Enerplus is a North American energy producer with a portfolio of oil and gas assets in resource plays that offer organic growth potential with superior economics.

Enerplus announces 2007 year end results and reserves information

February 28, 2008
    TSX: ERF.UN
    NYSE: ERF

    CALGARY, Feb. 28 /CNW/ - Enerplus Resources Fund ("Enerplus") is pleased
to announce our financial and operating results for the year ended
December 31, 2007.

    STRATEGIC EXECUTION:

    -   On February 13, 2008 we acquired Focus Energy Trust creating an
        entity with a combined market capitalization of approximately
        $7.6 billion and production of approximately 100,000 BOE/day
    -   In the second quarter of 2007, we completed the acquisition of an
        operated oil sands steam assisted gravity drainage ("SAGD") project
        with production potential of 30,000 to 40,000 bbls/day of bitumen
        through the purchase of a 100% working interest in the Kirby lease
        for a total purchase price of $203.1 million
    -   We expanded our U.S. asset base through the acquisition of a gross
        overriding royalty interest in the Jonah natural gas field in Wyoming
        for total consideration of approximately $61.0 million in January
        2007
    -   We maintained a strong balance sheet with a net debt to trailing 12
        month cash flow ratio of 0.8x at December 31, 2007 to support
        further potential acquisitions and growth

    FINANCIAL HIGHLIGHTS:

    -   Cash flow totaled $868.5 million during 2007, essentially flat over
        2006
    -   Cash distributions payable to unitholders remained constant at $0.42
        per trust unit for the past 28 months resulting in annual cash
        distributions paid of $5.04 per trust unit
    -   Our payout ratio increased slightly to 74% from 71%
    -   On April 10, 2007 we completed an equity offering of 4.25 million
        trust units in conjunction with the Kirby acquisition raising gross
        proceeds of $210.6 million
    -   Subsequent to year-end, we increased our bank credit facility from
        $1.0 billion to $1.4 billion in conjunction with the Focus
        transaction

    OPERATIONAL HIGHLIGHTS:

    -   Daily production averaged 82,319 BOE/day essentially on target with
        our third quarter guidance of 82,500 BOE/day
    -   Development capital spending was $387.2 million
    -   We drilled 252 net wells with a 99% success rate
    -   Operating costs were $9.12/BOE for 2007, slightly below our third
        quarter guidance of $9.20/BOE
    -   General and administrative ("G&A") expenses were $2.26/BOE, 6% lower
        than our guidance of $2.40/BOE

    RESERVES:

    -   We replaced 90% of 2007 production through reserve additions from
        development capital spending and acquisitions on a proved plus
        probable basis
    -   Proved plus probable reserves decreased slightly by 1% to 440.2 MMBOE
        and proved reserves decreased 3% to 289.9 MMBOE
    -   Proved plus probable finding and development costs ("F&D") on our
        conventional oil and gas activities were $19.97/BOE for the year and
        when we include our oil sands activities, F&D costs were $20.33/BOE
        (both measures include future development capital)
    -   Proved plus probable finding, development and acquisition ("FD&A")
        costs on our conventional oil and gas activities were $19.79/BOE for
        the year and when we include our oil sands activities, FD&A costs
        were $27.69/BOE, primarily as a result of the Kirby acquisition which
        has no reserves assigned to it at this time
    -   3 year FD&A costs were $19.57/BOE on our conventional assets and
        $20.69/BOE including oil sands
    -   We added 6.8 million barrels of proved plus probable reserves
        relating to our Joslyn SAGD project
    -   Our reserve Life Index ("RLI") continues to be one of the longest in
        the sector at 14.8 years on a proved plus probable basis and
        10.3 years on a proved basis

    SELECTED FINANCIAL AND OPERATING HIGHLIGHTS

    Readers are referred to "Information Regarding Disclosure in this News
Release and Oil and Gas Reserves, Resources and Operational Information" and
"Notice to U.S. Readers" at the end of this news release for information
regarding the presentation of the financial and operational information in
this news release.

    FINANCIAL HIGHLIGHTS
    For the years ended December 31,                       2007         2006
    -------------------------------------------------------------------------
    Financial (000's)
      Cash Flow from Operating Activities           $   868,548  $   863,696
      Cash Distributions to Unitholders(1)              646,835      614,340
      Cash Withheld for Acquisitions
       and Capital Expenditures                         221,713      249,356
      Net Income                                        339,691      544,782
      Debt Outstanding (net of cash)                    724,975      679,650
      Development Capital Spending                      387,165      491,226
      Acquisitions                                      274,244       51,313
      Divestments                                         9,572       21,127

    Financial per Unit(2)
      Cash Flow from Operating Activities           $      6.80  $      7.10
      Cash Distributions to Unitholders(1)                 5.07         5.05
      Cash Withheld for Acquisitions
       and Capital Expenditures                            1.73         2.05
      Net Income                                           2.66         4.48

      Payout Ratio(3)                                       74%          71%

    Selected Financial Results per BOE(4)
      Oil & Gas Sales(5)                            $     50.48  $     50.23
      Royalties                                           (9.49)       (9.47)
      Financial Contracts                                  0.45        (1.10)
      Operating Costs                                     (9.11)       (8.02)
      General and Administrative                          (1.98)       (1.71)
      Interest and Foreign Exchange                       (1.43)       (0.93)
      Taxes                                               (0.77)       (0.59)
      Restoration and Abandonment                         (0.54)       (0.37)
    -------------------------------------------------------------------------
    Cash Flow from Operating Activities before
     changes in non-cash operating working capital  $     27.61  $     28.04
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    Weighted Average Number of Trust
     Units Outstanding (thousands)                      127,691      121,588
    Debt/Trailing 12 Month Cash Flow Ratio                 0.8x         0.8x
    -------------------------------------------------------------------------



    OPERATING HIGHLIGHTS
    For the years ended December 31,                       2007         2006
    -------------------------------------------------------------------------

    Average Daily Production
      Natural gas (Mcf/day)                             262,254      270,972
      Crude oil (bbls/day)                               34,506       36,134
      NGLs (bbls/day)                                     4,104        4,483
    Total (BOE/day)                                      82,319       85,779

    % Natural gas                                           53%          53%

    Average Selling Price(5)
      Natural gas (per Mcf)                         $      6.45  $      6.81
      Crude oil (per bbl)                           $     65.11  $     61.80
      NGLs (per bbl)                                $     51.35  $     50.90
      Per BOE                                       $     50.48  $     50.23
      US$ exchange rate                                    0.93         0.88

    Net Wells drilled                                       252          361
    Success Rate                                            99%          99%

    Proved Reserves (MMBOE)(6)                            289.9        299.8
    Probable Reserves (MMBOE)(6)                          150.3        143.5
    -------------------------------------------------------------------------
    Total Proved plus Probable Reserves (MMBOE)(6)        440.2        443.3

    Conventional Finding & Development Cost/BOE(7)  $     19.97  $     27.48
    Conventional Finding, Development
     & Acquisition Cost/BOE(7)                      $     19.79  $     25.41

    Total Finding & Development
     Cost/BOE including oil sands(7)                $     20.33  $     22.87
    Total Finding, Development & Acquisition
     Cost/BOE including oil sands(7)                $     27.69  $     23.19

    Recycle Ratio (conventional)(7)                        1.6x         1.2x

    Proved Reserve Life Index (years)(8)                   10.3         10.1
    Proved plus Probable Reserve Life Index (years)(8)     14.8         14.0
    -------------------------------------------------------------------------
    (1) Calculated based on distributions paid or payable. Cash distributions
        to unitholders per unit will not correspond to actual distributions
        of $5.04 per trust unit 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 including
        future development capital. For additional details and information
        see "Finding and Development Costs ("F&D")" and "Finding, Development
        and Acquisition Costs ("FD&A")" and "Recycle Ratio" in this news
        release.
    (8) Based upon year-end company interest reserves and the following
        year's estimated production contained in the independent reserve
        reports.

