (3,750 bbls/day net
        to Enerplus).

    -   Mining investment of $13 million to advance the regulatory approval
        process and engineering, and to further delineate the mine.

    -   Investment of $6 million to further delineate the new Laricina lands
        in the first quarter of 2007.

    These investments will enhance the value of our portfolio of oil sands
assets. Our capital spending may increase further should we identify and
execute on other attractive oil sands opportunities.

    Crude Oil Waterfloods

    Crude oil waterfloods are a significant part of the Enerplus portfolio
representing 20% of our production and 24% of our proved plus probable
reserves. During 2006 we invested approximately $66 million on waterflood
development including drilling 40 gross (29.7 net) wells. Pembina and Joarcam
were our most active waterflood development areas in 2006. During 2007, we
expect to maintain our investment activity in this area at approximately $65
million. This will include drilling 76 gross wells (41 net). Key development
areas include Pembina, Joarcam, Virden as well as the Medicine Hat Glauconitic
"C" East Unit. Although capital efficiency measures based on initial
waterflood production may be higher, the low decline rates and long life
nature of these projects provide attractive full-cycle returns.

    Shallow Natural Gas and Coalbed Methane

    Shallow gas and coalbed methane represent 22% of our reserves, with an
attractive reserve life index of 17.2 years. Production volumes from these two
resource plays represent 16% of our total production, with shallow gas
representing the majority in this category. During 2006, we invested
$94 million on shallow gas/CBM development, drilling 430 gross (249.5 net)
wells and adding 3,200 BOE/day of incremental production at an average on-
stream cost of $29,400/BOE/day. Key areas of shallow gas development include
Hanna, Bantry and Shackleton, while CBM development efforts were focused at
Bashaw, Joffre and Trochu. Currently, our inventory of shallow gas/CBM future
drilling locations represents approximately six years of development at
historical investment levels. However, for 2007 we have chosen to high grade
our development program to $43 million, focusing on our most profitable
programs given potential risks in near-term gas prices. Should gas price
strength continue, the size of this program could increase.

    Other Conventional Oil and Gas

    We also have a diversified portfolio of other conventional opportunities
in western Canada. These properties are diversified by commodity (67% natural
gas, 33% liquids) and are mixed between operated (46%) and non-operated (54%).
Conventional oil and gas represents approximately 51% of our production and
32% of our proved plus probable reserves. In 2006, we invested approximately
$175 million in other conventional oil and gas development activities
including the drilling of 275 gross wells (53.5 net). In 2007, we plan to
invest $192 million in development activities at other conventional oil and
gas properties including drilling approximately 200 gross wells (70 net).
Actual capital may vary depending on the activity levels from industry
partners on non-operated properties in which we participate.

    FUTURE POTENTIAL

    Enerplus has focused on building a large, diversified portfolio of
economic, conventional and non-conventional capital projects that will support
our operations in the years ahead through the addition of production and
reserves. We currently have a conventional opportunity set of approximately $2
billion of capital projects representing approximately 2,500 net wells. The
non-conventional opportunities are estimated at approximately $1 billion of
capital projects associated with oil sands excluding any investments relating
to an upgrader solution. This represents about five years of conventional
future development potential at current capital spending levels assuming no
new acquisitions, land deals, or new opportunity identification on our
existing properties.
    Our opportunity set includes significant potential across our entire
asset base and capital projects which are both technically and economically
viable at todayès commodity prices:

    -   Weighted 60% to natural gas and 40% to oil

    -   Resource plays comprise over 50% of the total

    -   Includes approximately $500 million of opportunity included in our
        third party reserve engineering reports

    -   $1 billion of ùbaseâ projects which we project to have a greater
        than 80% chance of technical success

    -   Approximately $500 million of risk-adjusted opportunities that have
        less than an 80% chance of success

    We have excluded those projects from our opportunity set that are early
stage ideas with greater technical/economic uncertainty.

    ACQUISITIONS & DIVESTMENTS

    2006 was a year our disciplined approach to acquisitions resulted in
limited transactions despite actively pursuing numerous opportunities. As a
result, we preserved our balance sheet and avoided the high cost acquisitions
within Canada driven by an aggressive energy trust sector. Within the U.S. we
tempered our activities as we built our U.S. operating group and executed an
expanded internal development program which achieved strong internal
production and reserve gains.
    Given recent weakness in commodity markets and capital market
uncertainty, we see an increasing number of attractive acquisitions at
potentially more favourable pricing. This increased opportunity set comes at a
time when our equity value is relatively stronger than the general trust
sector, our balance sheet is strong and our U.S. execution capability is now
in place.
    During the year, through a series of small transactions, we increased our
interests in core areas, notably at Sleeping Giant in Montana and at Gleneath
in Saskatchewan. We acquired minor non-operated interests in a large block of
land at Copton within the greater Deep Basin which has significant upside from
relatively low risk drilling for deep, sweet natural gas. These properties
were acquired at an attractive cost per BOE of $14 and a higher cost on a
flowing barrel metric given the significant upside we see within the
properties.
    In early 2006, we sold a 1% working interest in our Joslyn oil sands
lease in exchange for an equity stake in Laricina Energy Ltd. a private oil
sands focused company. Given the low selling price of these reserves and the
modest number of acquired reserves for the year, the resulting net acquisition
metrics appear unattractive. However, the chart below offers more comparable
per BOE and per flowing BOE metrics by excluding the Joslyn sale.

    2006 Acquisition & Divestment Summary

                                  Proved                 Cost of
                                    plus             Proved plus
                       Cost/    Probable                Probable
                  Proceeds(*)   Reserves  Production    Reserves    Cost per
                 ($ millions)      (MBOE)   (BOE/day)     ($/BOE)  Daily BOE
    -------------------------------------------------------------------------
    Acquired       $    51.3       3,654         655   $   14.04   $  78,321
    Divested(xx)   $    (1.4)        (63)        (26)  $  (22.22)  $  53,846
    -------------------------------------------------------------------------
    Net excluding
     Joslyn        $    49.9       3,591         629   $   13.90   $  79,332
    Joslyn
     Divestment    $   (19.7)     (3,329)        n/a   $   (5.91)        n/a
    -------------------------------------------------------------------------
    Net including
     Joslyn        $    30.2         262         629   $  115.27   $  48,013
    -------------------------------------------------------------------------
    (*)  After adjustments for working capital and excluding future
         development capital.
    (xx) Excludes sale of reserves of Joslyn for equity stake in Laricina.


    Acquisition of Gross Overriding Royalty Interests

    On January 31, 2007, Enerplus acquired various gross overriding royalty
("GORR") interests in the state of Wyoming for total consideration of
US$52 million (CDN$60 million). This acquisition represents a modest addition
to our assets in the United States and establishes a new area with significant
gas development potential.
    The assets produce natural gas from the EnCana Corporation operated Jonah
gas field in Wyoming, which is one of the largest gas fields in the U.S. with
an estimated original gas in place of 14 trillion cubic feet. We have acquired
approximately 540 BOE/day of daily production and approximately
2.2 million BOE of proved reserves and 2.9 million BOE of proved plus probable
reserves. This represents a GORR of about 0.5% on about 650 producing gas
wells in the Jonah field. The proved plus probable reserve life index of the
assets is 15.9 years, calculated using independent third party engineering
reserve estimates and management's estimate of current production. We believe
the field has a significant number of additional infill drilling locations
that will provide growth potential for the future. Enerplus will not be
required to expend any future development capital on the assets. We expect the
net operating cash flow per BOE, net of all applicable U.S. taxes, to be
significantly higher than that of our existing production due to the nature of
the GORR which is not subject to deductions for operating costs and royalties.

    RESERVES

    Attractive reserve additions from our U.S. properties, oil sands and
conventional Canadian operations were partially offset by unexpected capital
inflation and negative revisions (mainly in the probable category) in our
Canadian conventional areas. Enerplus achieved overall proved plus probable
finding, development and acquisition costs including future development
capital of $23.19/BOE in 2006 ($20.45/BOE excluding FDC) and a three-year
average FD&A cost of $14.90/BOE ($11.51/BOE excluding FDC).

    Other key points in our reserve assessment include:

    -   Reserve life index increased to 14 years in line with our historical
        performance.

    -   We replaced 82% of production without the benefit of any significant
        acquisitions. Over the last five years, we have averaged almost 200%
        reserve replacement inclusive of acquisition and divestment activity.

    -   Our U.S. operations added 7.3 million BOE at a one-year proved plus
        probable F&D cost of $13.78/BOE including FDC reflecting a 20%
        increase in reserves at December 31, 2005 as a result of our strong
        operational and development performance in the U.S.

    -   6.9 million BOE were added to our oil sands reserves at a one-year
        proved plus probable F&D cost of $10.54/BOE ($5.67/BOE excluding
        FDC) reflecting another successful year of core hole drilling and
        analysis.

    -   No changes were made to the allocation of reserves associated with
        the SAGD portion of the Joslyn lease versus the mining portion.
        Total and Enerplus are in discussions on a potential change to the
        lease development plan which could impact the reserve allocation
        between the mine and SAGD portions of the lease and the timing of
        reserve bookings.

    -   There are no proved or probable mining reserves included in our year-
        end reserve summary. The current North Mine project continues to
        progress and there is the potential to book probable reserves
        associated with this project at year-end 2007.

    -   Canadian conventional development added over 19 million BOE,
        excluding negative revisions, at a one-year proved plus probable F&D
        cost of $20.63/BOE ($17.17/BOE without FDC). This reflects the
        strong conventional drilling results we achieved in Canada which
        were partially offset by the negative revisions tied to existing
        Canadian operations.

    -   Proved and probable negative revisions of 7.5 million BOE were
        predominantly from the "probable" reserves category which has less
        certainty than "proved" reserves. These revisions represent less
        than 2% of our total year-end reserves and were mainly due to
        performance and economic factors in a few of our older Canadian
        conventional properties.

    -   No changes to the after-tax calculations have been included for our
        Canadian assets in connection with the proposed changes on
        taxability for trusts in the Canadian market. Should the proposed
        legislation be enacted, Enerplus would provide an updated analysis
        which would include the effect of any enacted tax legislation.

    -   Acquisition and divestment activity resulted in no significant
        change to our reserves. Minor acquisitions were offset by the sale
        of a 1% working interest in our Joslyn lease.


    Reserve Reporting and Determination Methodologies

    All reports, including our U.S. reserves, were evaluated using Canadian
NI 51-101 rules. Three external, independent third party engineering firms
were used to evaluate and review our reserves this year. Sproule Associates
Limited ("Sproule"), our historical independent engineering evaluators,
evaluated our Canadian conventional reserves. GLJ Petroleum Consultants Ltd.
("GLJ") evaluated the Joslyn SAGD bitumen reserves as they have previously
performed such evaluations for the operator of the Joslyn project. DeGolyer
and MacNaughton ("D&M") of Dallas, Texas, evaluated the reserves attributed to
our assets in the United States. Sproule evaluated 90% of the total proved
plus probable value (discounted at 10%) of our Canadian conventional year-end
reserves and has reviewed the remainder of the reserves internally evaluated
by Enerplus. Both GLJ and D&M evaluated 100% of the reserves in their
respective areas. Both GLJ and D&M utilized Sproule's forecast price and cost
assumptions as of December 31, 2006 in their evaluations to maintain
consistency among our reserve reporting.
    The following tables report company interest reserves that include gross
working interest reserves plus owned royalty interest reserves using forecast
prices. "Company interest" reserves are not a measure defined in NI 51-101
adopted by the Canadian securities regulators and does not have a standardized
meaning under NI 51-101. Accordingly, our company interest reserves may not be
comparable to reserves presented or disclosed by other issuers. Our reserves
statement, which includes complete disclosure of our oil and gas reserves and
other oil and gas information in accordance with NI 51-101 is contained within
our Annual Information Form which will be available on our website at
www.enerplus.com and on our SEDAR profile at www.sedar.com. Additionally, the
Annual Information Form is part of our Form 40-F that will be filed with the
SEC and available on www.sec.gov.
    Probable reserves are evaluated and categorized by our third party
engineering firms or our own internal evaluators under the review of the third
party engineering firm. Care should be used when comparing U.S. and Canadian
style reserves and production reporting between companies. Under U.S.
reporting, reserve estimates are calculated using prices and costs held
constant at amounts in effect at the date of the reserve report and typically
only include net proved reserves. Additionally, proved reserve standards in
the U.S. may not be comparable to the Canadian standards. Generally, Canadian
standards for reporting proved reserves may be more conservative than U.S.
standards.
    All evaluations of future net production revenues set forth in the tables
are stated after the provision for income taxes and exclude abandonment costs
on wells and facilities where reserves are not assigned or associated general
and administrative costs. These schedules have been prepared on the basis that
Enerplus will not pay cash income taxes in Canada in the future due to
Enerplus' current structure as an income trust and Canadian tax laws currently
in effect. Under our current mutual fund structure and existing tax
legislation in Canada, annual taxable income is transferred from our operating
entities to the Fund through interest, royalty and other payments. We, in
turn, make distributions to our unitholders and therefore currently do not
incur any Canadian income tax. As a result, after tax future net revenues from
Canadian oil and gas reserves are equal to before tax future net revenues from
Canadian oil and gas reserves. Enerplus' U.S. operations are subject to cash
income taxes, and as a result Enerplus' U.S. reserves are shown net of the
effect of such taxes that we estimate would be payable after taking into
account inter-company debt in our structure. The Canadian federal government
has announced a proposal designed to effectively tax income trusts such as
Enerplus at the same level as Canadian corporations, effective for the 2011
tax year. Such proposal has not yet been approved or put in force and it is
uncertain as what form, if any, changes in Canadian income tax laws will take
as a result of such proposal. Any changes in Canadian income tax laws that may
result from such proposal could adversely affect the estimated future net
revenues associated with Enerplus' oil and gas reserves. For additional
information, investors should refer to disclosure that will be contained in
Enerplus' Annual Information Form.
    The net estimated present value of all future net revenues at
December 31, 2006 was based upon crude oil and natural gas pricing assumptions
prepared by Sproule as of December 31, 2006. These prices were applied to the
reserves evaluated by Sproule, GLJ and D&M. The base reference prices and
exchange rates used by Sproule are detailed below:

    Sproule December 31, 2006 - Forecast Price Assumptions

                                           Differ-
                                           ential
                                          Between
                                         Hardisty
                                            Heavy            Natural
                               Hardisty       And    Henry    Gas 30
                         Light Heavy 12 Bitumen(2)     Hub  day spot
                 WTI   crude(1)  degree      (Oil    Price   at AECO Exchange
           crude oil  Edmonton      API    Sands)     US$/     CDN$/     Rate
             US$/bbl  CDN$/bbl CDN$/bbl  CDN$/bbl    MMbtu     MMbtu CDN$/US$
    -------------------------------------------------------------------------
    2007     $ 65.73   $ 74.10   $ 42.98  $  8.88  $  7.85  $  7.72  $  0.87
    2008       68.82     77.62     45.02    11.35     8.39     8.59     0.87
    2009       62.42     70.25     40.74    12.83     7.65     7.74     0.87
    2010       58.37     65.56     38.03    12.19     7.48     7.55     0.87
    2011       55.20     61.90     35.90    11.66     7.63     7.72     0.87
    Thereafter  2.0%      2.0%      2.0%      (xx)     (xx)    2.0%     0.87
    -------------------------------------------------------------------------
    (1)  Edmonton refinery postings for 40 degree API, 0.4% sulphur content
         crude.
    (2)  The bitumen price is derived by GLJ from Sproule's forecasts of
         various stream prices.
    (xx) Escalation varies after 2011.