    Trust Unit Trading Information

                                                   TSX - ERF.un   NYSE - ERF
    -------------------------------------------------------------------------
                                                          ($CDN)        ($US)
    High                                             $    53.70   $    50.75
    Low                                              $    38.00   $    38.06
    Close                                            $    39.87   $    40.05
    Volume (000's)                                       96,898       54,192
    -------------------------------------------------------------------------

    COMPLETION OF STRATEGIC ACQUISITION OF FOCUS ENERGY TRUST

    On February 13, 2008, Enerplus completed the acquisition of Focus Energy
Trust ("Focus") resulting in improved asset quality, organizational strength
and efficiency and financial position for the combined entity going forward.
Focus adds approximately 21,000 BOE/day of production to Enerplus
(18,000 BOE/day annualized from closing date), weighted approximately 90% to
natural gas, coming from two principal properties - the Shackleton shallow
natural gas property in southwest Saskatchewan and the Tommy Lakes deep tight
gas property in British Columbia.
    Over 90% of the Focus employees, excluding executives, have joined the
Enerplus organization providing continuity in the management of the Focus
assets. The nature and quality of the Focus assets is anticipated to also
position us for improved operating metrics. With a greater percentage of
operated properties and concentrated resource plays the merger will allow us
to concentrate our attention on large, high impact areas.
    As a result of the acquisition, Enerplus is now one of the top shallow
natural gas producers in Canada and will have the ability to combine technical
and execution expertise with purchasing power over a significant asset base.
We believe the Shackleton property offers more than 1,500 future drilling
locations representing 4 to 5 years of low risk repeatable development
opportunities. We expect some cost saving synergies and increased ability to
control the pace of development in the area especially on our previously non-
operated interests. We also believe Shackleton has potential for increased
well density, additional compression, play extension through step-out drilling
on 240,000 net acres of undeveloped land and recompletion potential from
additional Milk River formation intervals. We believe the Tommy Lakes property
has more than 50 future drilling locations representing at least three years
of development potential.
    The following table summarizes Focus' company interest reserves at
December 31, 2007 as evaluated by Paddock Lindstrom & Associates Ltd.
utilizing the year end price and cost forecasts of Sproule Associates Limited
("Sproule"), our Canadian conventional independent reserves evaluators. Focus'
total reserves at December 31, 2007 increased over 2006 levels by
approximately 1.1 million BOE effectively replacing 114% of produced reserves
as a result of capital development activities.

    Focus Energy Trust Reserve Summary (company interest using forecast
    prices and costs)

                             Light &             Natural
                              Medium     Total       Gas   Natural
                                 Oil       Oil   Liquids       Gas     Total
                              (Mbbls)   (Mbbls)   (Mbbls)    (MMcf)    (MBOE)
    -------------------------------------------------------------------------
    Total Reserves at
     Dec. 31, 2006             5,248     5,248     3,267   450,966    83,676
    -------------------------------------------------------------------------
    Proved developed
     producing                 3,500     3,500     1,774   196,111    37,959
    Proved developed
     non-producing                 -         -        15     1,705       299
    Proved undeveloped           127       127       956   142,830    24,888
    -------------------------------------------------------------------------
    Total Proved Reserves      3,627     3,627     2,745   340,646    63,146
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    Probable                     939       939       834   118,948    21,598
    Total Proved plus Probable
     Reserves at
     Dec. 31, 2007             4,566     4,566     3,579   459,594    84,744
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    OPERATIONS

    Production

    Daily production averaged 82,319 BOE/day for 2007 approximately 4% lower
than 2006 average daily volumes. In the third quarter we adjusted our
production guidance to 82,500 BOE/day reflecting significantly lower capital
spending on development activities from 2006 levels as well as lower initial
production rates on our Bakken oil infill drilling program and higher than
expected downtime and turnaround activity during the year.
    Our exit rate production was roughly 4% lower than expected at
79,800 BOE/day as compared to our guidance of 83,000 BOE/day due to the
previously announced Giltedge fire, capital project delays and additional
unexpected downtime. Approximately 2,000 BOE/day was shut in as a result of a
fire at the Giltedge oil property in late November. We expect the facility to
be back to full production by mid-2008. Property and business interruption
insurance will mitigate most of the costs resulting from the Giltedge fire.
Delayed tie-ins primarily on non-operated capital projects at year-end and
additional line breaks at our non-operated Mitsue field also impacted our exit
production by 1,200 BOE/day. While the majority of the capital for these
projects was spent in 2007, we do not expect production until early March. We
also expect production at Mitsue to be back on line by the end of March.

    Development Activities

    Our capital spending program during 2007 totaled $387.2 million.
Approximately two thirds of our conventional development program was invested
in crude oil projects both in the U.S. and Canada where we realized the
highest rates of return given strong crude oil prices through 2007. In total,
we drilled 252 net wells with a 99% success rate and brought on approximately
15,700 BOE/day of new initial production at an average on-stream cost of
$22,150/BOE/day, excluding oil sands spending.
    We continued to invest in activities such as land, seismic and oil sands
which did not add immediate cash flow and reserves, but positioned us to add
production and reserves in the future. Approximately 20% of our capital
expenditures, or $75 million, was spent on these types of activities during
2007.

    2007 Production and Capital Spending

                   Average                                           Finding
                     Daily  Drilling   Initial             Capital   & Devel-
                   Product- Activity   Product-  Capital   Efficie-   opment
                       ion       Net       ion  Spending       ncy     Cost/
    Play Types     BOE/day     Wells   BOE/day       $MM $/BOE/day     BOE(1)
    -------------------------------------------------------------------------
    Crude Oil
     Waterfloods    16,576        20     2,200  $     54  $ 24,550  $  19.78
    Shallow Gas &
     Coalbed
     Methane        14,696       155     2,500        39    15,600       n/a
    Bakken Oil      11,132        24     4,700       106    22,550     16.30
    Deep Tight Gas   8,772         6     1,700        35    20,600     20.30
    Other
     Conventional
     Oil & Gas      31,143        47     4,600       114    24,800     12.10
    -------------------------------------------------------------------------
    Total
     Conventional   82,319       252    15,700  $    348  $ 22,150  $  19.97
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    Oil Sands            -       n/a         -        39         -     21.16
    -------------------------------------------------------------------------
    Total Company   82,319       252    15,700  $    387  $ 24,650  $  20.33
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    (1) See "Finding and Development Costs ("F&D") and Finding, Development
        and Acquisitions Costs ("FD&A")" in this news release for additional
        information

    Resource Plays

    Crude Oil Waterfloods
    ---------------------

    Crude oil waterfloods represented approximately 20% of our 2007
production and 23% of our proved plus probable reserves at year-end. Enerplus
operates over 80% of our waterfloods which are located throughout the Western
Canadian Sedimentary Basin. We invested $54 million on waterflood resource
plays in 2007, drilling 20 new wells in Virden, Joarcam, Pembina and Silver
Heights resulting in an overall finding and development cost of $19.78/BOE.
Increased optimization at our Gleneath, Giltedge, Medicine Hat Glauc C and
Mitsue properties, combined with the success of the drilling program, resulted
in capital efficiencies improving markedly year-over-year, from
$41,250/BOE/day in 2006 to $24,550/BOE/day.
    We expect to see a significant increase in capital investment to
$105 million in 2008 with plans for 49 new wells, increased optimization at
our Cadogan property and two new surfactant pilots at Giltedge. Continued high
oil prices and success in key development programs has laid the ground work
for larger drilling programs at Pembina, Joarcam and Virden. We will also be
rebuilding the Giltedge facility after the fire in November 2007 and expect it
to be back to full production by mid-2008.

    Shallow Natural Gas and CBM
    ---------------------------

    Shallow natural gas and coal bed methane ("CBM") represented 18% of our
daily production volumes in 2007 and 21% of our total proved plus probable
reserves at year-end. Shallow gas and CBM spending was reduced by
approximately 60% last year as weak natural gas prices and increasing costs
eroded returns in this play type. We invested only $39 million and
concentrated our spending on our most attractive shallow gas opportunities in
the Bantry, Medicine Hat Sun Valley, Verger and Shackleton/Sceptre areas.
Reserve additions were offset by technical disappointments at Hanna Garden
which made overall finding and development costs misrepresentative on a one
year basis for the overall program. Drilling activity was significantly
reduced with only 155 net wells drilled in 2007 compared to 249 in 2006. This
high-graded program resulted in a significant improvement in capital
efficiencies year-over-year from $29,400/BOE/day in 2006 to $15,600/BOE/day.
    In 2008 we expect to see a significant increase in total spending given
improvements in costs and natural gas prices, the addition of the Focus
Shackleton property and the relatively limited impact from the royalty changes
in Alberta on our shallow gas program. We are planning to drill approximately
371 net wells with total spending of $128 million. Shallow gas activities will
be focused at our properties in Shackleton where we are infill drilling to
increase well density from 4 to 8 wells per section and at Bantry and Milk
River prospects in Medicine Hat and Fox Valley where we are down spacing to
16 wells per section. Approximately 73% of our total conventional drill wells
in 2008 will be shallow gas wells.

    Bakken Oil
    ----------

    The Sleeping Giant Bakken oil resource play in Montana produced
approximately 13% of our average daily production in 2007 and represented 9%
of our proved plus probable reserves at December 31, 2007. Capital investment
activity remained high throughout 2007 with $106 million invested to complete
the initial two wells per section drilling program across the core of the
field, drill 25 third well per section wells, complete 23 refracs and expand
the resource outside of the core area. Overall results remained attractive on
the third well per section drilling given recoverable reserves of over
200,000 BOE despite lower than anticipated initial production rates that
averaged 200 BOE/day versus our original expectation of 300 BOE/day. Refracs
continued to provide both incremental oil production and reserve recovery of
approximately 50 BOE/day and 77,000 BOE, respectively. Our expansion efforts
to date outside the core Bakken area have been unsuccessful with two
uneconomic Red River wells and uneconomic extension wells northwest and
southeast of the core field area. In total we spent $14 million on expansion
efforts including associated seismic costs. We continue to evaluate these
early results and other potential outside the core Bakken area.
    Our activities generated positive proved plus probable reserve additions
of 10 million BOE, offset by 5 million BOE of negative revisions. The
additions were primarily associated with our third wells per section and
refrac program, while negative revisions were related to our extension areas
and a change in recovery factor for solution gas. Since the acquisition of
this property in 2005, we have added over 12 million BOE of proved plus
probable reserves on the initial 30 million BOE acquired. Our finding and
development costs in this resource play remained attractive at $16.30 per
barrel with an on-stream cost of $22,550/BOE/day.
    In 2008 we plan to complement our ongoing capital program with a focused
optimization effort and will spend approximately $47 million. Optimization
will include automating pump controls, managing fluid levels and improving our
field downtime. We expect to complete the third well per section drilling
program in the core areas of the field (approximately 6 wells) and continue
the refrac program (24 refracs). Efforts to understand and evaluate enhanced
oil recovery projects ("EOR") are also underway given our expectations as to
the potential recovery beyond primary depletion. Other activities will include
determining the viability of a fourth well per section along the lease lines,
potential EOR piloting and further work in expanding areas outside the core
Bakken play.

    Deep Tight Gas
    --------------

    Deep tight gas represented approximately 11% of our average daily
production in 2007 and 7% of our year-end proved plus probable reserves. These
play types includes mostly non-operated multi-zone deep tight gas plays such
as Cardium, Nikannassin, Montney, Bluesky and Halfway zones as well as many
others. In 2007, we completed our first significant operated development
success with a $14 million deep gas drilling project at Ansell. We added
3.5 million BOE of new proved plus probable reserves by drilling 4 gross wells
and expanded gas gathering and compression facilities. These wells are
currently averaging 2 MMcf/day gross with an average 45% working interest. The
success at Ansell was partially offset by a 1.3 million BOE negative proved
plus probable reserve revision at our non-operated Benjamin property
associated with a proved undeveloped location as the operator elected not to
drill the well due to lower gas prices and reallocation of capital to other
projects. The majority of the $35 million we invested in 2007 continued to be
in the non-operated areas of Deep Basin, Elmworth Wapiti, Pine Creek and
Copton.
    Through the Focus transaction we added the Tommy Lakes property which
will be our largest operated deep tight gas field currently producing
approximately 6,000 BOE/day. Overall spending in 2008 is currently anticipated
to increase to $53 million for Deep Gas, mainly as a result of the addition of
this property with plans to spend approximately $20 million at Tommy Lakes
(post close), and the remainder primarily in Ansell and the non-operated areas
of Deep Basin, Elmworth, Wapiti and Copton.

    Other Conventional Oil & Gas
    ----------------------------

    Other conventional oil and gas properties comprised approximately 38% of
our total average daily production and 25% of our year-end proved plus
reserves. This includes a diversified portfolio of both oil and gas projects
across western Canada which are smaller in nature and which we operate
approximately 70%. Our capital investment was reduced in this play type by 19%
year-over-year primarily due to lower capital spending in our non-operated
properties and a shift to more spending in our Bakken oil play. Despite
efforts to high grade our program, we did not see the high impact wells that
were attributable to this category in 2006 and our activities at two main
projects where we spent approximately $15 million, Kantah and Tatagwa, did not
produce the results expected. In total, we spent $114 million on capital
development activities in this category in 2007.
    Going forward in 2008 we expect to spend $142 million on a variety of oil
and gas projects, both operated ($100 million) and non-operated ($42 million).
We will spend just under $20 million on operated oil optimization activities
and equipment upgrades at Bantry North and South and almost $20 million at our
oil properties in southeast Saskatchewan, primarily on horizontal drilling in
an attempt to extend the boundaries of those assets. The remainder of the
operated capital will be spent on a variety of smaller prospects in Alberta
and British Columbia.

    Oil Sands
    ---------

    We invested $39 million in our oil sands portfolio in 2007 which includes
our operated Kirby SAGD project, our non-operated SAGD and mine projects at
Joslyn and our joint venture and equity ownership with Laricina Energy Ltd.

    Kirby:
    ------

    The most significant oil sands activity in 2007 was the acquisition of
the Kirby lease, a 100% working interest, operated SAGD project for
$203 million with potential production capacity through staged development of
30,000 to 40,000 bbls/day of bitumen. The Kirby oil sands leases cover a large
land block of 43,360 gross acres (over 67 sections of land) in a highly
prospective area in the heart of the Athabasca oil sands fairway near several
other major SAGD development projects currently on production. While the Kirby
lease does not have current production or proved plus probable reserves, an
independent engineering assessment conducted by GLJ Petroleum Consultants Ltd.
("GLJ") effective December 31, 2007 indicates a "best estimate" of contingent
resources of 244 million barrels of bitumen. Our initial development plans
include a 10,000 bbl/day SAGD project starting in 2011/2012 with further
expansion capability to a total of 30,000 to 40,000 bbls/day of gross bitumen
production over time.
    Our oil sands strategy is to be a best in class SAGD operator given the
fit with our business model, the availability of resource and link to the
conventional business. We believe Kirby is an attractive first project given
the reservoir quality, lack of thief zones, proximity to markets and
infrastructure, and expandability. We have added to our capabilities with a
new Vice President, Oil Sands and seasoned management and staff. Our capital
spending in 2007 totaled $2 million and we have begun work on our first winter
delineation drilling program at the Kirby lease and are targeting 70 new core
holes and testing for water sources and disposal zones on the lease. We expect
to use this new information in support of a 10,000 BOE/day SAGD project
application in late fall of 2008. Our original cost estimates of $365 million
associated with the development of the 10,000 bbl/day project will be updated
later in the year as work progresses on the regulatory application. We plan to
spend approximately $50 million in 2008 on our core hole drilling program and
the regulatory application. The following outlines our current expectations as
to the key milestones associated with the development of the Kirby lease:

    -   2007/2008 - Winter drilling program, stakeholder consultation and
                    work on regulatory applications
    -   Fall 2008 - Regulatory application filed
    -   Fall 2009 - Regulatory approval anticipated
    -   Late 2011 - First steam
    -   Mid-2012 - First production
    -   2013 - Full production of 10,000 bbls/day

    Joslyn:
    -------

    We continued to invest in the Joslyn lease throughout 2007 spending
$18 million on the Joslyn SAGD project and $11 million on the Joslyn mining
development. Our activity included additional delineation spending, regulatory
work, SAGD facility upgrades and other costs.
    Results of the 2006-07 winter drilling program continue to indicate a
growing resource on the Joslyn lease. As a result of the program, we obtained
new reserve and contingent resource estimates in a report from GLJ which
utilized results from an updated Norwest mining report. Effective December 31,
2007 GLJ added 6.8 million barrels of probable bitumen reserves and increased
contingent resource estimates net to Enerplus. A key factor in the increased
contingent resource estimates for the bitumen was a change from 12:1 total
volume to bitumen in place ratio ("TV:BIP") to 15:1 TV:BIP ratio. TV:BIP
measures the total volume of material (dirt, sand and bitumen) relative to the
volume of bitumen in place; it considers how much dirt must be removed to
access the bitumen deposit and the ore grade, or the richness of the deposit.
The higher costs associated with mining at higher TV:BIP ratios is more than
offset by higher commodity prices. While the operator is still determining the
optimal lease development plan for the lease, should the mining area expand we
would expect higher overall recoveries from the lease given the higher
recovery rate for mining versus SAGD.
    The Joslyn lease currently has two key mining areas (North and South) and
a SAGD area with expansion potential. The existing SAGD project continues to
run behind expectations. The operator does not expect to drill any new well
pairs or achieve commercial production on the project until at least 2009
pending continued improvement in well performance. Production volumes at
year-end from the SAGD project were approximately 2,400 bbls/day gross,
(360 bbls/day net) to Enerplus. We expect the North mine regulatory
application to be approved in the second half of 2008. The extent of the South
mine and expansion potential for SAGD is currently being evaluated and we
expect to finalize these plans in 2008 with the operator. We are also
expecting to finalize an expanded joint operating agreement and our downstream
marketing plans in 2008. A South mine regulatory application is expected to be
made once lease development plans have been determined. As the lease
development plans have not been finalized and significant engineering work is
underway, we do not have any current estimates of the future capital
requirements associated with the lease. We expect to report capital spending
estimates once the lease development plan is complete. There are no proved or
probable reserves associated with the Joslyn mining development included in
our year-end reserves report.