    Reserves Summary

    The following table sets out our company interest volumes by production
type and reserve category under a forecast price scenario. Under different
price scenarios, these reserves could vary as a change in price can affect the
economic limit and reserves associated with a property.


    2006 Reserve Summary - Company Interest Volumes (Forecast Prices)

                                         OIL AND GAS RESERVES
    -------------------------------------------------------------------------
                              Light &        Heavy      Bitumen
                           Medium Oil          Oil   (Oil Sands)   Total Oil
                               (Mbbls)      (Mbbls)      (Mbbls)      (Mbbls)
    -------------------------------------------------------------------------
    Proved developed
     producing
      Canada                   66,458       28,932        2,479       97,869
      United States            21,933            -            -       21,933
    -------------------------------------------------------------------------
      Total                    88,391       28,932        2,479      119,802
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    Proved developed
     non-producing
      Canada                      537            -            -          537
      United States               871            -            -          871
    -------------------------------------------------------------------------
      Total                     1,408            -            -        1,408
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    Proved undeveloped
      Canada                    3,509        2,221        6,251       11,981
      United States               587            -            -          587
    -------------------------------------------------------------------------
      Total                     4,096        2,221        6,251       12,568
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    Total Proved
      Canada                   70,504       31,153        8,730      110,387
      United States            23,391            -            -       23,391
    -------------------------------------------------------------------------
      Total                    93,895       31,153        8,730      133,778
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    Probable
      Canada                   16,872        8,912       47,998       73,782
      United States             8,637            -            -        8,637
    -------------------------------------------------------------------------
      Total                    25,509        8,912       47,998       82,419
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    Proved plus Probable
      Canada                   87,376       40,065       56,728      184,169
      United States            32,028            -            -       32,028
    -------------------------------------------------------------------------
      Total                   119,404       40,065       56,728      216,197
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------


                                   OIL AND GAS RESERVES
    ------------------------------------------------------------
                              Natural
                                  Gas      Natural
                              Liquids          Gas        Total
                               (Mbbls)       (MMcf)       (MBOE)
    ------------------------------------------------------------
    Proved developed
     producing
      Canada                   11,434      727,596      230,569
      United States                 -       13,626       24,204
    ------------------------------------------------------------
      Total                    11,434      741,222      254,773
    ------------------------------------------------------------
    ------------------------------------------------------------

    Proved developed
     non-producing
      Canada                      621       17,317        4,044
      United States                 -          724          992
    ------------------------------------------------------------
      Total                       621       18,041        5,036
    ------------------------------------------------------------
    ------------------------------------------------------------

    Proved undeveloped
      Canada                      635      160,348       39,341
      United States                 -          450          662
    ------------------------------------------------------------
      Total                       635      160,798       40,003
    ------------------------------------------------------------
    ------------------------------------------------------------

    Total Proved
      Canada                   12,690      905,261      273,954
      United States                 -       14,800       25,858
    ------------------------------------------------------------
      Total                    12,690      920,061      299,812
    ------------------------------------------------------------
    ------------------------------------------------------------
    Probable
      Canada                    3,777      306,804      128,693
      United States                 -       37,221       14,840
    ------------------------------------------------------------
      Total                     3,777      344,025      143,533
    ------------------------------------------------------------
    ------------------------------------------------------------
    Proved plus Probable
      Canada                   16,467    1,212,065      402,647
      United States                 -       52,021       40,698
    ------------------------------------------------------------
      Total                    16,467    1,264,086      443,345
    ------------------------------------------------------------
    ------------------------------------------------------------


    Proved Reserve Reconciliation

    Proved Reserves - Company Interest Volumes (Forecast Prices)

                              Light &        Heavy      Bitumen
                           Medium Oil          Oil   (Oil Sands)   Total Oil
    CANADA                     (Mbbls)      (Mbbls)      (Mbbls)      (Mbbls)
    -------------------------------------------------------------------------
    Proved Reserves at
     Dec. 31, 2005             73,249       32,901        9,453      115,603
    -------------------------------------------------------------------------
    Acquisitions                  984            -            -          984
    Divestments                   (30)           -         (591)        (621)
    Discoveries                     -           48            -           48
    Extensions                  1,648           11            -        1,659
    Technical Revisions        (2,191)       1,058         (132)      (1,265)
    Economic Factors              226           58            -          284
    Improved Recovery           2,806          327            -        3,133
    Production                 (6,188)      (3,250)           -       (9,438)
    -------------------------------------------------------------------------
    Proved Reserves at
     Dec. 31, 2006             70,504       31,153        8,730      110,387
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------


                              Natural
                                  Gas      Natural
                              Liquids          Gas        Total
    CANADA                     (Mbbls)       (MMcf)       (MBOE)
    ------------------------------------------------------------
    Proved Reserves at
     Dec. 31, 2005             13,084      952,624      287,458
    ------------------------------------------------------------
    Acquisitions                  160        5,518        2,063
    Divestments                    (1)        (145)        (647)
    Discoveries                    27        4,095          757
    Extensions                    671       26,180        6,693
    Technical Revisions           372       (4,956)      (1,717)
    Economic Factors              (17)      (5,304)        (616)
    Improved Recovery              30       23,981        7,159
    Production                 (1,636)     (96,732)     (27,196)
    ------------------------------------------------------------
    Proved Reserves at
     Dec. 31, 2006             12,690      905,261      273,954
    ------------------------------------------------------------
    ------------------------------------------------------------



                              Light &        Heavy      Bitumen
                           Medium Oil          Oil   (Oil Sands)   Total Oil
    UNITED STATES              (Mbbls)      (Mbbls)      (Mbbls)      (Mbbls)
    -------------------------------------------------------------------------
    Proved Reserves at
     Dec. 31, 2005             23,595            -            -       23,595
    -------------------------------------------------------------------------
    Acquisitions                  401            -            -          401
    Divestments                     -            -            -            -
    Discoveries                     -            -            -            -
    Extensions                    440            -            -          440
    Technical Revisions           584            -            -          584
    Economic Factors                -            -            -            -
    Improved Recovery           2,122            -            -        2,122
    Production                 (3,751)           -            -       (3,751)
    -------------------------------------------------------------------------
    Proved Reserves at
     Dec. 31, 2006             23,391            -            -       23,391
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------


                              Natural
                                  Gas      Natural
                              Liquids          Gas        Total
    UNITED STATES              (Mbbls)       (MMcf)       (MBOE)
    ------------------------------------------------------------
    Proved Reserves at
     Dec. 31, 2005                  -       13,152       25,787
    ------------------------------------------------------------
    Acquisitions                    -          341          458
    Divestments                     -            -            -
    Discoveries                     -            -            -
    Extensions                      -          384          504
    Technical Revisions             -        1,732          872
    Economic Factors                -            -            -
    Improved Recovery               -        1,364        2,350
    Production                      -       (2,173)      (4,113)
    ------------------------------------------------------------
    Proved Reserves at
     Dec. 31, 2006                  -       14,800       25,858
    ------------------------------------------------------------
    ------------------------------------------------------------



                              Light &        Heavy      Bitumen
                           Medium Oil          Oil   (Oil Sands)   Total Oil
    TOTAL ENERPLUS             (Mbbls)      (Mbbls)      (Mbbls)      (Mbbls)
    -------------------------------------------------------------------------
    Proved Reserves at
     Dec. 31, 2005             96,844       32,901        9,453      139,198
    -------------------------------------------------------------------------
    Acquisitions                1,385            -            -        1,385
    Divestments                   (30)           -         (591)        (621)
    Discoveries                     -           48            -           48
    Extensions                  2,088           11            -        2,099
    Technical Revisions        (1,607)       1,058         (132)        (681)
    Economic Factors              226           58            -          284
    Improved Recovery           4,928          327            -        5,255
    Production                 (9,939)      (3,250)           -      (13,189)
    -------------------------------------------------------------------------
    Proved Reserves at
     Dec. 31, 2006             93,895       31,153        8,730      133,778
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------


                              Natural
                                  Gas      Natural
                              Liquids          Gas        Total
    TOTAL ENERPLUS             (Mbbls)       (MMcf)       (MBOE)
    ------------------------------------------------------------
    Proved Reserves at
     Dec. 31, 2005             13,084      965,776      313,245
    ------------------------------------------------------------
    Acquisitions                  160        5,859        2,521
    Divestments                    (1)        (145)        (647)
    Discoveries                    27        4,095          757
    Extensions                    671       26,564        7,197
    Technical Revisions           372       (3,224)        (845)
    Economic Factors              (17)      (5,304)        (616)
    Improved Recovery              30       25,345        9,509
    Production                 (1,636)     (98,905)     (31,309)
    ------------------------------------------------------------
    Proved Reserves at
     Dec. 31, 2006             12,690      920,061      299,812
    ------------------------------------------------------------
    ------------------------------------------------------------


    Probable Reserve Reconciliation

    Probable Reserves - Company Interest Volumes (Forecast Prices)

                              Light &        Heavy      Bitumen
                           Medium Oil          Oil   (Oil Sands)   Total Oil
    CANADA                     (Mbbls)      (Mbbls)      (Mbbls)      (Mbbls)
    -------------------------------------------------------------------------
    Probable Reserves at
     Dec. 31, 2005             17,498        8,495       43,700       69,693
    -------------------------------------------------------------------------
    Acquisitions                  451            -            -          451
    Divestments                    (5)           -       (2,738)      (2,743)
    Discoveries                     1           18            -           19
    Extensions                    407            9        6,935        7,351
    Technical Revisions        (2,414)         337          101       (1,976)
    Economic Factors               47           10            -           57
    Improved Recovery             887           43            -          930
    Production                      -            -            -            -
    -------------------------------------------------------------------------
    Probable Reserves at
     Dec. 31, 2006             16,872        8,912       47,998       73,782
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------


                              Natural
                                  Gas      Natural
                              Liquids          Gas        Total
    CANADA                     (Mbbls)       (MMcf)       (MBOE)
    ------------------------------------------------------------
    Probable Reserves at
     Dec. 31, 2005              3,539      309,572      124,827
    ------------------------------------------------------------
    Acquisitions                   72        2,219          893
    Divestments                    (1)         (13)      (2,745)
    Discoveries                     8          845          168
    Extensions                    217        9,593        9,167
    Technical Revisions           (62)     (22,147)      (5,730)
    Economic Factors               (5)      (1,642)        (223)
    Improved Recovery               9        8,377        2,336
    Production                      -            -            -
    ------------------------------------------------------------
    Probable Reserves at
     Dec. 31, 2006              3,777      306,804      128,693
    ------------------------------------------------------------
    ------------------------------------------------------------



                              Light &        Heavy      Bitumen
                           Medium Oil          Oil   (Oil Sands)   Total Oil
    UNITED STATES              (Mbbls)      (Mbbls)      (Mbbls)      (Mbbls)
    -------------------------------------------------------------------------
    Probable Reserves at
     Dec. 31, 2005              5,574            -            -        5,574
    -------------------------------------------------------------------------
    Acquisitions                  202            -            -          202
    Divestments                     -            -            -            -
    Discoveries                     -            -            -            -
    Extensions                    982            -            -          982
    Technical Revisions            37            -            -           37
    Economic Factors                -            -            -            -
    Improved Recovery           1,842            -            -        1,842
    Production                      -            -            -            -
    -------------------------------------------------------------------------
    Probable Reserves at
     Dec. 31, 2006              8,637            -            -        8,637
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------


                              Natural
                                  Gas      Natural
                              Liquids          Gas        Total
    UNITED STATES              (Mbbls)       (MMcf)       (MBOE)
    ------------------------------------------------------------
    Probable Reserves at
     Dec. 31, 2005                  -       32,946       11,065
    ------------------------------------------------------------
    Acquisitions                    -          230          240
    Divestments                     -            -            -
    Discoveries                     -            -            -
    Extensions                      -        1,095        1,164
    Technical Revisions             -       (1,002)        (129)
    Economic Factors                -            -            -
    Improved Recovery               -        3,952        2,500
    Production                      -            -            -
    ------------------------------------------------------------
    Probable Reserves at
     Dec. 31, 2006                  -       37,221       14,840
    ------------------------------------------------------------
    ------------------------------------------------------------



                              Light &        Heavy      Bitumen
                           Medium Oil          Oil   (Oil Sands)   Total Oil
    TOTAL ENERPLUS             (Mbbls)      (Mbbls)      (Mbbls)      (Mbbls)
    -------------------------------------------------------------------------
    Probable Reserves at
     Dec. 31, 2005             23,072        8,495       43,700       75,267
    -------------------------------------------------------------------------
    Acquisitions                  653            -            -          653
    Divestments                    (5)           -       (2,738)      (2,743)
    Discoveries                     1           18            -           19
    Extensions                  1,389            9        6,935        8,333
    Technical Revisions        (2,377)         337          101       (1,939)
    Economic Factors               47           10            -           57
    Improved Recovery           2,729           43            -        2,772
    Production                      -            -            -            -
    -------------------------------------------------------------------------
    Probable Reserves at
     Dec. 31, 2006             25,509        8,912       47,998       82,419
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------