    Joslyn Oil Sands Reserves & Resource Estimates
    (based upon Enerplus working interests, million barrels of bitumen)

    The following table outlines the reserves and resources associated with
the Joslyn lease as estimated by GLJ utilizing the Norwest mining report
received late in 2007. The improved estimates at December 31, 2007 indicate
that the lease could support up to 240,000 bbls/day of gross production
(36,000 bbls/day net) including both SAGD and mining activities.

                                         Mine Contingent  Total P+P Reserves
                    SAGD Proved plus            Resource        & Contingent
                   Probable Reserves     "Best" Estimate   Resource Estimate
                                (GLJ)               (GLJ)               (GLJ)
                             (MMbbls)            (MMbbls)            (MMbbls)
    -------------------------------------------------------------------------
    2006 Year-End               56.7                 223                 280
    -------------------------------------------------------------------------
    2007 Year-End:
      Full mine with
       10,000 bbl/day
       SAGD                     11.0                 359                 370
    -------------------------------------------------------------------------
      Smaller mine with
       25,000 bbl/day
       SAGD                     63.5                 252                 315
    -------------------------------------------------------------------------
      Year-over-Year
       Change          -45.7 to +6.8          +29 to 136           +35 to 89
    -------------------------------------------------------------------------

    Mine estimates are contingent resource estimates using a 12:1 TV:BIP
ratio at December 31, 2006 and a 15:1 TV:BIP ratio at December 31, 2007. There
is no certainty that it will be commercially viable to produce any portion of
the resources. For information on contingent resource estimates and the risks
and uncertainties associated therewith, see "Information Regarding Disclosure
in this News Release and Oil and Gas Reserves, Resources and Operational
Information" at the conclusion of this news release.

    Laricina
    --------

    In 2005, we formed a joint venture with Laricina Energy Ltd., a private
oil sands company focused on SAGD development in the Athabasca oil sands
fairway. As part of this joint venture, Enerplus swapped a 1% working interest
in the Joslyn lease for approximately 20% equity value in Laricina, including
an area of mutual interest agreement which has now expired. Over the past two
years, we have participated in four land acquisitions and in 2007 invested
approximately $8 million in an effort to delineate the potential on these
lands. We believe the value of our equity investment has appreciated
significantly since 2005 and based upon a recent financing by Laricina, we
would value our investment at approximately $140 million and own approximately
12% of the total shares outstanding.

    2008 PRODUCTION AND CAPITAL SPENDING PLANS

    On December 3, 2007, Enerplus announced pro-forma 2008 guidance assuming
the merger between Enerplus and Focus occurred January 1, 2008. The actual
closing date of the merger was February 13, 2008, and therefore we have
revised our 2008 guidance to reflect the combined results of Enerplus and
Focus from that date forward.
    We anticipate that our average daily production volumes will increase
significantly in 2008 to approximately 98,000 BOE/day representing a
production estimate of approximately 80,000 BOE/day from Enerplus and a pro-
rated estimate of 18,000 BOE/day from the Focus assets. Given the timing of
our capital development program, we expect to exit 2008 with production of
approximately 100,000 BOE/day.
    We also intend to significantly increase our capital spending plans in
2008 as a result of the Focus transaction and our investment in the oil sands.
We currently expect to spend approximately $580 million in total with
approximately $475 million directed to conventional oil and gas with a slight
bias to oil related projects over natural gas projects. Over 70% of our
capital program is currently dedicated to resource play assets which we
believe offer lower risk, repeatable development opportunities and
approximately 75% of the spending is anticipated to be on operated properties.
We also expect our spending on activities such as land, seismic and
exploration will account for approximately 15% of our conventional spending
which helps to create opportunities in the future. We expect our drilling
activity to virtually double in 2008 as we focus our activities on shallow
natural gas development in southeastern Alberta and southwestern Saskatchewan.
Our largest expenditures are expected to be in shallow gas, particularly the
Shackleton property in Saskatchewan where we now operate, and on our crude oil
waterflood properties across the Western Canadian Sedimentary Basin.
    We are currently estimating capital spending of approximately
$105 million dedicated to our oil sands portfolio in 2008. This spending is
evenly split between Kirby and Joslyn with the Kirby spending concentrated on
the initial core hole drilling program and regulatory project application and
Joslyn spending focused on advancing the mining interests. We expect capital
spending on our oil sands assets to continue to increase over the next few
years and as a result, we are reviewing our options for financing which could
include the sale of a portion of our oil sands portfolio as well as debt,
partnering opportunities and special purposes equity alternatives.

                      2008 Estimated      2008 Estimated      2008 Estimated
                             Average            Drilling             Capital
                    Daily Production            Activity            Spending
    Play Types              (BOE/day)         (Net Wells)               ($MM)
    -------------------------------------------------------------------------
      Shallow Gas
       & CBM                  25,000                 371                $128
      Crude Oil
       Waterfloods            16,000                  49                 105
      Deep Tight Gas          13,800                  20                  53
      Bakken Oil              10,800                   6                  47
      Other
       Conventional
       Oil & Gas              32,400                  61                 142
    -------------------------------------------------------------------------
    Total
     Conventional             98,000                 507                $475
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    Oil Sands                      -                 n/a                 105
    -------------------------------------------------------------------------
    Total Company             98,000                 507                $580
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    Includes the Focus assets effective February 13, 2008

    ACQUISITIONS & DIVESTMENTS

    In 2007 Enerplus acquired approximately 4.3 million BOE of company
interest proved plus probable conventional oil and gas reserves, the majority
of which was through the acquisition of gross overriding royalty ("GORR")
interests in the state of Wyoming for consideration of $61 million. The assets
produce natural gas from the Jonah field in Wyoming, which is one of the
largest gas fields in the U.S. We acquired an effective interest of
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 at
Jonah. We believe the field has a significant number of additional infill
drilling locations that will provide growth potential for the future and to
date have seen a 10% increase in our net production volumes. Enerplus is not
required to pay any capital or operating costs on the assets.
    We also acquired a 100% working interest in the Kirby oil sands lease for
$203.1 million as described more fully in the oil sands section of this
release. The following table outlines our acquisition and divestment activity
in 2007.

    2007 Acquisition & Divestment Summary

                                                           Cost of
                                        Proved              Proved
                                          plus                plus  Cost per
                               Cost/  Probable            Probable     Daily
                          Proceeds(*) Reserves Production Reserves    Barrel
    Conventional Oil & Gas      ($MM)    (MBOE)  (BOE/day)  ($/BOE)    ($000)
    -------------------------------------------------------------------------
    Acquisitions              $ 71.1     4,773       667   $ 14.90   $ 106.6
    Divestments                  9.6       523       128     18.36      75.0
    -------------------------------------------------------------------------
    Net Conventional Oil
     & Gas Acquisitions       $ 61.5     4,250       539   $ 14.47   $ 114.1
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    Oil Sands
     Acquisitions(xx)         $203.1         -         -       n/a       n/a
    -------------------------------------------------------------------------
    (*)    After adjustment for working capital and excluding future
           development
    (xx)   The Kirby lease has been assessed by GLJ as containing a best
           estimate of 244 MMBOE of bitumen contingent resources. For
           information on contingent resource estimates and the risks and
           uncertainties associated therewith, see "Information Regarding
           Disclosure in this News Release and Oil and Gas Reserves,
           Resources and Operational Information" at the conclusion of this
           news release

    RESERVES

    Total proved plus probable reserves at December 31, 2007 were 440
million BOE, down less than 1% from 2006 levels. Through our development and
acquisition activities, we replaced 90% of produced volumes including the
addition of 6.8 million barrels from our oil sands properties. Over the last
5 years we have replaced on average 179% of produced volumes including
acquisition and divestment activity.
    Enerplus has built a large, diversified portfolio of conventional and
unconventional capital projects that we believe will support our operations in
the years ahead through the addition of production and reserves. We estimate
our current inventory of conventional capital projects at over $2.3 billion
representing over 4,000 net wells excluding any future capital associated with
our oil sands activities. This includes approximately $430 million of
estimated future development potential that was added through the Focus
acquisition ($320 million at Shackleton and $85 million at Tommy Lakes) and in
total represents approximately four to five years of conventional future
development potential at current capital spending levels assuming no new
acquisitions or changes of strategies on existing properties. We believe this
opportunity set includes significant potential across our entire asset base
and capital projects which are both technically and economically viable at
today's commodity prices. Future development capital estimates associated with
our oil sands activities are not currently available but we expect to provide
such estimate later in 2008. We continue to expect production volumes in the
range of 60,000 bbls/day net to Enerplus from our current oil sands projects
once all such projects, as currently planned, have reached their peak
production rates.
    The following table highlights our year end reserves, reserve life index
and future development potential by resource play. Approximately 75% of proved
plus probable reserves are attributable to resource plays.

                                                            Proved
                                                              plus    Future
                                                  Proved  Probable    Devel-
                                                    Plus   Reserve    opment
                              Proved  Probable  Probable      Life   Opport-
                            Reserves  Reserves  Reserves     Index   unities
    Conventional Play Types   (MMBOE)   (MMBOE)   (MMBOE)   (years)     ($MM)
    -------------------------------------------------------------------------
    Crude Oil Waterfloods       80.3      20.9     101.2      17.3    $  350
    Shallow Gas & CBM           65.7      25.9      91.7      17.4       640
    Deep Tight Gas              23.5       7.7      31.2      10.3       225
    Bakken Oil                  30.8      10.8      41.6      10.1       280
    Other Conventional
     Oil & Gas                  81.0      30.1     111.0       9.9       850
    -------------------------------------------------------------------------
    Total Conventional         281.3      95.4     376.7      12.8    $2,345
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    Oil Sands                    8.6      54.9      63.5       n/a       TBA
    -------------------------------------------------------------------------
    Total Company              289.9     150.3     440.2      14.8       n/a
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    Amounts shown in table may not add due to rounding.

    Reserve Reporting and Determination Methodologies

    All of our reserves, including our U.S. reserves, were evaluated using
Canadian National Instrument 51-101 ("NI 51-101") standards. Three external,
independent third party engineering firms were used to evaluate and review our
reserves this year. Sproule, our historical independent engineering
evaluators, evaluated our Canadian conventional reserves. GLJ evaluated the
Joslyn SAGD bitumen reserves as they have previously performed such
evaluations for the operator of the Joslyn project. Netherland, Sewell
Associates Inc. ("NSA") of Dallas, Texas evaluated the reserves attributed to
our assets in the United States. Sproule evaluated 92% 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 which were internally
evaluated by Enerplus. Both GLJ and NSA evaluated 100% of the reserves in
their respective areas and utilized Sproule's forecast price and cost
assumptions as of December 31, 2007 in their evaluations to maintain
consistency among our reserve reporting.

    For information regarding the presentation of our oil and gas reserves,
please see "Information Regarding Disclosure in this News Release and Oil and
Gas Reserves, Resources and Operational Information" and "Notice to U.S.
Investors" at the conclusion of this news release.

    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.

    2007 Reserve Summary - Company Interest Volumes (Forecast Prices)

                               OIL AND GAS NATURAL RESERVES
    -------------------------------------------------------------------------
                Light &                           Natural
                 Medium   Heavy            Total      Gas   Natural
                    Oil     Oil  Bitumen     Oil  Liquids       Gas    Total
                 (Mbbls) (Mbbls)  (Mbbls) (Mbbls)  (Mbbls)    (MMcf)   (MBOE)
    -------------------------------------------------------------------------
    Proved
     developed
     producing
      Canada     63,963  28,832   2,365   95,160  10,469    649,382  213,860
      United
       States    21,672       -       -   21,672      74     28,527   26,501
    -------------------------------------------------------------------------
      Total      85,635  28,832   2,365  116,832  10,543    677,909  240,361
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    Proved
     developed
     non-producing
      Canada        190       -       -      190     510     14,911    3,185
      United
       States     1,588       -       -    1,588       5      1,623    1,863
    -------------------------------------------------------------------------
      Total       1,778       -       -    1,778     515     16,534    5,048
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    Proved
     undeveloped
      Canada      3,233   2,383   6,203   11,819     694    164,829   39,984
      United
       States     3,377       -       -    3,377      33      6,805    4,544
    -------------------------------------------------------------------------
      Total       6,610   2,383   6,203   15,196     727    171,634   44,528
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    Total Proved
      Canada     67,386  31,215   8,568  107,169  11,673    829,122  257,029
      United
       States    26,637       -       -   26,637     112     36,955   32,908
    -------------------------------------------------------------------------
      Total      94,023  31,215   8,568  133,806  11,785    866,077  289,937
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    Probable
      Canada     17,837  10,948  54,930   83,715   3,797    308,276  138,891
      United
       States     6,719       -       -    6,719      30     27,938   11,406
    -------------------------------------------------------------------------
      Total      24,556  10,948  54,930   90,434   3,827    336,214  150,297
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    Total Proved
     plus
     Probable
      Canada     85,223  42,163  63,498  190,884  15,470  1,137,398  395,920
      United
       States    33,356       -       -   33,356     142     64,893   44,314
    -------------------------------------------------------------------------
      Total     118,579  42,163  63,498  224,240  15,612  1,202,291  440,234
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    Reserve Reconciliation

    The following tables outline the changes in Enerplus' proved, probable and
proved plus probable reserves, on a company interest basis, from December 31,
2006 to December 31, 2007.

    Proved Reserves

                Light &                           Natural
                 Medium   Heavy            Total      Gas   Natural
                    Oil     Oil  Bitumen     Oil  Liquids       Gas    Total
    CANADA       (Mbbls) (Mbbls)  (Mbbls) (Mbbls)  (Mbbls)    (MMcf)   (MBOE)
    -------------------------------------------------------------------------
    Proved
     Reserves at
     Dec. 31,
     2006        70,504  31,153   8,730  110,387  12,690    905,261  273,954
    -------------------------------------------------------------------------
    Acquisitions      2       -       -        2       4      3,496      588
    Divestments       -       -       -        -       -     (2,814)    (469)
    Discoveries     251       -       -      251       5        178      285
    Extensions      849       -       -      849     550     22,574    5,161
    Improved
     Recovery       961   1,870       -    2,831      21      7,838    4,158
    Economic
     Factors      1,581     548       -    2,129     114      5,527    3,164
    Technical
     Revisions     (986)    844    (162)    (304)   (214)   (21,118)  (4,036)
    Production   (5,776) (3,200)      -   (8,976) (1,497)   (91,820) (25,776)
    -------------------------------------------------------------------------
    Proved
     Reserves at
     Dec. 31,
     2007        67,386  31,215   8,568  107,169  11,673    829,122  257,029
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------



                Light &                           Natural
                 Medium   Heavy            Total      Gas   Natural
    UNITED          Oil     Oil  Bitumen     Oil  Liquids       Gas    Total
     STATES      (Mbbls) (Mbbls)  (Mbbls) (Mbbls)  (Mbbls)    (MMcf)   (MBOE)
    -------------------------------------------------------------------------
    Proved
     Reserves at
     Dec. 31,
     2006        23,391       -       -   23,391       -     14,800   25,858
    -------------------------------------------------------------------------
    Acquisitions      -       -       -        -     124     13,311    2,343
    Divestments       -       -       -        -       -          -        -
    Discoveries       -       -       -        -       -          -        -
    Extensions       66       -       -       66       -         36       72
    Improved
     Recovery     6,772       -       -    6,772       -      5,585    7,703
    Economic
     Factors          -       -       -        -       -          -        -
    Technical
     Revisions       15       -       -       15       -      7,126    1,202
    Production   (3,607)      -       -   (3,607)    (12)    (3,903)  (4,270)
    -------------------------------------------------------------------------
    Proved
     Reserves at
     Dec. 31,
     2007        26,637       -       -   26,637     112     36,955   32,908
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------