                              Natural
                                  Gas      Natural
                              Liquids          Gas        Total
    TOTAL ENERPLUS             (Mbbls)       (MMcf)       (MBOE)
    ------------------------------------------------------------
    Probable Reserves at
     Dec. 31, 2005              3,539      342,518      135,892
    ------------------------------------------------------------
    Acquisitions                   72        2,449        1,133
    Divestments                    (1)         (13)      (2,745)
    Discoveries                     8          845          168
    Extensions                    217       10,688       10,331
    Technical Revisions           (62)     (23,149)      (5,859)
    Economic Factors               (5)      (1,642)        (223)
    Improved Recovery               9       12,329        4,836
    Production                      -            -            -
    ------------------------------------------------------------
    Probable Reserves at
     Dec. 31, 2006              3,777      344,025      143,533
    ------------------------------------------------------------
    ------------------------------------------------------------


    Proved Plus Probable Reserve Reconciliation

    Proved Plus Probable Reserves - Company Interest Volumes (Forecast
    Prices)

                              Light &        Heavy      Bitumen
                           Medium Oil          Oil   (Oil Sands)   Total Oil
    CANADA                     (Mbbls)      (Mbbls)      (Mbbls)      (Mbbls)
    -------------------------------------------------------------------------
    Proved Plus Probable
     Reserves at
     Dec. 31, 2005             90,747       41,396       53,153      185,296
    -------------------------------------------------------------------------
    Acquisitions                1,435            -            -        1,435
    Divestments                   (35)           -       (3,329)      (3,364)
    Discoveries                     1           66            -           67
    Extensions                  2,055           20        6,935        9,010
    Technical Revisions        (4,605)       1,395          (31)      (3,241)
    Economic Factors              273           68            -          341
    Improved Recovery           3,693          370            -        4,063
    Production                 (6,188)      (3,250)           -       (9,438)
    -------------------------------------------------------------------------
    Proved Plus Probable
     Reserves at
     Dec. 31, 2006             87,376       40,065       56,728      184,169
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------


                              Natural
                                  Gas      Natural
                              Liquids          Gas        Total
    CANADA                     (Mbbls)       (MMcf)       (MBOE)
    ------------------------------------------------------------
    Proved Plus Probable
     Reserves at
     Dec. 31, 2005             16,623    1,262,196      412,285
    ------------------------------------------------------------
    Acquisitions                  232        7,737        2,956
    Divestments                    (2)        (158)      (3,392)
    Discoveries                    35        4,940          925
    Extensions                    888       35,773       15,860
    Technical Revisions           310      (27,103)      (7,447)
    Economic Factors              (22)      (6,946)        (839)
    Improved Recovery              39       32,358        9,495
    Production                 (1,636)     (96,732)     (27,196)
    ------------------------------------------------------------
    Proved Plus Probable
     Reserves at
     Dec. 31, 2006             16,467    1,212,065      402,647
    ------------------------------------------------------------
    ------------------------------------------------------------



                              Light &        Heavy      Bitumen
                           Medium Oil          Oil   (Oil Sands)   Total Oil
    UNITED STATES              (Mbbls)      (Mbbls)      (Mbbls)      (Mbbls)
    -------------------------------------------------------------------------
    Proved Plus Probable
     Reserves
     at Dec. 31, 2005          29,169            -            -       29,169
    -------------------------------------------------------------------------
    Acquisitions                  603            -            -          603
    Divestments                     -            -            -            -
    Discoveries                     -            -            -            -
    Extensions                  1,422            -            -        1,422
    Technical Revisions           621            -            -          621
    Economic Factors                -            -            -            -
    Improved Recovery           3,964            -            -        3,964
    Production                 (3,751)           -            -       (3,751)
    -------------------------------------------------------------------------
    Proved Plus Probable
     Reserves at
     Dec. 31, 2006             32,028            -            -       32,028
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------


                              Natural
                                  Gas      Natural
                              Liquids          Gas        Total
    UNITED STATES              (Mbbls)       (MMcf)       (MBOE)
    ------------------------------------------------------------
    Proved Plus Probable
     Reserves
     at Dec. 31, 2005               -       46,098       36,852
    ------------------------------------- -----------------------
    Acquisitions                    -          571          698
    Divestments                     -            -            -
    Discoveries                     -            -            -
    Extensions                      -        1,479        1,668
    Technical Revisions             -          730          743
    Economic Factors                -            -            -
    Improved Recovery               -        5,316        4,850
    Production                      -       (2,173)      (4,113)
    ------------------------------------------------------------
    Proved Plus Probable
     Reserves at
     Dec. 31, 2006                  -       52,021       40,698
    ------------------------------------------------------------
    ------------------------------------------------------------



                              Light &        Heavy      Bitumen
                           Medium Oil          Oil   (Oil Sands)   Total Oil
    TOTAL ENERPLUS             (Mbbls)      (Mbbls)      (Mbbls)      (Mbbls)
    -------------------------------------------------------------------------
    Proved Plus Probable
     Reserves at
     Dec. 31, 2005            119,916       41,396       53,153      214,465
    -------------------------------------------------------------------------
    Acquisitions                2,038            -            -        2,038
    Divestments                   (35)           -       (3,329)      (3,364)
    Discoveries                     1           66            -           67
    Extensions                  3,477           20        6,935       10,432
    Technical Revisions        (3,984)       1,395          (31)      (2,620)
    Economic Factors              273           68            -          341
    Improved Recovery           7,657          370            -        8,027
    Production                 (9,939)      (3,250)           -      (13,189)
    -------------------------------------------------------------------------
    Proved Plus Probable
     Reserves at
     Dec. 31, 2006            119,404       40,065       56,728      216,197
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------


                              Natural
                                  Gas      Natural
                              Liquids          Gas        Total
    TOTAL ENERPLUS             (Mbbls)       (MMcf)       (MBOE)
    ------------------------------------------------------------
    Proved Plus Probable
     Reserves at
     Dec. 31, 2005             16,623    1,308,294      449,137
    ------------------------------------------------------------
    Acquisitions                  232        8,308        3,654
    Divestments                    (2)        (158)      (3,392)
    Discoveries                    35        4,940          925
    Extensions                    888       37,252       17,528
    Technical Revisions           310      (26,373)      (6,704)
    Economic Factors              (22)      (6,946)        (839)
    Improved Recovery              39       37,674       14,345
    Production                 (1,636)     (98,905)     (31,309)
    ------------------------------------------------------------
    Proved Plus Probable
     Reserves at
     Dec. 31, 2006             16,467    1,264,086      443,345
    ------------------------------------------------------------
    ------------------------------------------------------------


    Net Present Value of Future Production Revenue - Forecast Prices and
    Costs (after U.S. taxes) at December 31, 2006

    Conventional Reserves
     ($ millions,
     discounted at)                0%           5%          10%          15%
    -------------------------------------------------------------------------
    Proved developed producing
      Canada                    6,705        4,479        3,464        2,877
      United States               804          624          509          431
    -------------------------------------------------------------------------
    Total                       7,509        5,103        3,973        3,308
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    Proved developed
     non-producing
      Canada                      120           75           56           45
      United States                25           19           16           13
    -------------------------------------------------------------------------
    Total                         145           94           72           58
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    Proved undeveloped
      Canada                      556          385          272          196
      United States                26           16           10            7
    -------------------------------------------------------------------------
    Total                         582          401          282          203
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    Total Proved
      Canada                    7,381        4,939        3,792        3,118
      United States               855          659          535          451
    -------------------------------------------------------------------------
    Total                       8,236        5,598        4,327        3,569
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    Probable
      Canada                    2,721        1,242          745          516
      United States               419          217          126           78
    -------------------------------------------------------------------------
    Total                       3,140        1,459          871          594
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    Total Proved Plus
     Probable Conventional
     Reserves                  11,376        7,057        5,198        4,163
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    Bitumen (Oil Sands)
     Reserves
      Proved developed
       producing                   20           16           13           11
      Proved undeveloped           39           20           10            4
    -------------------------------------------------------------------------
    Total Proved                   59           36           23           15
    -------------------------------------------------------------------------
      Probable                    453          104           25            2
    -------------------------------------------------------------------------
    Total Proved plus Probable
     Bitumen (Oil Sands)Reserves  512          140           48           17
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    Total Conventional and
     Bitumen (Oil Sands)
     Reserves                  11,888        7,197        5,246        4,180
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    Net Asset Value

    Enerplus' net asset value is measured with reference to the present value
of all future net revenue from our reserves, assuming current income tax laws,
as estimated by our independent reserve engineers, Sproule, GLJ and D&M, plus
land values, adjusted for working capital and long-term debt at year-end. This
calculation can vary significantly depending on the oil and natural gas price
assumptions used by the independent reserve engineers. In addition, this
calculation ignores "going concern" value and assumes only the reserves
identified in the reserve reports with no further acquisitions, despite our 20
year history of replacing production through acquisitions and development.

    Net Asset Value - Forecast Prices and Costs (After U.S. Tax) at
    December 31, 2006

    ($ millions except trust
     unit amounts, discounted at)   0%           5%          10%          15%
    ------------------------------------------------------------------------
    Present value of  proved
     plus probable reserves
      Canadian Conventional    10,102        6,181        4,537        3,634
      United States
       (after tax)              1,274          876          661          529
      Bitumen (Oil Sands)         512          140           48           17
    -------------------------------------------------------------------------
      Total, present value
       of proved plus
       probable reserves       11,888        7,197        5,246        4,180
    Undeveloped acreage
      Canada                       53           53           53           53
      United States                16           16           16           16
    Long-term debt
     (net of cash)               (680)        (680)        (680)        (680)
    Asset retirement
     obligations(1)              (194)         (95)         (24)         (11)
    -------------------------------------------------------------------------
    Net Working Capital
     excluding deferred
     financial assets and
     distributions payable
     to unitholders.             (102)        (102)        (102)        (102)
    -------------------------------------------------------------------------
    Net Asset Value            10,981        6,389        4,509        3,456
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    Net Asset Value per
     Trust Unit at
     December 31, 2006(2)  $    89.17   $    51.88   $    36.61   $    28.06
    -------------------------------------------------------------------------
    (1) Asset retirement obligations do not equal the amount on the balance
        sheet ($124 million) as the balance sheet amount uses a 6% discount
        rate and a portion of the ARO costs are already reflected in the
        present value of reserves computed by the independent engineers
    (2) Based on 123,151,000 Trust Units outstanding as at December 31, 2006


    FINDING DEVELOPMENT AND ACQUISITION COSTS

    FD&A costs can be calculated either including or excluding future
development capital ("FDC"). FD&A costs under NI 51-101 include FDC as this
provides a more representative view of the full cost of reserve additions as
it accounts for future costs to bring the reserves to market. Under the
historic method, FD&A costs are understated as reserves are included without
taking into account the future capital expenditures required to fully develop
the reserve base. We have included both the NI 51-101 method which includes
FDC and the historic method for comparison purposes.

    FD&A Costs (including Future Development Capital)

    ($ millions, except per BOE amounts)      2006         2005         2004
    -------------------------------------------------------------------------
    Proved Reserves
    Excluding Oil Sands:

      Capital expenditures and
       net acquisitions                $     502.0  $     973.0  $     803.2
      Net change in future
       development capital                     8.0        184.7         99.0
      Company reserve additions (MMBOE)       18.6         53.7         57.5
    Oil Sands:
      Capital expenditures and net
       acquisitions                           19.4         33.2          8.3
      Net change in future
       development capital                   (13.6)        44.6            -
      Company reserve additions (MMBOE)       (0.7)         9.5            -
    FD&A costs ($/BOE)                 $     28.82  $     19.55  $     15.83
    Three-year average FD&A
     costs ($/BOE)(1)                  $     19.20  $     22.73  $     18.85
    -------------------------------------------------------------------------
    Proved plus Probable Reserves
    Excluding Oil Sands:
      Capital expenditures and net
       acquisitions                    $     502.0  $     973.0  $     803.2
      Net change in future
       development capital                    54.4        197.7        120.7
      Company reserve additions (MMBOE)       21.9         66.6         58.0
    Oil Sands:
      Capital expenditures and net
       acquisitions                           19.4         33.2          8.3
      Net change in future
       development capital                    15.6         33.4        266.1
      Company reserve additions (MMBOE)        3.6          5.4         47.7
    FD&A costs ($/BOE)                 $     23.19  $     17.18  $     11.34
    Three-year average FD&A
     costs ($/BOE)(1)                  $     14.90  $     13.46  $     11.02
    -------------------------------------------------------------------------
    (1) FD&A calculated over a three-year period.


    FD&A Costs (excluding Future Development Capital)

    ($ millions, except per BOE amounts)      2006         2005         2004
    -------------------------------------------------------------------------
    Proved Reserves
    Excluding Oil Sands:
      Capital expenditures and
       net acquisitions                $     502.0  $     973.0  $     803.2
      Company reserve additions (MMBOE)       18.6         53.7         57.5
    Oil Sands:
      Capital expenditures and
       net acquisitions                       19.4         33.2          8.3
      Company reserve additions (MMBOE)       (0.7)         9.5            -
    FD&A costs ($/BOE)                 $     29.13  $     15.92  $     14.11
    Three-year average FD&A costs
     ($/BOE)(1)                        $     16.88  $     14.30  $     11.62
    -------------------------------------------------------------------------
    Proved plus Probable Reserves
    Excluding Oil Sands:
      Capital expenditures and
       net acquisitions                $     502.0  $     973.0  $     803.2
      Company reserve additions (MMBOE)       21.9         66.6         58.0
    Oil Sands:
      Capital expenditures and
       net acquisitions                       19.4         33.2          8.3
      Company reserve additions (MMBOE)        3.6          5.4         47.7
    FD&A costs ($/BOE)                 $     20.45  $     13.98  $      7.68
    Three-year average FD&A costs
     ($/BOE)(1)                        $     11.51  $     10.09  $      8.22
    -------------------------------------------------------------------------
    (1) Calculated as FD&A over a three-year period.

    RECYCLE RATIO

    Recycle ratio is calculated as operating income divided by FD&A including
FDC. It is indicative of the value created for each dollar invested and
accounts for the quality of reserves, operating costs and attractiveness of
acquisitions and internal development capital.

    (Proved plus probable reserves)           2006         2005         2004
    -------------------------------------------------------------------------
    Operating income ($/BOE)                 31.75        29.80        21.86
    Finding, development and acquisition
     costs including FDC ($/BOE)             23.19        17.18        11.34
    Recycle ratio                             1.4x         1.7x         1.9x
    Three-year average recycle ratio          1.6x         1.8x         1.8x
    -------------------------------------------------------------------------

    FINANCIAL OVERVIEW

    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 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.

    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     % Change
    -------------------------------------------------------------------------
    Natural 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     % Change
    -------------------------------------------------------------------------
    Natural 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     % Change
    -------------------------------------------------------------------------
    AECO 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 $8.41/Mcf realized in 2005. This reduction is comparable to the
price decreases realized in each of: the AECO daily index which decreased by
25% year over year; the AECO monthly index which decreased by 18%; and the
NYMEX monthly index (converted to CDN$/Mcf) which decreased by 20%.

    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.

    Canadian/US Exchange Rate

    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:

                                        Natural Gas                Crude Oil
                                         (CDN$/Mcf)                (US$/bbl)
                           -----------------------------------  -------------
                           January 1,     April 1,  November 1,   January 1,
                              2007 -       2007 -       2007 -       2007 -
                            March 31,  October 31,    March 31, December 31,
                                2007         2007         2008         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                      2005
    -------------------------------------------------------------------------
    Cash (gains)/losses:
      Crude oil           $      27.2  $  2.06/bbl  $      91.0  $  8.51/bbl
      Natural Gas                 7.1  $  0.07/Mcf         51.6  $  0.52/Mcf
                          ------------              ------------
    Total Cash losses     $      34.3  $  1.10/BOE  $     142.6  $  4.90/BOE

    Non-cash
     (gains)/losses:
      Change in fair
       value - financial
       contracts          $     (81.0) $(2.59)/BOE  $     (35.8) $(1.23)/BOE
      Amortization of
       deferred financial
       assets                    49.9  $  1.59/BOE          3.1  $  0.11/BOE
                          ------------              ------------
    Total Non-cash gains  $     (31.1) $(0.99)/BOE  $     (32.7) $(1.12)/BOE

                          ------------              ------------
    Total 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                                    $      0.08
    Change of US$1.00 per barrel in the price
     of WTI crude oil                                    $      0.05
    Change of 1,000 BOE/day in production                $      0.13
    Change of $0.01 in the US$/CDN$ exchange rate        $      0.12
    Change of 1% in interest rate                        $      0.06
    -------------------------------------------------------------------------
    (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)                                         Natural
     ($ millions)           Crude oil         NGLs          Gas        Total
    -------------------------------------------------------------------------
    2005 Sales Revenue    $     598.4  $      81.0  $     844.3  $   1,523.7
    Price 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:

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

    (Per BOE)                                              2006         2005
    -------------------------------------------------------------------------
    Cash                                            $      1.71  $      1.28
    Trust unit rights incentive plan (non-cash)            0.20         0.11
    -------------------------------------------------------------------------
    Total 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         2005
    -------------------------------------------------------------------------
    Development expenditures                        $     380.5  $     272.2
    Plant and facilities                                  110.7         96.5
    -------------------------------------------------------------------------
      Development Capital                                 491.2        368.7
    Office                                                  5.0          4.3
    -------------------------------------------------------------------------
      Sub-total                                           496.2        373.0
    Acquisitions of oil and gas properties(1)              51.3        119.9
    Corporate acquisitions                                    -        584.1
    Dispositions of oil and gas properties(1)             (21.1)       (66.5)
    -------------------------------------------------------------------------
    Total Net Capital Expenditures                  $     526.4  $   1,010.5
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    Total Capital Expenditures financed
     with cash flow                                 $     249.4  $     276.4
    Total Capital Expenditures financed with
     debt and equity                                      296.5        734.1
    Total 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.

    ($ millions)
    Property              Development Type                 2006         2005
    -------------------------------------------------------------------------
    Sleeping Giant        Bakken oil                $     116.7  $      29.1
    Joslyn and oil sands  Oil sands                        39.1         33.2
    Bantry                Conventional oil and
                           shallow gas                     21.7         42.0
    Joarcam               Oil waterflood                   20.2         16.9
    Pembina 5-Way         Oil waterflood                   15.7         19.8
    Medicine Hat          Oil waterflood and
                           shallow gas                     14.9         11.0
    Shackleton            Shallow gas                      12.7          5.6
    Hanna/Garden Plains   Shallow gas                      12.5         18.5
    Joffre                Coalbed methane                  12.5         15.9
    Deep Basin            Natural gas                      12.4         11.6
    Other                 Oil and gas                     212.8        165.1
    -------------------------------------------------------------------------
    Total                                           $     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         2005
    -------------------------------------------------------------------------
    Amortization of the asset retirement cost       $      12.6  $      10.6
    Accretion of the asset retirement obligation            6.2          6.3
    -------------------------------------------------------------------------
    Total Amortization and Accretion                $      18.8  $      16.9
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    Asset 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.
    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:

                                             Trust    Operating        Total
    Pool Type ($ millions)                             entities
    -------------------------------------------------------------------------
    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.

    Selected Financial Results

    Per BOE of production (6:1)                            2006         2005
    -------------------------------------------------------------------------
    Production per day                                   85,779       79,727
    -------------------------------------------------------------------------
    Weighted average sales price(1)                 $     50.23    $   52.36
    Royalties                                             (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         0.11
    Interest 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        27.30
    Asset retirement obligations settled                   0.37         0.27
    Non-cash items:
      Depletion, depreciation, amortization
       and accretion                                     (15.38)      (13.27)
      Financial contracts                                  0.99         1.12
      G&A expense (trust unit rights)                     (0.20)       (0.11)
      Foreign exchange gain                                   -         0.07
      Future 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      270,972
      Crude oil (bbls/day)                  25,858       10,276       36,134
      Natural gas liquids (bbls/day)         4,483            -        4,483
      Total daily sales (BOE/day)           74,511       11,268       85,779

    Pricing(1)
      Natural gas (per Mcf)            $      6.79  $      7.78  $      6.81
      Crude oil (per bbl)                    59.36        67.93        61.80
      Natural gas liquids (per bbl)          50.90            -        50.90

    Capital
      Development capital and office   $     378.5  $     117.7  $     496.2
      Acquisitions of oil and
       gas properties                         35.3         16.0         51.3
      Dispositions of oil and
       gas properties                        (21.1)           -        (21.1)

    Revenues
      Oil and gas sales(1)             $   1,301.0  $     271.7  $   1,572.7
      Royalties                             (241.0)    (52.2)(2)      (293.2)
      Other financial contracts               (3.2)           -         (3.2)

    Expenses
      Operating                        $     243.8  $       7.4  $     251.2
      General and administrative              51.4          8.5         59.9
      Depletion, depreciation,
       amortization and accretion            369.6        112.0        481.6
      Current 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.

    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               Net Income Per Trust Unit
    ($ millions, except per   and Gas
     trust unit amounts)      Sales(1)  Net Income        Basic      Diluted
    -------------------------------------------------------------------------
    2006
    Fourth Quarter        $     369.5  $     110.2  $      0.90  $      0.89
    Third Quarter               398.0        161.3         1.31         1.31
    Second Quarter              403.5        146.0         1.19         1.19
    First Quarter               401.7        127.3         1.08         1.07
    -----------------------------------------------
    Total                 $   1,572.7  $     544.8  $      4.48  $      4.47
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    2005
    Fourth Quarter        $     503.2  $     150.9  $      1.29  $      1.28
    Third Quarter               398.7        107.1         0.97         0.97
    Second Quarter              320.0        108.8         1.04         1.04
    First Quarter               301.8         65.2         0.63         0.62
    -----------------------------------------------
    Total                 $   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 28% to $207.1 million in 2006 compared to
        $288.5 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            Three Months  Three Months
     Information                             Ended         Ended
    ($ millions, except                December 31,  December 31,
     per unit amounts)                        2006          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%

    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         2004
    -------------------------------------------------------------------------
    Oil and gas sales(1)               $   1,572.7  $   1,523.7  $   1,124.6

    Net income                               544.8        432.0        258.3
    Per unit (Basic)(2)                       4.48         3.96         2.60
    Per unit (Diluted)                        4.47         3.95         2.60

    Cash flow from operating activities      863.7        774.6        555.1
    Per unit (Basic)(2)                       7.10         7.10         5.59

    Cash distributions                       614.3        498.2        423.3
    Per unit (Basic)(2)                       5.05         4.57         4.26
    Payout ratio                               71%          64%          76%

    Total assets                           4,203.8      4,130.6      3,180.7

    Long-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.

    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 would 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         2005
    -------------------------------------------------------------------------
    Cash flow from operating activities:            $     863.7  $     774.6

    Use of cash flow:
      Cash distributions                            $     614.3  $     498.2
      Capital expenditures                                249.4        276.4
    -------------------------------------------------------------------------
                                                    $     863.7  $     774.6

    Excess of cash flow over cash distributions     $     249.4  $     276.4

    Net income                                      $     544.8  $     432.0
    Shortfall of net income over cash
     distributions                                  $     (69.5) $     (66.2)

    Cash distributions per weighted average
     trust unit                                     $      5.05  $      4.57
    Payout 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.

    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 comprised of $348.5 million 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:

                                                     Year ended   Year ended
                                                        Dec. 31,     Dec. 31,
    Financial Leverage and Coverage                        2006         2005
    -------------------------------------------------------------------------

    Long-term debt to trailing cash flow                  0.8 x        0.8 x
    Cash flow to interest expense                        26.8 x       30.0 x
    Long-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:

                                                                       Total
                          Minimum Annual Commitment Each Year      Committed
                  ------------------------------------------------     after
    ($ millions)     Total    2007    2008    2009    2010    2011      2011
    -------------------------------------------------------------------------
    Bank credit
     facility     $348.5(1) $    -  $    -  $348.5  $    -  $    -  $      -
    Senior
     unsecured
     notes         331.3(1)      -       -       -    53.7    66.3     211.3
    Pipeline
     commitments      28.5     6.4     5.8     3.0     2.4     2.2       8.7
    Office lease      20.9     6.7     6.8     6.7     0.6     0.1         -
    -------------------------------------------------------------------------
    Total
     commit-
     ments(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.

    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 news release. 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.

    Summary of 2007
     Expectations               Target            Comments
    -------------------------------------------------------------------------
    Average annual production   85,000 BOE/day    Assumes no new acquisitions
                                                   or dispositions
    Exit rate December          86,000 BOE/day    Assumes $410 million
     2007 production                               development capital
                                                   spending
    2007 production mix         54% gas, 42% oil,
                                 4% NGL

    Average royalty rate        19%               Percentage of gross
                                                   unhedged sales
    Operating costs             $8.45/BOE
    G&A costs                   $2.40/BOE         Includes non-cash charges
                                                   of $0.30/BOE (unit rights
                                                   plan)
    U.S. income and             15%               Applied to net cash flow
     withholding tax -                             generated by U.S.
     cash costs                                    operations and assumes
                                                   repatriation of the funds
                                                   to Canada after U.S.
                                                   development capital
                                                   spending
    Average interest cost       5.0%              Based on current fixed
                                                   rates and forward market

    Payout ratio                60% -90%

    Development capital         $410 million      Based on current plans and
     spending                                      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.

    ADDITIONAL INFORMATION

    Additional information relating to Enerplus Resources Fund 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. Readers should review the risk factors
regarding our business and operations contained in our publicly filed
documents including our Annual Information Form.


    UNAUDITED CONSOLIDATED BALANCE SHEETS

    As at December 31 (CDN$ thousands)                     2006         2005
    -------------------------------------------------------------------------
    Assets
    Current assets
      Cash                                          $       124  $    10,093
      Accounts receivable                               175,454      170,623
      Deferred financial assets (Note 2)                 23,612       49,874
      Other current (Note 10)                             6,715       26,751
    -------------------------------------------------------------------------
                                                        205,905      257,341
    Property, plant and equipment (Note 3)            3,726,097    3,650,327
    Goodwill (Note 6)                                   221,578      221,234
    Other assets (Notes 7 and 10)                        50,224        1,721
    -------------------------------------------------------------------------
                                                    $ 4,203,804  $ 4,130,623
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    Liabilities
    Current liabilities
      Accounts payable                              $   284,286  $   316,875
      Distributions payable to unitholders               51,723       49,367
      Deferred credits (Note 2)                               -       57,368
    -------------------------------------------------------------------------
                                                        336,009      423,610
    -------------------------------------------------------------------------
    Long-term debt (Note 7)                             679,774      659,918
    Future income taxes (Note 9)                        331,340      442,970
    Asset retirement obligations (Note 4)               123,619      110,606
    -------------------------------------------------------------------------
                                                      1,134,733    1,213,494
    -------------------------------------------------------------------------
    Equity
    Unitholders' capital (Note 8)
      Trust Units
      Authorized:              Unlimited
      Issued and Outstanding:  2006 - 123,150,820
                               2005 - 117,539,331     3,713,126    3,410,614
    Accumulated deficit                                (971,085)    (901,527)
    Cumulative translation adjustment (Note 1(j))        (8,979)     (15,568)
    -------------------------------------------------------------------------
                                                      2,733,062    2,493,519
    -------------------------------------------------------------------------
                                                    $ 4,203,804  $ 4,130,623
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------


    UNAUDITED CONSOLIDATED STATEMENTS OF ACCUMULATED DEFICIT


    For the year ended December 31 (CDN$ thousands)        2006         2005
    -------------------------------------------------------------------------

    Accumulated income, beginning of year           $ 1,408,178  $   976,137
    Net income                                          544,782      432,041
    -------------------------------------------------------------------------
    Accumulated income, end of year                 $ 1,952,960  $ 1,408,178

    Accumulated cash distributions, beginning
     of year                                        $(2,309,705) $(1,811,500)
    Cash distributions                                 (614,340)    (498,205)
    -------------------------------------------------------------------------
    Accumulated cash distributions, end of year     $(2,924,045) $(2,309,705)

    -------------------------------------------------------------------------
    Accumulated deficit, end of year                $  (971,085) $  (901,527)
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------