                Light &                           Natural
                 Medium   Heavy            Total      Gas   Natural
    TOTAL           Oil     Oil  Bitumen     Oil  Liquids       Gas    Total
     ENERPLUS    (Mbbls) (Mbbls)  (Mbbls) (Mbbls)  (Mbbls)    (MMcf)   (MBOE)
    -------------------------------------------------------------------------
    Proved
     Reserves at
     Dec. 31,
     2006        93,895  31,153   8,730  133,778  12,690    920,061  299,812
    -------------------------------------------------------------------------
    Acquisitions      2       -       -        2     128     16,807    2,931
    Divestments       -       -       -        -       -     (2,814)    (469)
    Discoveries     251       -       -      251       5        178      285
    Extensions      915       -       -      915     550     22,610    5,233
    Improved
     Recovery     7,733   1,870       -    9,603      21     13,423   11,861
    Economic
     Factors      1,581     548       -    2,129     114      5,527    3,164
    Technical
     Revisions     (971)    844    (162)    (289)   (214)   (13,992)  (2,834)
    Production   (9,383) (3,200)      -  (12,583) (1,509)   (95,723) (30,046)
    -------------------------------------------------------------------------
    Proved
     Reserves at
     Dec. 31,
     2007        94,023  31,215   8,568  133,806  11,785    866,077  289,937
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------



    Probable Reserves

                Light &                           Natural
                 Medium   Heavy            Total      Gas   Natural
                    Oil     Oil  Bitumen     Oil  Liquids       Gas    Total
    CANADA       (Mbbls) (Mbbls)  (Mbbls) (Mbbls)  (Mbbls)    (MMcf)   (MBOE)
    -------------------------------------------------------------------------
    Probable
     Reserves at
     Dec. 31,
     2006        16,872   8,912  47,998   73,782   3,777    306,804  128,693
    -------------------------------------------------------------------------
    Acquisitions      -       -       -        -       -      7,532    1,256
    Divestments       -       -       -        -       -       (325)     (54)
    Discoveries      63       -       -       63       1         45       72
    Extensions      378       -   4,064    4,442     172      6,829    5,753
    Improved
     Recovery       276   1,301       -    1,577      16      3,193    2,125
    Economic
     Factors        343     338       -      681      20      1,156      894
    Technical
     Revisions      (95)    397   2,868    3,170    (189)   (16,958)     152
    Production        -       -       -        -       -          -        -
    -------------------------------------------------------------------------
    Probable
     Reserves at
     Dec. 31,
     2007        17,837  10,948  54,930   83,715   3,797    308,276  138,891
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------



                Light &                           Natural
                 Medium   Heavy            Total      Gas   Natural
    UNITED          Oil     Oil  Bitumen     Oil  Liquids       Gas    Total
     STATES      (Mbbls) (Mbbls)  (Mbbls) (Mbbls)  (Mbbls)    (MMcf)   (MBOE)
    -------------------------------------------------------------------------
    Probable
     Reserves at
     Dec. 31,
     2006         8,637       -       -    8,637       -     37,221   14,840
    -------------------------------------------------------------------------
    Acquisitions      -       -       -        -      30      3,340      586
    Divestments       -       -       -        -       -          -        -
    Discoveries       -       -       -        -       -          -        -
    Extensions       16       -       -       16       -         37       22
    Improved
     Recovery     1,378       -       -    1,378       -      5,106    2,229
    Economic
     Factors          -       -       -        -       -          -        -
    Technical
     Revisions   (3,312)      -       -   (3,312)      -    (17,766)  (6,271)
    Production        -       -       -        -       -          -        -
    -------------------------------------------------------------------------
    Probable
     Reserves at
     Dec. 31,
     2007         6,719       -       -    6,719      30     27,938   11,406
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------



                Light &                           Natural
                 Medium   Heavy            Total      Gas   Natural
    TOTAL           Oil     Oil  Bitumen     Oil  Liquids       Gas    Total
     ENERPLUS    (Mbbls) (Mbbls)  (Mbbls) (Mbbls)  (Mbbls)    (MMcf)   (MBOE)
    -------------------------------------------------------------------------
    Probable
     Reserves at
     Dec. 31,
     2006        25,509   8,912  47,998   82,419   3,777    344,025  143,533
    -------------------------------------------------------------------------
    Acquisitions      -       -       -        -      30     10,872    1,842
    Divestments       -       -       -        -       -       (325)     (54)
    Discoveries      63       -       -       63       1         45       72
    Extensions      394       -   4,064    4,458     172      6,866    5,775
    Improved
     Recovery     1,654   1,301       -    2,955      16      8,299    4,354
    Economic
     Factors        343     338       -      681      20      1,156      894
    Technical
     Revisions   (3,407)    397   2,868     (142)   (189)   (34,724)  (6,119)
    Production        -       -       -        -       -          -        -
    -------------------------------------------------------------------------
    Probable
     Reserves at
     Dec. 31,
     2007        24,556  10,948  54,930   90,434   3,827    336,214  150,297
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------



    Proved plus Probable Reserves

                Light &                           Natural
                 Medium   Heavy            Total      Gas   Natural
                    Oil     Oil  Bitumen     Oil  Liquids       Gas    Total
    CANADA       (Mbbls) (Mbbls)  (Mbbls) (Mbbls)  (Mbbls)    (MMcf)   (MBOE)
    -------------------------------------------------------------------------
    Proved Plus
     Probable
     Reserves at
     Dec. 31,
     2006        87,376  40,065  56,728  184,169  16,467  1,212,065  402,647
    -------------------------------------------------------------------------
    Acquisitions      2       -       -        2       4     11,028    1,844
    Divestments       -       -       -        -       -     (3,139)    (523)
    Discoveries     314       -       -      314       6        223      357
    Extensions    1,227       -   4,064    5,291     722     29,403   10,914
    Improved
     Recovery     1,237   3,171       -    4,408      37     11,031    6,283
    Economic
     Factors      1,924     886       -    2,810     134      6,683    4,058
    Technical
     Revisions   (1,081)  1,241   2,706    2,866    (403)   (38,076)  (3,884)
    Production   (5,776) (3,200)      -   (8,976) (1,497)   (91,820) (25,776)
    -------------------------------------------------------------------------
    Proved Plus
     Probable
     Reserves at
     Dec. 31,
     2007        85,223  42,163  63,498  190,884  15,470  1,137,398  395,920
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------



                Light &                           Natural
                 Medium   Heavy            Total      Gas   Natural
    UNITED          Oil     Oil  Bitumen     Oil  Liquids       Gas    Total
     STATES      (Mbbls) (Mbbls)  (Mbbls) (Mbbls)  (Mbbls)    (MMcf)   (MBOE)
    -------------------------------------------------------------------------
    Proved Plus
     Probable
     Reserves at
     Dec. 31,
     2006        32,028       -       -   32,028       -     52,021   40,698
    -------------------------------------------------------------------------
    Acquisitions      -       -       -        -     154     16,651    2,929
    Divestments       -       -       -        -       -          -        -
    Discoveries       -       -       -        -       -          -        -
    Extensions       82       -       -       82       -         73       94
    Improved
     Recovery     8,150       -       -    8,150       -     10,691    9,932
    Economic
     Factors          -       -       -        -       -          -        -
    Technical
     Revisions   (3,297)      -       -   (3,297)      -    (10,640)  (5,069)
    Production   (3,607)      -       -   (3,607)    (12)    (3,903)  (4,270)
    -------------------------------------------------------------------------
    Proved Plus
     Probable
     Reserves at
     Dec. 31,
     2007        33,356       -       -   33,356     142     64,893   44,314
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------



                Light &                           Natural
                 Medium   Heavy            Total      Gas   Natural
    TOTAL           Oil     Oil  Bitumen     Oil  Liquids       Gas    Total
     ENERPLUS    (Mbbls) (Mbbls)  (Mbbls) (Mbbls)  (Mbbls)    (MMcf)   (MBOE)
    -------------------------------------------------------------------------
    Proved Plus
     Probable
     Reserves at
     Dec. 31,
     2006       119,404  40,065  56,728  216,197  16,467  1,264,086  443,345
    -------------------------------------------------------------------------
    Acquisitions      2       -       -        2     158     27,679    4,773
    Divestments       -       -       -        -       -     (3,139)    (523)
    Discoveries     314       -       -      314       6        223      357
    Extensions    1,309       -   4,064    5,373     722     29,476   11,008
    Improved
     Recovery     9,387   3,171       -   12,558      37     21,722   16,215
    Economic
     Factors      1,924     886       -    2,810     134      6,683    4,058
    Technical
     Revisions   (4,378)  1,241   2,706     (431)   (403)   (48,716)  (8,953)
    Production   (9,383) (3,200)      -  (12,583) (1,509)   (95,723) (30,046)
    -------------------------------------------------------------------------
    Proved Plus
     Probable
     Reserves at
     Dec. 31,
     2007       118,579  42,163  63,498  224,240  15,612  1,202,291  440,234
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    NET PRESENT VALUE OF FUTURE PRODUCTION REVENUE