    UNAUDITED CONSOLIDATED STATEMENTS OF INCOME

    For the year ended December 31
    (CDN$ thousands except per trust unit amounts)         2006         2005
    -------------------------------------------------------------------------

    Revenues
      Oil and gas sales                             $ 1,595,324  $ 1,550,569
      Royalties                                        (293,161)    (296,983)
      Derivative instruments (Notes 2 and 10)
        Financial contracts - qualified hedges                -      (27,256)
        Other financial contracts                        (3,226)     (82,664)
      Other income                                        2,465       11,064
    -------------------------------------------------------------------------
                                                      1,301,402    1,154,730
    -------------------------------------------------------------------------
    Expenses
      Operating                                         251,239      216,808
      General and administrative (Note 8(b))             59,937       40,375
      Transportation                                     22,611       26,915
      Interest on long-term debt (Note 7)                32,168       25,791
      Foreign exchange (gain)/loss                         (528)       1,677
      Depletion, depreciation, amortization
       and accretion                                    481,598      386,545
    -------------------------------------------------------------------------
                                                        847,025      698,111
    -------------------------------------------------------------------------
    Income before taxes                                 454,377      456,619
    Capital taxes                                         3,393        6,486
    Current taxes                                        18,236        2,764
    Future income tax (recovery)/expense (Note 9)      (112,034)      15,328
    -------------------------------------------------------------------------
    Net Income                                      $   544,782  $   432,041
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    Net income per trust unit
      Basic                                         $      4.48  $      3.96
      Diluted                                       $      4.47  $      3.95
    -------------------------------------------------------------------------
    Weighted average number of trust units
     outstanding (thousands)
      Basic                                             121,588      109,083
      Diluted                                           121,858      109,371
    -------------------------------------------------------------------------


    UNAUDITED CONSOLIDATED STATEMENTS OF CASH FLOWS

    For the year ended December 31 (CDN$ thousands)        2006         2005
    -------------------------------------------------------------------------
    Operating Activities
    Net income                                      $   544,782  $   432,041
    Non-cash items add/(deduct):
      Depletion, depreciation, amortization
       and accretion                                    481,598      386,545
      Non-cash financial contracts (Note 2)             (31,106)     (32,679)
      Non-cash foreign exchange                             (32)      (2,036)
      Unit based compensation (Note 8)                    6,323        3,040
      Future income tax (Note 9)                       (112,034)      15,328
    Asset retirement obligations settled (Note 4)       (11,514)      (7,829)
    -------------------------------------------------------------------------
                                                        878,017      794,410
    Increase in non-cash operating working capital      (14,321)     (19,777)
    -------------------------------------------------------------------------
    Cash flow from operating activities                 863,696      774,633
    -------------------------------------------------------------------------

    Financing Activities
    Issue of trust units, net of issue costs (Note 8)   296,189      507,209
    Cash distributions to unitholders                  (614,340)    (498,205)
    Increase in bank credit facilities (Note 7)          19,888       76,963
    Decrease in non-cash financing working capital        2,356       12,924
    -------------------------------------------------------------------------
    Cash flow from financing activities                (295,907)      98,891
    -------------------------------------------------------------------------

    Investing Activities
    Capital expenditures                               (496,201)    (373,032)
    Property acquisitions (Note 5)                      (51,313)    (123,896)
    Property dispositions                                 1,599       66,511
    Corporate acquisitions, net of cash
     acquired (Note 6)                                        -     (483,014)
    Purchase of investments                             (29,172)           -
    (Increase)/Decrease in non-cash investing
     working capital                                     (3,535)      51,045
    -------------------------------------------------------------------------
    Cash flow from investing activities                (578,622)    (862,386)
    -------------------------------------------------------------------------

    Effect of exchange rate changes on cash                 864       (1,045)
    -------------------------------------------------------------------------
    Change in cash                                       (9,969)      10,093
    Cash, beginning of year                              10,093            -
    -------------------------------------------------------------------------
    Cash, end of year                               $       124  $    10,093
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    Supplementary Cash Flow Information
    Cash income taxes paid                          $    14,060  $     2,669
    Cash interest paid                              $    34,924  $    24,220


    NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS


    1.  SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

    The management of Enerplus Resources Fund ("Enerplus" or the "Fund")
    prepares the financial statements in accordance with Canadian generally
    accepted accounting principles ("GAAP"). A reconciliation between
    Canadian GAAP and United States of America GAAP is disclosed in Note 14.
    The preparation of financial statements requires management to make
    estimates and assumptions that affect the reported amounts of assets and
    liabilities and disclosures of contingencies, if any, as at the date of
    the financial statements and the reported amounts of revenues and
    expenses during the reporting period. The following significant
    accounting policies are presented to assist the reader in evaluating
    these consolidated financial statements and, together with the following
    notes, should be considered an integral part of the consolidated
    financial statements.

    (a) Organization and Basis of Accounting

    The Fund is an open-end investment trust created under the laws of the
    Province of Alberta operating pursuant to the Amended and Restated Trust
    Indenture between EnerMark Inc. (the Fund's wholly-owned subsidiary),
    Enerplus Resources Corporation ("ERC") and CIBC Mellon Trust Company as
    Trustee. The beneficiaries of the Fund (the "unitholders") are holders of
    the trust units issued by the Fund. As a trust under the Income Tax Act
    (Canada), Enerplus is limited to holding and administering permitted
    investments and making distributions to the unitholders.

    The Fund's financial statements include the accounts of the Fund and its
    subsidiaries on a consolidated basis. All inter-entity transactions have
    been eliminated. Many of the Fund's production activities are conducted
    through joint ventures and the financial statements reflect only the
    Fund's proportionate interest in such activities.

    (b) Revenue Recognition

    Revenue associated with the sale of crude oil, natural gas and natural
    gas liquids is recognized when title passes from the Fund to its
    customers based on volumes delivered and contractual delivery points and
    price. A portion of the properties acquired through the March 5, 2003
    acquisition of PCC Energy Inc. and PCC Energy Corp. are subject to a
    royalty arrangement with a private company that is structured as a net
    profits interest. The results from operations included in the Fund's
    consolidated financial statements for these properties are reduced for
    this net profits interest.

    (c) Property, Plant and Equipment ("PP&E")

    The Fund follows the full cost method of accounting for petroleum and
    natural gas properties under which all acquisition and development costs
    are capitalized on a country by country cost centre basis. Such costs
    include land acquisition, geological, geophysical, drilling costs for
    productive and non- productive wells, facilities and directly related
    overhead charges. Repairs, maintenance and operational costs that do not
    extend or enhance the recoverable reserves are charged to earnings.
    Proceeds from the sale of petroleum and natural gas properties are
    applied against the capitalized costs. Gains and losses are not
    recognized upon disposition of oil and natural gas properties unless such
    a disposition would alter the rate of depletion by 20% or more. Net costs
    related to operating and administrative activities during the development
    of large capital projects are capitalized until commercial production has
    commenced.

    (d) Impairment Test

    A limit is placed on the aggregate carrying value of PP&E (the
    "impairment test"). The Fund performs an impairment test on a country by
    country basis. An impairment loss exists when the carrying amount of the
    country's PP&E exceeds the estimated undiscounted future net cash flows
    associated with the country's proved reserves. If an impairment loss is
    determined to exist, the costs carried on the balance sheet in excess of
    the discounted future net cash flows associated with the country's proved
    and probable reserves are charged to income.

    (e) Depletion and Depreciation

    The provision for depletion and depreciation of oil and natural gas
    assets is calculated on a country by country basis using the unit-of-
    production method, based on the country's share of estimated proved
    reserves before royalties. Reserves and production are converted to
    equivalent units on the basis of 6 Mcf = 1 bbl, reflecting the
    approximate relative energy content.

    (f) Goodwill

    The Fund, when appropriate, recognizes goodwill relating to corporate
    acquisitions when the total purchase price exceeds the fair value of the
    net identifiable assets and liabilities of the acquired companies. The
    goodwill balance is assessed for impairment annually at year-end or as
    events occur that could result in an impairment. To assess impairment,
    the fair values of the Canadian and U.S. reporting units are compared to
    their respective book values. If the fair value is less than the book
    value, a second test is performed to determine the amount of impairment.
    The amount of impairment is measured by allocating the fair value of the
    reporting unit to its identifiable assets and liabilities as if they had
    been acquired in a business combination for a purchase price equal to
    their fair value. If goodwill determined in this manner is less than the
    carrying value of goodwill, an impairment loss is recognized in the
    period in which it occurs. Goodwill is stated at cost less impairment and
    is not amortized. Goodwill is not deductible for income tax purposes.

    (g) Asset Retirement Obligations

    The Fund recognizes as a liability the estimated fair value of the future
    retirement obligations associated with PP&E. The fair value is
    capitalized and amortized over the same period as the underlying asset.
    The Fund estimates the liability based on the 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. This
    estimate is evaluated on a periodic basis and any adjustment to the
    estimate is prospectively applied. As time passes, the change in net
    present value of the future retirement obligation is expensed through
    accretion. Retirement obligations settled during the period reduce the
    future retirement liability. No gains or losses on retirement activities
    were realized, due to settlements approximating the estimates.

    (h) Income Taxes

    The Fund is a taxable entity under the Income Tax Act (Canada) and is
    taxable only on Canadian income that is not distributed or distributable
    to the Fund's unitholders. In the Trust structure, payments made between
    the Canadian operating entities and the Fund, ultimately transfers both
    income and future income tax liability to the unitholders. The future
    income tax liability associated with Canadian assets recorded on the
    balance sheet is recovered over time through these payments. As the
    Canadian operating entities transfer all of their Canadian taxable income
    to the Fund, no provision for current Canadian income tax has been made
    by any Canadian operating entity.

    The U.S. operating entity is subject to U.S. income taxes on its taxable
    income determined under U.S. income tax rules and regulations.
    Repatriation of funds from U.S. operations will also be subject to
    applicable withholding taxes as required under U.S. tax law. A provision
    has been setup to reflect these current U.S. income taxes.

    The Fund follows the liability method of accounting for income taxes.
    Under this method, income tax liabilities and assets are recognized for
    the estimated tax consequences attributable to temporary differences
    between the amounts reported in the financial statements of the Fund's
    corporate subsidiaries and their respective tax bases, using
    substantively enacted income tax rates. The effect of a change in these
    income tax rates on future income tax liabilities and assets is
    recognized in income during the period that the change occurs.

    (i) Financial Instruments

    The Fund is exposed to market risks resulting from fluctuations in
    commodity prices and interest rates in the normal course of operations.
    The Fund uses various types of financial instruments to manage these
    market risks. Prior to December 31, 2005, the Fund designated certain
    commodity contracts and interest rate swaps as qualified hedges.
    Effective December 31, 2005, the Fund elected to stop designating
    commodity contracts as qualified hedges. The fair value of the former
    commodity hedges has been recorded as a financial liability with an
    offset to deferred financial assets. The deferred financial asset will be
    amortized over the remaining lives of the associated financial contracts.
    The fair value of the financial liability will be determined at each
    period end with any resulting change in fair value being taken into
    income in that period.

    The gain or loss in fair value of all financial contracts that had not
    previously qualified for hedge accounting are taken into income during
    the period of change and charged to deferred credits or deferred
    financial assets on the balance sheet.

    Proceeds or costs realized from holding interest rate swaps are
    recognized at the time each transaction under a contract is settled and
    is recorded in interest expense. The Fund has designated the interest
    rate swaps as qualified hedges and these swaps are evaluated quarterly to
    ensure they effectively hedge the underlying interest rate.

    (j) Foreign Currency Translation

    The Fund's U.S. operations are self-sustaining. Assets and liabilities of
    these operations are translated into Canadian dollars at period end
    exchange rates, while revenues and expenses are converted using average
    rates for the period. Gains and losses from the translation into Canadian
    dollars are deferred and included in the cumulative translation
    adjustment as part of unitholders' equity.

    Other monetary assets and liabilities, not related to the Fund's U.S.
    operations, are translated into Canadian dollars at rates of exchange in
    effect at the balance sheet date. The other assets and related
    depreciation, depletion and amortization, other liabilities, revenue and
    other expenses are translated into Canadian dollars at rates of exchange
    in effect at the respective transaction dates. The resulting exchange
    gains or losses are included in earnings.

    (k) Unit Based Compensation

    The Fund uses the fair value method of accounting for the trust unit
    rights incentive plan. Under this method, the fair value of the rights is
    determined on the date in which fair value can reasonably be determined,
    generally being the grant date. This amount is charged to earnings over
    the vesting period of the rights, with a corresponding increase in
    contributed surplus. When rights are exercised, the proceeds, together
    with the amount recorded in contributed surplus, are recorded to
    unitholders' capital.


    2.  DEFERRED FINANCIAL ASSETS AND DEFERRED CREDITS

    The deferred financial assets of $23,612,000 at December 31, 2006 consist
    of the fair value of the financial instruments of $49,268,000 less the
    related deferred premiums of $25,656,000.


    Deferred Financial Assets ($ thousands)
    -------------------------------------------------------------------------
    Fair value of financial instruments
      Deferred financial assets as at December 31, 2005          $    49,874
      Deferred financial credits as at December 31, 2005             (57,368)
      Change in fair value - other financial contracts(1)             80,980
      Amortization of deferred financial assets(2)                   (49,874)
    -------------------------------------------------------------------------
                                                                 $    23,612
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    (1) Changes in the fair value of financial contracts that do not qualify
        for hedge accounting are taken into income during the period as
        other financial contracts and reflected as an increase or decrease in
        the deferred financial asset or liability.
    (2) Represents the amortization of the fair value of financial contracts
        on December 31, 2005 for which hedge accounting is no longer applied.
        These deferred financial assets are fully amortized at December 31,
        2006.


    The following table summarizes the income statement effects of other
    financial contracts:

    Other Financial Contracts ($ thousands)                2006         2005
    -------------------------------------------------------------------------
    Change in fair value                            $   (80,980) $   (35,823)
    Amortization of deferred financial assets            49,874        3,144
    Realized cash costs, net                             34,332      115,343
    -------------------------------------------------------------------------
    Other financial contracts                       $     3,226  $    82,664
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------


    During the year ended December 31, 2006, the Fund realized cash costs of
    $nil from commodity financial contracts that qualified as hedges compared
    to cash costs of $27,256,000 (net gains and losses) during 2005.


    3.  PROPERTY, PLANT AND EQUIPMENT

    ($ thousands)                                          2006         2005
    -------------------------------------------------------------------------
    Property, plant and equipment                   $ 5,855,511  $ 5,306,137
    Accumulated depletion, depreciation and
     accretion                                       (2,129,414)  (1,655,810)
    -------------------------------------------------------------------------
    Net property, plant and equipment               $ 3,726,097  $ 3,650,327
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------


    Capitalized development G&A of $14,111,000 (2005 - $11,571,000) is
    included in PP&E and the depletion and depreciation calculation includes
    future capital costs of $472,567,000 (2005 - $464,423,000) included in
    our reserve reports. Excluded from PP&E for the depletion and
    depreciation calculation is $81,183,000 (2005 - $61,795,000) related to
    the Joslyn development project that has not commenced commercial
    production.

    An impairment test calculation was performed on a country by country
    basis on the PP&E values at December 31, 2006 in which the estimated
    undiscounted future net cash flows associated with the proved reserves
    exceeded the carrying amount of the Fund's PP&E.

    The following table outlines benchmark prices and the exchange rate used
    in the impairment tests for both Canadian and U.S. cost centres at
    December 31, 2006:

                                                                 Natural Gas
                            WTI Crude     Exchange    Edm Light  30 day spot
                                Oil(1)        Rate      Crude(1) @ AECO(1)
    Year                      US$/bbl     US$/CDN$     CDN$/bbl     CDN$/Mcf
    -------------------------------------------------------------------------
    2007                  $     65.73  $      0.87  $     74.10  $      7.72
    2008                        68.82         0.87        77.62         8.59
    2009                        62.42         0.87        70.25         7.74
    2010                        58.37         0.87        65.56         7.55
    2011                        55.20         0.87        61.90         7.72
    Thereafter                 + 2.0%         0.87       + 2.0%       + 2.0%
    -------------------------------------------------------------------------
    (1) Actual prices used in the impairment test were adjusted for commodity
        price differentials specific to the Fund


    4.  ASSET RETIREMENT OBLIGATIONS

    Total future asset retirement obligations were estimated by management
    based on the Fund's 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. The Fund
    has estimated the net present value of its total asset retirement
    obligations to be $123,619,000 at December 31, 2006 compared to
    $110,606,000 at December 31, 2005 based on a total liability of
    $436,663,000 and $422,045,000 respectively. These payments are expected
    to be made over the next 66 years with the majority of costs incurred
    between 2036 and 2045. To calculate the present value of the asset
    retirement obligations for 2006 the Fund used a weighted credit-adjusted
    rate of approximately 6.3% and an inflation rate of 2.0%, the same as for
    2005. Settlements during the year approximated our estimates and as a
    result, no gains or losses were recognized.

    Following is a reconciliation of the asset retirement obligations:


    ($ thousands)                                          2006         2005
    -------------------------------------------------------------------------
    Asset retirement obligations, beginning of year $   110,606  $   105,978
    Changes in estimates                                 12,757        8,764
    Acquisition and development activity                  5,574        6,791
    Dispositions                                            (45)      (9,413)
    Asset retirement obligations settled                (11,514)      (7,829)
    Accretion expense                                     6,241        6,315
    -------------------------------------------------------------------------
    Asset retirement obligations, end of year       $   123,619  $   110,606
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------


    5.  PROPERTY ACQUISITIONS

    Assets of Sleeping Giant LLC ("Sleeping Giant")

    On October 4, 2005 the Fund acquired all ownership interests and retired
    the debt of Sleeping Giant, a private U.S. company holding additional
    working interests in certain properties of Lyco Energy Corporation for
    total cash consideration of $111,914,000 which was financed through
    existing credit facilities. The fair value of this consideration was
    allocated to cash and positive working capital assumed of $5,754,000 and
    PP&E of $106,160,000. This acquisition has been accounted for as an asset
    acquisition. The operating results of Sleeping Giant subsequent to
    October 4, 2005 are included in the Fund's consolidated financial
    statements.


    6.  CORPORATE ACQUISITIONS

    The allocation to the fair value of the assets acquired and liabilities
    assumed plus the future income tax cost are summarized as follows:


                                                           2005         2005
    ($ thousands)                                          Lyco      TriLoch
    -------------------------------------------------------------------------
    Property, plant and equipment                   $   506,379  $    77,786
    Goodwill (with no tax base)                         179,019       18,450
    Future income taxes                                (179,019)     (18,450)
    -------------------------------------------------------------------------
                                                        506,379       77,786
    Cash                                                 27,231            -
    Non-cash working capital deficiency                 (31,664)        (399)
    -------------------------------------------------------------------------
    Net assets acquired                             $   501,946  $    77,387
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    Goodwill is comprised of the following:

    Goodwill ($ thousands)                                 2006         2005
    -------------------------------------------------------------------------
    Balance, beginning of year                      $   221,234  $    29,082
    Lyco acquisition                                          -      179,019
    TriLoch acquisition                                       -       18,450
    Foreign exchange(1)                                     344       (5,317)
    -------------------------------------------------------------------------
    Balance, end of year                            $   221,578  $   221,234
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    (1) The foreign exchange results from the translation of Lyco goodwill at
        the period end rate.


    Lyco Energy Corporation ("Lyco")

    On August 30, 2005 the Fund acquired all the outstanding common shares
    and retired the debt including all outstanding mandatorily redeemable
    preferred shares of Lyco, a private U.S. company operating in the states
    of Montana and North Dakota. Total consideration was approximately
    $501,946,000, and the Fund assumed a net working capital deficiency of
    $4,433,000. Goodwill of $179,019,000 was recorded based on the excess of
    the consideration paid over the value assigned to the identifiable assets
    and liabilities including the future income tax liability. The
    acquisition, which was financed through an equity offering and available
    credit facilities, has been accounted for using the purchase method of
    accounting for business combinations. Results from the operations of Lyco
    subsequent to August 30, 2005 are included in the Fund's consolidated
    financial statements.

    TriLoch Resources Inc. ("TriLoch")

    On July 1, 2005 the Fund acquired all the outstanding common shares of
    TriLoch, a public Alberta corporation operating in southern Alberta, in
    exchange for 1,632,516 trust units of the Fund with a recorded value of
    $69,088,000. The trust unit value was based on the weighted average price
    of the Fund's trust units on the Toronto Stock Exchange during the five
    day trading period surrounding the announcement of the TriLoch
    transaction. Total consideration was $77,387,000 consisting of units,
    deal costs and the retirement of TriLoch's bank indebtedness. The Fund
    also assumed a working capital deficiency of $399,000. Goodwill of
    $18,450,000 has been recorded as a result of the excess of the
    consideration paid over the value allocated to the identifiable assets
    and liabilities including the future income tax liability. This
    acquisition has been accounted for using the purchase method of
    accounting for business combinations. Results from the operations of
    TriLoch subsequent to July 1, 2005 are included in the Fund's
    consolidated financial statements.


    7.  LONG-TERM DEBT

    ($ thousands)                                          2006         2005
    -------------------------------------------------------------------------
    Bank credit facilities(a)                       $   348,520  $   328,632
    Senior notes(b)
      US$175 million (issued June 19, 2002)             268,328      268,328
      US$54 million (issued October 1, 2003)             62,926       62,958
    -------------------------------------------------------------------------
    Total long-term debt                            $   679,774  $   659,918
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------


    (a) Unsecured Bank Credit Facility

    Enerplus has an $850,000,000 unsecured covenant based three year term
    facility and has the ability to extend the facility each year or repay
    the entire balance at the end of the three year term. During 2006, the
    facility was extended until November 2009. At December 31, 2006, Enerplus
    had available credit of $501,480,000 under this facility. The facility is
    extendible each year with a bullet payment required at the end of the
    three year term. Various borrowing options are available under the
    facility including prime rate based advances and bankers' acceptance
    loans. This facility 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. The effective interest rate on the facility for
    the year ended December 31, 2006 was 4.8% (2005 - 3.4%).

    (b) Senior Unsecured Notes

    On October 1, 2003 Enerplus issued US$54,000,000 senior unsecured notes
    that mature October 1, 2015. The notes have a coupon rate of 5.46% priced
    at par with interest paid semi-annually on April 1 and October 1 of each
    year. Principal payments are required in five equal installments
    beginning October 1, 2011 and ending October 1, 2015. Costs incurred in
    connection with issuing the notes in the amount of $475,000 are
    classified as deferred charges on the balance sheet and are being
    amortized as a part of depletion, depreciation, amortization and
    accretion ("DDA&A") over the term of the notes. At December 31, 2006, the
    amount remaining to be amortized associated with these costs was $346,000
    (2005 - $386,000). The notes are subject to fluctuations in foreign
    exchange rates.

    On June 19, 2002 Enerplus issued US$175,000,000 senior unsecured notes
    that mature June 19, 2014. The notes have a coupon rate of 6.62% priced
    at par, with interest paid semi-annually on June 19 and December 19 of
    each year. Principal payments are required in five equal installments
    beginning June 19, 2010 and ending June 19, 2014. Costs incurred in
    connection with issuing the notes in the amount of $1,892,000 are
    classified as deferred charges on the balance sheet and are being
    amortized to DDA&A over the term of the notes. At December 31, 2006, the
    amount remaining to be amortized was $1,177,000 (2005 - $1,335,000).
    Concurrent with the issuance of the notes on June 19, 2002, the Fund
    entered into a cross currency swap with a syndicate of financial
    institutions. Under the terms of the swap, the amount of the notes was
    fixed for purposes of interest and principal repayments at a notional
    amount of CDN$268,328,000. Interest payments are made on a floating rate
    basis, set at the rate for three-month Canadian bankers' acceptances,
    plus 1.18%.

    The bank credit facility and the senior notes (the "Combined Facilities")
    are the legal obligation of EnerMark Inc. and are guaranteed by its
    subsidiaries. Payments with respect to the Combined Facilities have
    priority over payments to the Fund and over claims of and future
    distributions to the unitholders. However, unitholders have no direct
    liability beyond their equity investment should cash flow be insufficient
    to repay the Combined Facilities.


    8.  FUND CAPITAL

    (a) Unitholders' Capital

    Trust Units

    Authorized: Unlimited number of trust units

    (thousands)                      2006                      2005
    Issued:                     Units       Amount        Units       Amount
    -------------------------------------------------------------------------
    Balance before
     Contributed Surplus,
     beginning of year        117,539  $ 3,407,567      104,124  $ 2,826,641
    Issued for cash:
      Pursuant to public
       offerings                4,370      240,287       10,638      466,885
      Pursuant to rights
       plans                      640       22,974          805       24,737
    Trust unit rights
     incentive plan
     (non-cash) -
     exercised                      -        3,065            -        4,629
    DRIP(*), net of
     redemptions                  602       32,928          339       15,613
    Issued for acquisition
     of corporate and
     property interests
     (non-cash)                     -            -        1,633       69,062
    -------------------------------------------------------------------------
                              123,151    3,706,821      117,539    3,407,567
    Contributed Surplus
     (Trust Unit Rights
     Plan)                          -        6,305            -        3,047
    -------------------------------------------------------------------------
    Balance, end of year      123,151  $ 3,713,126      117,539  $ 3,410,614
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    (*) Distribution Reinvestment and Unit Purchase Plan


    Contributed surplus ($ thousands)                      2006         2005
    -------------------------------------------------------------------------
    Balance, beginning of year                      $     3,047  $     4,636
    Trust unit rights incentive plan
     (non-cash) - exercised                              (3,065)      (4,629)
    Trust unit rights incentive plan
     (non-cash) - expensed                                6,323        3,040
    -------------------------------------------------------------------------
    Balance, end of year                            $     6,305  $     3,047
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------


    On March 20, 2006 the Fund 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 the Fund completed a Canadian equity offering of
    10,637,500 subscription receipts at a price of $46.25 per subscription
    receipt for gross proceeds of $491,984,000 ($466,885,000 net of issuance
    costs). The subscription receipts were exchanged for an equal number of
    trust units on August 30, 2005 upon the closing of the Lyco transaction.

    On July 1, 2005 the Fund issued 1,632,516 trust units pursuant to the
    acquisition of TriLoch valued at $42.32 per trust unit, being the
    weighted average trading price of the Fund's trust units on the Toronto
    Stock Exchange during the five day trading period surrounding the
    announcement of the TriLoch transaction, for a recorded value of
    $69,088,000 ($69,062,000 net of issuance costs).

    Pursuant to the monthly Distribution Reinvestment and Unit Purchase Plan
    ("DRIP"), Canadian unitholders are entitled to reinvest cash
    distributions in additional trust units of the Fund. Trust units are
    issued at 95% of the weighted average market price on the Toronto Stock
    Exchange for the 20 trading days preceding a distribution payment date
    without service charges or brokerage fees. Eligible unitholders are also
    entitled to make optional cash payments to acquire additional trust
    units; however, the 5% discount does not apply.

    Trust units are redeemable by unitholders at approximately 85% of the
    current market price. Redemptions are limited to $500,000 during any
    rolling two calendar months. Redemption requests in excess of $500,000
    can be paid using investments of the Fund or a non-interest bearing
    instrument.

    (b) Trust Unit Rights Incentive Plan

    As at December 31, 2006 a total of 3,079,000 rights issued pursuant to
    the Trust Unit Rights Incentive Plan ("Rights Plan") were outstanding at
    an average exercise price of $48.53. This represents 2.5% of the total
    trust units outstanding of which 809,000 rights, with an average exercise
    price of $39.81, were exercisable. Under the Rights Plan, distributions
    per trust unit to Enerplus unitholders in a calendar quarter which
    represent a return of more than 2.5% of the net PP&E of Enerplus at the
    end of such calendar quarter, may result in a reduction in the exercise
    price of the rights. Results for the year ended December 31, 2006 reduced
    the exercise price of the outstanding rights by $2.02 per trust unit of
    which a $0.51 reduction is effective January 2007 and a $0.50 reduction
    is effective April 2007. Plan members have the choice to exercise rights
    using the original exercise price or a reduced strike price. In certain
    circumstances, it may be more advantageous to use the original exercise
    price as it could effectively lower the plan member's tax rate on the
    transaction.