    The following tables provide an estimate of the net present value of
Enerplus' future production revenue before provision for interest and general
and administrative expenses and after deduction of royalties and estimated
future capital expenditures and both before and after income taxes. It should
not be assumed that the present value of estimated future cash flows shown
below is representative of the fair market value of the reserves. The
following information does not give effect to the proposed revised Alberta
royalty regime as no legislation has yet been introduced to pass the proposed
new royalty regime into law.
    The net estimated present value of all future net revenues at
December 31, 2007 was based upon forecast crude oil and natural gas pricing
assumptions prepared by Sproule as of December 31, 2007. These prices were
applied to the reserves evaluated by Sproule, GLJ and NSA. The base reference
prices and exchange rates used by Sproule are detailed below:

    Sproule December 31, 2007 - Forecast Price Assumptions
    -------------------------------------------------------------------------
                                          Differ-
                                          ential
                                         Between            Natural
                                        Hardisty                Gas
                                           Heavy             30 day
                              Hardisty       And     Henry     spot
               WTI     Light     Heavy  Bitumen(2)     Hub     @
             crude  crude(1) 12(degrees)    (Oil     Price     AECO  Exchange
               oil  Edmonton       API     Sands)     US$/    CDN$/      Rate
           US$/bbl  CDN$/bbl  CDN$/bbl  CDN$/bbl     MMbtu    MMbtu  US$/CDN$
    -------------------------------------------------------------------------
    2008    $89.61    $88.17    $54.67    $20.50     $7.56    $6.51    $1.00
    2009     86.01     84.54     52.42     15.96      8.27     7.22     1.00
    2010     84.65     83.16     51.56     14.02      8.74     7.69     1.00
    2011     82.77     81.26     50.38     12.05      8.75     7.70     1.00
    2012     82.26     80.73     50.05     12.02      8.66     7.61     1.00
    There-
     after     (xx)      (xx)      (xx)      (xx)     2.0%      (xx)    1.00
    -------------------------------------------------------------------------
    (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 2012



    Net Present Value of Future Production Revenue- Forecast Prices and Costs
    (Before Tax)
    At December 31, 2007
    -------------------------------------------------------------------------
    Conventional Reserves ($ Millions,
     before tax, discounted at)             0%        5%       10%       15%
    -------------------------------------------------------------------------
    Proved developed producing        $  8,661   $ 5,602   $ 4,252   $ 3,487
    Proved developed non-producing         187       127        95        76
    Proved undeveloped                     827       512       334       223
    -------------------------------------------------------------------------
    Total Proved                      $  9,675   $ 6,241   $ 4,681   $ 3,786
    Probable                             3,805     1,740     1,032       707
    -------------------------------------------------------------------------
    Total Proved Plus Probable
     Conventional Reserves            $ 13,480   $ 7,981   $ 5,713   $ 4,493
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    Bitumen Reserves
    Proved developed producing        $     35   $    28   $    23   $    19
    Proved undeveloped                     100        56        32        19
    -------------------------------------------------------------------------
    Total Proved                           135        84        55        38
    Probable                             1,293       294        89        29
    -------------------------------------------------------------------------
    Total Proved plus Probable
     Bitumen Reserves                 $  1,428   $   378   $   144   $    67
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    Total Conventional
     and Bitumen Reserves             $ 14,908   $ 8,359   $ 5,857   $ 4,560
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------


    Net Present Value of Future Production Revenue - Forecast Prices and
    Costs (after Tax) at December 31, 2007

    Conventional Reserves
     ($ Millions, discounted at)            0%        5%       10%       15%
    -------------------------------------------------------------------------
    Proved developed producing        $  7,316   $ 4,890   $ 3,787   $ 3,146
    Proved developed non-producing         132        91        67        53
    Proved undeveloped                     670       406       259       167
    -------------------------------------------------------------------------
    Total Proved                      $  8,118   $ 5,387   $ 4,113   $ 3,366
    Probable                             2,838     1,314       789       546
    -------------------------------------------------------------------------
    Total Proved Plus Probable
     Conventional Reserves            $ 10,956   $ 6,701   $ 4,902   $ 3,912
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    Bitumen Reserves
    Proved developed producing        $     28   $    22   $    19   $    15
    Proved developed non-producing          72        40        22        13
    -------------------------------------------------------------------------
    Total Proved                      $    100   $    62   $    41   $    28
    Probable                               928       207        59        15
    -------------------------------------------------------------------------
    Total Proved plus Probable
     Bitumen Reserves                 $  1,028   $   269   $   100   $    43
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    Total Conventional
     and Bitumen Reserves             $ 11,984   $ 6,970   $ 5,002   $ 3,955
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    NET ASSET VALUE

    Enerplus' estimated net asset value is measured with reference to the net
present value of all future net revenue from our reserves as estimated by our
independent reserve engineers (Sproule, GLJ and NSA) 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 or incremental development,
despite our 22 year history of replacing production through acquisitions and
development.
    In addition, we are including an estimated net asset value of our oil
sands portfolio to approximate the value of these assets. We used a market
valuation if a recent third party, arms length transaction had occurred
subsequent to our investment or our original investment cost if no such
transaction had occurred.

    Forecast Prices and Costs at December 31, 2007


    Conventional Oil and Gas
     ($ millions except trust unit
      amounts, discounted at)               0%        5%       10%       15%
    -------------------------------------------------------------------------
    Present value of proved plus
     probable reserves (before tax)
    -------------------------------------------------------------------------
    Total, present value of proved
     plus probable reserves            $13,480   $ 7,981   $ 5,713   $ 4,493
    Undeveloped acreage                     66        66        66        66
    Asset retirement obligations          (292)     (148)      (49)      (26)
    Long-term debt (net of cash)          (725)     (725)     (725)     (725)
    Net Working Capital excluding
     deferred financial asset,
     distributions to unitholders,
     deferred credits,
     and future income tax                (117)     (117)     (117)     (117)
    -------------------------------------------------------------------------
    Net Asset Value of
     Conventional Assets(1)            $12,412   $ 7,057   $ 4,888   $ 3,691
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    Net Asset Value per Trust Unit
     - Conventional Assets(1)(2)       $ 95.61   $ 54.36   $ 37.65   $ 28.43
    -------------------------------------------------------------------------

    Oil Sands
    Value of Joslyn Lease(3)           $ 340.0   $ 340.0   $ 340.0   $ 340.0
    Value of Kirby Oil Sands Lease(4)    205.4     205.4     205.4     205.4
    Laricina Equity Investment(5)        139.9     139.9     139.9     139.9
    Undeveloped Oil Sands acreage(6)      10.7      10.7      10.7      10.7
    -------------------------------------------------------------------------
    Net Asset Value of Oil Sands
     Assets                            $ 695.9   $ 695.9   $ 695.9   $ 695.9
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    Net Asset Value per Trust Unit
     - Oil Sands                       $  5.36   $  5.36   $  5.36   $  5.36

    Total Net Asset Value
     per Trust Unit(2)                 $100.97   $ 59.72   $ 43.01   $ 33.79
    -------------------------------------------------------------------------
    (1) Asset retirement obligations ("ARO") do not equal the amount on the
        balance sheet ($165.7 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 129,813,000 trust units outstanding at December 31, 2007
    (3) Joslyn valuation represents 15% working interest valued using Total's
        purchase price of Deer Creek in 2005 including development capital
        spent since the Total purchase
    (4) Kirby valuation represents $203.1 MM purchase price plus capital
        spending of $2.3 MM since acquisition
    (5) Laricina equity investment represents 4,305,675 shares at most recent
        equity offering of $32.50/share
    (6) Undeveloped oil sands acreage valued at cost of land acquisitions and
        development capital spent on those lands.