    The Fund uses a binomial lattice option-pricing model to calculate the
    estimated fair value of rights granted under the plan. The following
    assumptions were used to arrive at the estimate of fair value:


                                                           2006         2005
    -------------------------------------------------------------------------
    Dividend yield                                        9.26%        8.97%
    Right's exercise price reduction                $     1.61  $      1.43
    Volatility                                           25.61%       21.46%
    Risk-free interest rate                               4.13%        3.70%
    Forfeiture rate                                       2.80%        4.60%
    -------------------------------------------------------------------------


    The fair value of the rights granted under the plan during 2006 ranged
    between 12% and 14% (2005 - 9% and 10%) of the underlying market price of
    a trust unit on the grant date.

    During the year the Fund expensed $6,323,000 or $0.05 per unit (2005 -
    $3,040,000 or $0.03 per unit) of unit based compensation expense using
    the fair value method. The remaining future fair value of the rights of
    $10,113,000 at December 31, 2006 (2005 - $6,380,000) will be recognized
    in earnings over the remaining vesting period of the rights. Activity for
    the rights issued pursuant to the Rights Plan is as follows:


                                     2006                      2005
    -------------------------------------------------------------------------

                                          Weighted                  Weighted
                            Number of      Average    Number of      Average
                               Rights     Exercise       Rights     Exercise
                               (000's)     Price(1)      (000's)     Price(1)
    -------------------------------------------------------------------------
    Trust unit rights
     outstanding
    Beginning of year           2,621  $     42.80        2,401  $     34.33
      Granted                   1,473        54.49        1,125        53.07
      Exercised                  (640)       35.94         (805)       30.72
      Cancelled                  (375)       46.35         (100)       37.15
    -------------------------------------------------------------------------
    End of year                 3,079        48.53        2,621        42.80
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    Rights exercisable at
     the end of the year          809  $     39.81          643  $     32.46
    -------------------------------------------------------------------------
    (1) Exercise price reflects grant prices less reduction in strike price
        discussed above.


    The following table summarizes information with respect to outstanding
    rights as at December 31, 2006. Rights vest between one and three years
    and expire between four and six years.

                                                                      Rights
                Rights                    Exercise               Exercisable
           Outstanding       Original        Price                        at
        at December 31,      Exercise  after Price  Expiry Date  December 31,
           2006 (000's)         Price   Reductions  December 31  2006 (000's)
    -------------------------------------------------------------------------
                    10    $     24.50  $     18.41         2007           10
                     1          26.40        20.43         2008            1
                    38          26.09        20.33         2008           38
                     6          27.70        22.14         2009            6
                    23          33.00        27.75         2009           23
                    19          36.00        31.13         2009           19
                   192          37.62        33.14         2009          192
                    14          40.70        36.61         2010            1
                    30          37.25        33.53         2010            8
                    58          38.83        35.51         2010           40
                   387          40.80        37.83         2010          208
                    80          45.55        42.90         2011            9
                    92          44.86        42.56         2011           16
                   143          49.75        47.85         2011           46
                   566          56.93        55.44         2011          192
                   178          56.55        55.54         2012            -
                   436          54.21        53.70         2012            -
                   320          56.00        56.00         2012            -
                   486          52.90        52.90         2012            -
    -------------------------------------------------------------------------
                 3,079    $     50.10  $     48.53                       809
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------


    (b) Basic and Diluted per Trust Unit Calculations

    Net income per trust unit has been determined based on the following:

    (thousands)                                            2006         2005
    -------------------------------------------------------------------------
    Weighted average units                              121,588      109,083
    Dilutive impact of rights                               270          288
    -------------------------------------------------------------------------
    Diluted trust units                                 121,858      109,371
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    No rights were excluded in calculating the weighted average number of
    diluted units for the year ended December 31, 2006. In 2005 we excluded
    132,511 rights because their exercise price was greater than the annual
    average unit market price of $48.08. During the last two years,
    outstanding rights were the only potential dilutive instrument.


    9.  INCOME TAXES

    (a) Enerplus Resources Fund

    The Fund is an inter-vivos trust for income tax purposes. As such, the
    Fund's income that is not allocated to the Fund's unitholders is taxable.
    The Fund intends to allocate all income to unitholders.

    For 2006, the Fund had taxable income of $588,000,000 (2005 -
    $451,000,000) or $4.81 per trust unit (2005 - $4.05 per trust unit).
    Taxable income of the Fund is comprised of dividend, royalty, interest
    and partnership income, less deductions for Canadian oil and gas property
    expense ("COGPE") and trust unit issue costs.

    The amounts of COGPE and issue costs remaining in the Fund at
    December 31, 2006 are $466,700,000 and $35,543,000 respectively (2005 -
    $466,700,000 and $40,109,000).

    Proposed Tax on Income Trusts

    On October 31, 2006, the Federal Government announced a new tax on
    publicly traded flow through entities including Enerplus. The tax would
    be applicable beginning in 2011 at the rate of 31.5% provided that
    Enerplus does not exceed the guidance provided on normal growth. Enerplus
    can issue up to $7.5 billion of new equity before 2011 without exceeding
    the guidance on normal growth. In addition, we understand that a trust
    will be able to issue equity to retire debt existing on October 31, 2006
    without eroding their safe harbour equity limits.

    At the present time, the proposed changes to tax legislation are not
    substantively enacted. Further, the timing of the enactment or the exact
    content of the proposed changes is difficult to predict. Therefore, no
    amounts in respect of this matter are reflected in the future tax
    liability presented on the balance sheet.

    If substantively enacted, the Fund would be treated as a taxable entity
    resulting in the recording of future income tax assets and liabilities.
    Enerplus' future tax liability would be adjusted to include differences
    between the accounting and tax bases of the trust's assets and
    liabilities at the substantively enacted tax rates.

    (b) Corporate Subsidiaries

    The future income tax liability on the balance sheet arises as a result
    of the following temporary differences:

    ($ thousands)                         Canadian      Foreign   2006 Total
    -------------------------------------------------------------------------
    Excess of net book value of
     property, plant and equipment
     over the underlying tax bases     $   179,770  $   183,081  $   362,851
    Asset retirement obligations           (37,667)           -      (37,667)
    Deferred hedging and other               6,963         (807)       6,156
    -------------------------------------------------------------------------
    Future income tax liability        $   149,066  $   182,274  $   331,340
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------


    ($ thousands)                         Canadian      Foreign   2005 Total
    -------------------------------------------------------------------------
    Excess of net book value of
     property, plant and equipment
     over the underlying tax bases     $   302,610  $   183,355  $   485,965
    Asset retirement obligations           (37,976)           -      (37,976)
    Deferred hedging and other              (1,925)      (3,094)      (5,019)
    -------------------------------------------------------------------------
    Future income tax liability        $   262,709  $   180,261  $   442,970
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------


    The provision for income taxes varies from the amounts that would be
    computed by applying the combined Canadian federal and provincial income
    tax rates for the following reasons:

    ($ thousands)                                          2006         2005
    -------------------------------------------------------------------------
    Income before taxes                             $   454,377  $   456,619
    -------------------------------------------------------------------------
    Computed income tax expense at the enacted
     rate of 34.88% (38.01% for 2005)               $   158,487  $   173,564
    Increase (decrease) resulting from:
    Net income attributed to the Fund                  (197,694)    (172,463)
    Non-deductible crown royalties                       11,878       30,652
    Resource allowance                                  (11,998)     (37,047)
    Amended returns and pool balances                   (21,446)      16,544
    Change in tax rate                                  (35,500)           -
    Other                                                 2,475        6,842
    -------------------------------------------------------------------------
                                                    $   (93,798) $    18,092
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    Future income tax (recovery)/expense            $  (112,034) $    15,328
    Current tax                                     $    18,236  $     2,764
    -------------------------------------------------------------------------


    The breakdown of our current and future income tax balances between our
    Canadian and Foreign operations is as follows:

    For the year ended
    December 31, 2006 ($ thousands)       Canadian      Foreign        Total
    -------------------------------------------------------------------------
    Future income (recovery)/expense   $  (113,643) $     1,609  $  (112,034)
    Current income tax                           -       18,236       18,236
    -------------------------------------------------------------------------


    For the year ended
    December 31, 2005 ($ thousands)       Canadian      Foreign        Total
    -------------------------------------------------------------------------
    Future income expense              $     8,708  $     6,620  $    15,328
    Current income tax                           -        2,764        2,764
    -------------------------------------------------------------------------


    10. FINANCIAL INSTRUMENTS

    The Fund's financial instruments presented on the balance sheet consist
    of cash, accounts receivable, deferred financial assets, other current
    assets, other assets, accounts payable, distributions payable to
    unitholders, deferred credits and long-term debt.

    The carrying value of cash, accounts receivable, deferred financial
    assets, other assets, current liabilities and the outstanding bank credit
    facility balances approximate their fair value. Other current assets are
    comprised of prepaid expenses and marketable securities and other assets
    are comprised of long-term investments. Marketable securities and long-
    term investments are carried on the balance sheet at the lower of cost
    and fair value. The fair value of the marketable securities at
    December 31, 2006 exceeded the cost of these securities by $14,493,000.
    The book value of other assets at December 31, 2006 of $48,700,000 was
    lower than the fair value of these assets by $3,231,000.

    The Fund carried US$54,000,000 of fixed rate debt. In addition, it
    carried US$175,000,000 of fixed rate debt that was converted to
    CDN$268,328,000 floating rate debt through a cross-currency swap with a
    syndicate of financial institutions. At December 31, 2006 the fair value
    of the senior unsecured notes was $62,990,000 (for the US$54,000,000
    notes) and $208,217,000 (for the US$175,000,000 notes), see Note 7.

    The estimated fair values have been determined based on available market
    information and appropriate valuation methods. The actual amounts
    realized may differ from these estimates.

    (a) Credit Risk

    Most of the Fund's accounts receivable relate to oil and natural gas
    sales and are exposed to typical industry credit risks. The Fund manages
    this credit risk by entering into sales contracts with only credit-worthy
    counterparties and reviewing its exposure to individual entities on a
    regular basis. The Fund is also exposed to certain losses in the event of
    non-performance by counterparties to derivative financial instruments.
    This credit risk is managed by the Fund by selecting financially sound
    counterparties.

    In 2006, approximately 15% of the Fund's oil and gas sales were made to a
    AA+ rated counterparty.

    (b) Interest Rate Risk

    The Fund is exposed to movements in interest rates. Long-term debt is
    comprised of both variable rate bank facilities and fixed rate senior
    notes. The Fund monitors the interest rate forward market and through the
    use of interest rate swaps along with the fixed-rate notes has fixed the
    interest rate on approximately 20% of its debt. See part (d) below.

    (c) Currency Risk

    The Fund is exposed to fluctuations in foreign currency as a result of
    its U.S. operations and the issuance of senior unsecured notes
    denominated in U.S. dollars. Through the use of a financial swap, the
    exposure on our US$175,000,000 senior unsecured notes has been converted
    to Canadian dollar debt. As well, the Fund has indirect exposure to
    fluctuations in foreign currency as crude oil sales and a portion of
    natural gas sales are based on U.S. dollar indices. We have not entered
    into any foreign currency derivatives with respect to oil and natural gas
    sales.

    (d) Derivative Financial Instruments

    The Fund uses certain derivative financial instruments to manage its
    commodity price, foreign currency and interest rate exposures. The fair
    values of these instruments are based on an approximation of the amounts
    that would have been paid to or received from counterparties to settle
    the instruments outstanding as at December 31, 2006 with reference to
    forward prices and market valuations provided by third party sources.

    The fair values of derivative financial instruments are as follows:

    Interest Rate Swaps

    The Fund has entered into interest rate swaps on $75,000,000 of notional
    debt at rates varying from 4.10% to 4.61% before banking fees that are
    expected to range between 0.55% and 1.10%. These interest rate swaps
    mature between January 2007 and January 2012. The fair value of the
    $75,000,000 interest rate swaps as at December 31, 2006 represents an
    unrealized cost of $673,000. These swaps have been designated as a cash
    flow hedge for accounting purposes.

    Cross Currency Interest Rate Swap

    The fair value of the cross currency interest rate swap related to the
    US$175,000,000 senior unsecured notes as at December 31, 2006 represents
    an unrealized cost of $65,002,000 whereas the fair value of the
    underlying debt instrument as at December 31, 2006 represents an
    unrealized gain of $60,111,000. The cross currency swap has been
    designated as a fair value hedge for accounting purposes.

    Crude Oil Instruments

    Enerplus has entered into the following financial option contracts to
    reduce the impact of a downward movement in crude oil prices. The net
    premium cost of the crude oil instruments entered into as of December 31,
    2006 is $20,108,000.

    The following table summarizes the Fund's crude oil risk management
    positions at February 13, 2007:


                                                           WTI US$/bbl
                                                    -------------------------
                                             Daily                     Fixed
                                           Volumes    Purchased        Price
                                          bbls/day          Put    and Swaps
    -------------------------------------------------------------------------
    Term
    January 1, 2007 - December 31, 2007
      Put                                    5,000  $     71.00            -
      Put                                    2,500  $     68.00            -
      Put(1)                                 2,500  $     65.70            -
      Swap(1)                                2,500            -  $     66.24
    -------------------------------------------------------------------------
    (1) Financial contracts entered into during the fourth quarter of 2006.


    Natural Gas Instruments

    Enerplus has physical and financial contracts in place on its natural gas
    production as described below. The net premium cost of the natural gas
    instruments entered into as of December 31, 2006 is $5,548,000.

    The following table summarizes the Fund's natural gas risk management
    positions at February 13, 2007:


                                                   AECO CDN$/Mcf
                                  -------------------------------------------
                           Daily                                       Fixed
                         Volumes             Purchased       Sold      Price
                        MMcf/day  Sold Call        Put        Put  and Swaps
    -------------------------------------------------------------------------
    Term
    January 1, 2007 -
     March 31, 2007
      Collar                 6.6   $  11.45   $   9.00          -          -
      Collar(1)              9.5   $   9.50   $   7.00          -          -
      Collar(1)              9.5   $  10.66   $   7.00          -          -
      Costless Collar        6.6   $  11.45   $   7.70          -          -
      Put(1)                 6.6          -   $   7.50          -          -
      Put(1)                 4.7          -   $   7.39          -          -
    January 1, 2007 -
     June 30, 2007
      Put(1)                 4.7          -   $   7.50          -          -
    April 1, 2007 -
     October 31, 2007
      Collar                 6.6   $  10.02   $   7.50          -          -
      Collar                 6.6   $   9.00   $   7.50          -          -
      Collar(1)              9.5   $   9.10   $   7.10          -          -
      Collar(1)              9.5   $   9.15   $   7.14          -          -
      Collar(1)              9.5   $   9.50   $   7.20          -          -
      Costless Collar(2)     4.7   $   8.02   $   7.17          -          -
      Costless Collar(2)     4.7   $   8.23   $   7.28          -          -
      Costless Collar(2)     4.7   $   8.20   $   7.50
      3-Way option(1)        4.7   $   9.50   $   7.75   $   5.49          -
      Put(1)                 4.7          -   $   7.28          -          -
      Swap(1)                6.6          -          -          -   $   7.60
      Swap(1)                4.7          -          -          -   $   7.33
      Swap(1)                2.4          -          -          -   $   7.84
      Swap(1)                2.4          -          -          -   $   7.96
      Swap(2)                7.1          -          -          -   $   7.17
      Swap(2)                2.4          -          -          -   $   7.70
      Swap(2)                2.4          -          -          -   $   7.53
      Swap(2)                2.4          -          -          -   $   8.35
    November 1, 2007 -
     March 31, 2008
      Collar(1)              2.4   $   9.95   $   8.00          -          -
      3-Way option(1)        4.7   $  10.50   $   8.20   $   5.70          -
      Swap(1)                4.7          -          -          -   $   8.70
    2007 - 2010
      Physical (escalated
       pricing)              2.0          -          -          -   $   2.52
    -------------------------------------------------------------------------
    (1) Financial contracts entered into during the fourth quarter of 2006.
    (2) Financial contracts entered into during the first quarter of 2007.


    Electricity Instrument

    The Fund has entered into electricity swap contracts that fix the price
    of electricity. These contracts have been designated as cash flow hedges
    and the fair value of these instruments as at December 31, 2006
    represents an unrealized gain of $1,494,000. Proceeds or costs realized
    from the electricity contracts are recognized as operating costs.

    The following table summarizes the Fund's electricity management
    positions at February 13, 2007:


                                                                      Price
    Term                                            Volumes MWh     CDN$/MWh
    -------------------------------------------------------------------------
    January 1, 2007 - December 31, 2007                     5.0  $     61.50
    January 1, 2007 - December 31, 2007                     4.0  $     62.90
    January 1, 2008 - September 30, 2008                    4.0  $     63.00
    -------------------------------------------------------------------------

    The Fund did not enter into any new electricity contracts in the
    fourth quarter of 2006.


    11. COMMITMENTS AND CONTINGENCIES

    (a) Pipeline Transportation

    Enerplus has contracted to transport natural gas with various pipelines
    totaling 35.3 MMcf/day until 2008; of this amount 5 MMcf/day extends
    until 2015. Enerplus also has a contract to transport a minimum of
    2,480 bbls/day of crude oil from the field to suitable marketing sales
    points until 2010.

    (b) Oil Sands Lease No. 24

    The Fund's acquisition of a working interest in the Joslyn project
    included the assumption of a proportionate share of certain contingent
    project debt. Effectively, this debt is comprised of principal of
    $3,150,000 plus accrued interest to December 31, 2006 of $1,379,000.
    Interest is accrued at the Bank of Canada prime business rate and is not
    compounded. The debt is contingent on attaining certain production
    hurdles with respect to development of the project. As it is still too
    early to determine if these hurdles will be satisfied, no portion of the
    contingent debt has been accrued for in the consolidated financial
    statements.

    (c) Office Lease

    Enerplus has office lease commitments for both its Canadian and U.S.
    operations that expire between November 2009 and January 2011. Annual
    costs of these lease commitments, which include rent and operating fees,
    amount to approximately $6,700,000.

    (d) Guarantees

        (i) Corporate indemnities have been provided by the Fund to all
        directors and certain officers of its subsidiaries and affiliates for
        various items including, but not limited to, all costs to settle
        suits or actions due to their association with the Fund and its
        subsidiaries and/or affiliates, subject to certain restrictions. The
        Fund has purchased directors' and officers' liability insurance to
        mitigate the cost of any potential future suits or actions. Each
        indemnity, subject to certain exceptions, applies for so long as the
        indemnified person is a director or officer of one of the Fund's
        subsidiaries and/or affiliates. The maximum amount of any potential
        future payment cannot be reasonably estimated.

        (ii) The Fund may provide indemnifications in the normal course of
        business that are often standard contractual terms to counterparties
        in certain transactions such as purchase and sale agreements. The
        terms of these indemnifications will vary based upon the contract,
        the nature of which prevents the Fund from making a reasonable
        estimate of the maximum potential amounts that may be required to be
        paid. Management believes the resolution of these matters would not
        have a material adverse impact on the Fund's liquidity, consolidated
        financial position or results of operations.

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

                                                                       Total
                             Minimum Annual Commitment Each Year   Committed
                       --------------------------------------------    after
    ($thousands) Total     2007     2008     2009     2010     2011     2011
    -------------------------------------------------------------------------
    Bank
     credit
     facility $348,520 $      - $      - $348,520 $      - $      - $      -
    Senior
     unsecured
     notes     331,254        -        -        -   53,666   66,251  211,337
    Pipeline
     commit-
     ments      28,543    6,364    5,788    2,952    2,444    2,275    8,720
    Office
     lease      20,917    6,745    6,828    6,702      592       50        -
    -------------------------------------------------------------------------
    Total
     commit-
     ments    $729,234 $ 13,109 $ 12,616 $358,174 $ 56,702 $ 68,576 $220,057
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------


    In addition, the Fund is involved in claims and litigation arising in the
    normal course of business. The resolution of these claims is uncertain
    and there can be no assurance they will be resolved in favour of the
    Fund; however, management believes the resolution of these matters would
    not have a material adverse impact on the Fund's liquidity, consolidated
    financial position or results of operations.


    12. GEOGRAPHICAL INFORMATION

    As at December 31, 2006
    ($ thousands)                           Canada         U.S.        Total
    -------------------------------------------------------------------------
    Oil and gas revenue                $ 1,323,631  $   271,693  $ 1,595,324
    Capital assets                       3,101,277      624,820    3,726,097
    Goodwill                                47,532      174,046      221,578
    -------------------------------------------------------------------------


    As at December 31, 2005
    ($ thousands)                           Canada         U.S.        Total
    -------------------------------------------------------------------------
    Oil and gas revenue                $ 1,471,473  $    79,096  $ 1,550,569
    Capital assets                       3,054,078      596,249    3,650,327
    Goodwill                                47,532      173,702      221,234
    -------------------------------------------------------------------------


    13. EVENTS SUBSEQUENT TO DECEMBER 31, 2006

    On January 31, 2007, Enerplus closed the acquisition of gross overriding
    royalty ("GORR") interests in the Jonah natural gas field in Wyoming for
    total consideration of US$52,000,000 (CDN$60,000,000). The full amount of
    the purchase price will be recorded to PP&E in 2007. This represents a
    GORR of approximately 0.5% on about 650 producing natural gas wells in
    the Jonah field.


    5 YEAR DETAILED STATISTICAL REVIEW

    ($ thousands,
    except per
    unit amounts)       2006        2005        2004        2003        2002
    -------------------------------------------------------------------------
    Financial
    Oil and gas
     sales(1)     $1,569,487  $1,413,734  $  989,266  $  890,011  $  621,450
    Cash
     distributions
     to
     unitholders     614,340     498,205     423,311     372,576     237,621
    Per unit            5.04        4.47        4.20        4.29        3.25
    Net income       544,782     432,041     258,316     248,046     116,621
    Per unit            4.48        3.96        2.60        2.88        1.62
    Total net
     capital
     expenditures    526,387   1,010,549     813,636     312,073     361,702
    Total assets   4,203,804   4,130,623   3,180,748   2,661,765   2,517,976
    Long-term
     debt, net of
     cash            679,650     649,825     584,991     257,701     361,011
    Net debt/cash
     flow ratio         0.8x        0.8x        1.1x        0.6x        1.2x
    -------------------------------------------------------------------------
    Average
     Benchmark
     Pricing
    AECO
     natural gas
     (per Mcf)    $     6.99  $     8.48  $     6.79  $     6.70  $     4.07
    NYMEX
     natural gas
     (US$ per
     Mcf)               7.26        8.55        6.09        5.54        3.25
    WTI crude
     oil (US$
     per bbl)          66.22       56.56       41.40       31.04       26.08
    CDN$/US$
     exchange
     rate               0.88        0.83        0.77        0.72        0.64
    -------------------------------------------------------------------------
    ($ per BOE
     except
     percentage
     data)
    -------------------------------------------------------------------------
    Oil and Gas
     Economics
    Net royalty
     rate                19%         19%         21%         20%         21%
    Weighted
     average
     price(2)     $    50.23  $    52.36  $    40.90  $    36.94  $    27.49
    Hedging(3)         (1.10)      (4.90)      (3.50)      (1.81)      (0.38)
    -------------------------------------------------------------------------
    Weighted
     average
     price(1)          49.13       47.46       37.40       35.13       27.11
    Net royalty
     expense            9.36       10.21        8.40        7.51        5.75
    Operating
     expense            8.02        7.45        7.14        6.73        5.86
    -------------------------------------------------------------------------
    Operating
     netback           31.75       29.80       21.86       20.89       15.50
    General and
     adminis-
     trative
     expense(3)         1.71        1.28        1.06        0.95        0.70
    Management fee         -           -           -        2.29        0.94
    Interest
     expense, net
     of interest
     and other
     income             0.95        0.51        0.68        0.74        0.78
    Foreign
     exchange(3)       (0.02)       0.13       (0.01)       0.08           -
    Taxes               0.70        0.31        0.24        0.26        0.23
    Restoration
     and
     abandonment
     cash costs         0.37        0.27        0.25        0.26        0.20
    -------------------------------------------------------------------------
    Cash flow
     before
     changes in
     non-cash
     working
     capital      $    28.04  $    27.30  $    19.64  $    16.31  $    12.65
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    (1) Net of commodity derivative instruments and transportation.
    (2) Net of transportation and before commodity derivative instruments.
    (3) Does not include non-cash portion of expense.


    OPERATIONAL STATISTICS

    The following information outlines Enerplus' gross average daily
production volumes for the years indicated and our Company interest reserves
based upon forecast prices and costs at December 31 each year.



                      2006(1)     2005(1)     2004(1)     2003(1)       2002
    -------------------------------------------------------------------------

    Daily
     Production
    Oil Sands            n/a         n/a         n/a         n/a         n/a
    Crude Oil
     (bbls/day)       36,134      29,315      25,550      24,597      23,288
    NGLs (bbls/day)    4,483       4,689       4,398       4,666       4,410
    Natural Gas
     (Mcf/day)       270,972     274,336     271,091     240,907     210,517
    -------------------------------------------------------------------------
    BOE per day       85,779      79,727      75,130      69,414      62,784
    -------------------------------------------------------------------------

    Proved
     Reserves
    Oil Sands          8,730       9,453         n/a         n/a         n/a
    Crude Oil
     (Mbls)          125,048     129,745     104,408      91,063     105,247
    NGLs (Mbbls)      12,690      13,084      12,776      13,571      16,035
    Natural Gas
     (MMcf)          920,061     965,776     971,598     867,204   1,001,913
    -------------------------------------------------------------------------
    MBOE             299,812     313,245     279,117     249,168     288,267
    -------------------------------------------------------------------------

    Probable
     Reserves(2)
    Oil Sands         47,998      43,700      47,747         n/a         n/a
    Crude Oil
     (Mbls)           34,421      31,567      26,783      27,807      16,725
    NGLs (Mbbls)       3,777       3,539       3,292       3,742       2,319
    Natural Gas
     (MMcf)          344,025     342,518     295,698     284,096     138,789
    -------------------------------------------------------------------------
    MBOE             143,533     135,892     127,105      78,898      42,175
    -------------------------------------------------------------------------

    Proved Plus
     Probable
     Reserves
    Oil Sands         56,728      53,153      47,747         n/a         n/a
    Crude Oil
     (Mbls)          159,469     161,312     131,191     118,870     121,972
    NGLs (Mbbls)      16,467      16,623      16,068      17,313      18,354
    Natural Gas
     (MMcf)        1,264,086   1,308,294   1,267,296   1,151,300   1,140,702
    -------------------------------------------------------------------------
    MBOE             443,345     449,137     406,222     328,066     330,442
    -------------------------------------------------------------------------

    Reserve Life
     Index(3)
    Without Oil
     Sands:
    Proved (years)       9.8         9.6        10.1        10.6        12.0
    Proved Plus
     Probable
     (years)            12.2        12.0        12.4        13.3        13.8
    -------------------------------------------------------------------------

    With Oil Sands:
    Proved (years)      10.1         9.9        10.1        10.6        12.0
    Proved Plus
     Probable
     (years)            14.0        13.5        14.0        13.3        13.8
    -------------------------------------------------------------------------

    (1) 2003 - 2006 reserve information reflects NI 51-101 reporting
        methodology. Year 2002 information has not been restated for
        NI 51-101.
    (2) Probable reserves for year 2002 have been risked by 50%.
    (3) The Reserve Life Indices (RLI) are based upon year-end proved plus
        probable reserves (established reserves for the year 2002) divided by
        the following year's proved and proved plus probable production
        volumes as determined in the independent reserve engineering reports
        for 2003 forward and management's estimate for 2002.


    This news release 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 news
release 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 future oil and gas
reserves; the volume and product mix 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, 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 news
release 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 news
release 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 public disclosure documents (including, without
limitation, those risks identified in this news release and in the Fund's
annual information form).
    The forward-looking information and statements contained in this news
release speak only as of the date of this news release, 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.

    Gordon J. Kerr
    President & Chief Executive Officer

For further information: Enerplus Resources Fund, The Dome Tower, 3000,
333-7th Avenue SW, Calgary, Alberta T2P 2Z1, Tel (403) 298-2200, Fax (403)
298-2211, Toll Free (800) 319-6462, www.enerplus.com
To request a free copy of this organization's annual report, please go to
http://www.newswire.ca and click on Tools for Investors.

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