    RESERVE LIFE INDEX ("RLI")

    Enerplus has maintained one of the longest RLIs in the sector throughout
our 22 year history. In 2007, our RLI increased from 12.2 years to 12.8 years
on our conventional oil and gas reserves (proved plus probable) and from
14.0 years to 14.8 years on an overall basis including oil sands using both
proved and probable reserves. Subsequent to the Focus transaction, our proved
plus probable RLI decreased to 14.0 years.

    As at December 31     Post Focus    2007    2006    2005    2004    2003
    -------------------------------------------------------------------------
    Without Oil Sands
      Proved                     9.7    10.0     9.8     9.6    10.1    10.6
      Proved plus Probable      12.4    12.8    12.2    12.0    12.4    13.3
    -------------------------------------------------------------------------
    With Oil Sands
      Proved                     9.9    10.3    10.1     9.9    10.1    10.6
      Proved plus Probable      14.0    14.8    14.0    13.5    14.0    13.3
    -------------------------------------------------------------------------

    Reserve life index is calculated as year end reserves divided by
following year production estimates contained in the independent reserve
engineering reports.

    FINDING AND DEVELOPMENT COSTS ("F&D") AND FINDING, DEVELOPMENT AND
    ACQUISITION COSTS ("FD&A")

    Through our conventional capital development program, we added
27.6 million BOE of proved plus probable reserves. Unfortunately, we also
experienced negative technical revisions of 11.7 million proved plus probable
BOE. On a net basis, our capital development program added 15.9 million BOE
resulting in F&D costs of $19.97/BOE on our conventional oil and gas assets on
a proved plus probable basis.
    Our total spending on our conventional asset base delivered a FD&A cost
of $19.79/BOE on a proved plus probable basis including future development
capital ("FDC"). Our three-year conventional proved plus probable FD&A was
$19.57/BOE including changes in future development capital.
    F&D costs on our oil sands assets were $21.16/bbl based on proved plus
probable reserves which reflects a significant increase in FDC associated with
the SAGD development. Our oil sands acquisition activity consisted solely of
the acquisition of the Kirby lease which did not add any reserves or
production but has a contingent resource estimate of 244 million barrels as
described above. As we move forward with the development of the Kirby lease,
we expect to move contingent resources into the probable reserve category. Our
proved plus probable oil sands FD&A cost in 2007 was $51.03/bbl.
    Combined our 2007 corporate F&D cost was $20.33/BOE and our FD&A cost was
$27.69/BOE (both measures including changes in FDC). Our three-year average
F&D cost was $17.96/BOE and our three-year average FD&A cost was $20.69/BOE.
    F&D and FD&A costs can be calculated either including or excluding future
development capital. F&D and FD&A costs calculated under NI 51-101 include
future development capital 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, F&D and 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 future development capital
and the historic method for comparison purposes. The aggregate of the
exploration and development costs incurred in the most recent financial year
and the change during that year in estimated future development costs
generally will not reflect total finding and development costs related to
reserves additions for that year. For information on the use of the term "BOE"
see "Information Regarding Disclosure in this News Release and Oil and Gas
Reserves, Resources and Operational Information" at the conclusion of this
news release.

    F&D and FD&A Costs (Including Future
     Development Capital)
    ($ millions except for per BOE amounts)       2007       2006       2005
    -------------------------------------------------------------------------
    Proved Reserves

    Conventional Oil & Gas
    -------------------------------------------------------------------------
      Capital Expenditures                   $   348.3    $ 452.1    $ 335.5
      Net change in Future
       Development Capital                   $    39.3    $  22.3    $  97.4
      Gross Reserve additions (MMBOE)             17.9       16.1       28.8
      F&D costs ($/BOE)                      $   21.65    $ 29.47    $ 15.03
      Three year averages F&D cost
       ($/BOE)(1)                            $   20.62    $ 15.54        n/a

      Capital Expenditures
       and net acquisitions                  $   409.8    $ 502.0    $ 973.0
      Net change in Future Developments
       Costs                                 $    48.5    $   8.0    $ 184.7
      Gross company reserve additions (MMBOE)     20.4       18.6       53.7
      FD&A costs ($/BOE)                     $   22.47    $ 27.42    $ 21.56
      Three year average FD&A costs
       ($/BOE)(1)                            $   22.93    $ 19.80    $ 24.02

    Oil Sands
    -------------------------------------------------------------------------
      Capital Expenditures                   $    38.9    $  39.1    $  33.2
      Net change in Future
       Development Capital                   $    (1.7)   $ (10.8)   $  44.6
      Gross Reserve additions (MMBOE)             (0.2)      (0.1)       9.5
      F&D costs ($/BOE)                      $ (186.00)  $(283.00)   $  8.19
      Three year averages F&D cost
       ($/BOE)(1)                            $   15.58    $ 12.17    $  9.51

      Capital Expenditures
       and net acquisitions                  $   242.0    $  19.4    $  33.2
      Net change in Future Development Costs $    (1.7)   $ (13.6)   $  44.6
      Gross company reserve additions (MMBOE)     (0.2)      (0.7)       9.5
      FD&A costs ($/BOE)                    $(1,201.50)   $ (8.29)   $  8.19
      Three year average FD&A
       costs ($/BOE)(1)                      $   37.66    $ 10.44    $  9.51

    Total Fund
    -------------------------------------------------------------------------
     Capital Expenditures                    $   387.2    $ 491.2    $ 368.7
      Net change in Future
       Development Capital                   $    37.6    $  11.5    $ 142.0
      Gross Reserve additions (MMBOE)             17.7       16.0       38.3
      F&D costs ($/BOE)                      $   24.00    $ 31.42    $ 13.33
      Three year averages F&D
       cost ($/BOE)(1)                       $   19.98    $ 15.16        n/a

      Capital Expenditures and
       net acquisitions                      $   651.8    $ 521.4   $1,006.2
      Net change in Future Development Costs $    46.8    $  (5.6)   $ 229.3
      Gross company reserve additions (MMBOE)     20.2       17.9       63.2
      FD&A costs ($/BOE)                     $   34.58    $ 28.82    $ 19.55
      Three year average FD&A
       costs ($/BOE)(1)                      $   24.18    $ 19.20    $ 22.73
    -------------------------------------------------------------------------


    Proved Plus Probable Reserves
    ($ millions except for per BOE amounts)       2007       2006       2005

    Conventional Oil & Gas
    -------------------------------------------------------------------------
      Capital Expenditures                   $   348.3    $ 452.1    $ 335.5
      Net change in Future
       Development Capital                   $   (30.7)   $  50.7    $  92.1
      Gross Reserve additions (MMBOE)             15.9       18.3       32.0
      F&D costs ($/BOE)                      $   19.97    $ 27.48    $ 13.36
      Three year averages F&D
       cost ($/BOE)(1)                       $   18.85    $ 20.22        n/a

      Capital Expenditures
       and net acquisitions                  $   409.8    $ 502.0    $ 973.0
      Net change in Future Development Costs $   (12.0)   $  54.4    $ 197.7
      Gross company reserve additions (MMBOE)     20.1       21.9       66.6
      FD&A costs ($/BOE)                     $   19.79    $ 25.41    $ 17.58
      Three year average FD&A
       costs ($/BOE)(1)                      $   19.57    $ 18.10    $ 15.97

    Oil Sands
    -------------------------------------------------------------------------
      Capital Expenditures                   $    38.9    $  39.1    $  33.2
      Net change in Future
       Development Capital                   $   105.0    $  34.3    $  33.4
      Gross Reserve additions (MMBOE)              6.8        6.9        5.4
      F&D costs ($/BOE)                      $   21.16    $ 10.64    $ 12.33
      Three year averages F&D
       cost ($/BOE)(1)                       $   14.86    $  6.91        n/a

      Capital Expenditures
       and net acquisitions                  $   242.0    $  19.4    $  33.2
      Net change in Future
       Development Costs                     $   105.0    $  15.6    $  33.4
      Gross company reserve additions (MMBOE)      6.8        3.6        5.4
      FD&A costs ($/BOE)(1)                  $   51.03    $  9.72    $ 12.33
      Three year average FD&A
       costs ($/BOE)(1)                      $   28.39    $  6.63    $  6.50

    Total Fund
    -------------------------------------------------------------------------
      Capital Expenditures                   $   387.2    $ 491.2    $ 368.7
      Net change in Future
       Development Capital                   $    74.3    $  85.0    $ 125.5
      Gross Reserve additions (MMBOE)             22.7       25.2       37.4
      F&D costs ($/BOE)                      $   20.33    $ 22.87    $ 13.21
      Three year averages F&D
       cost ($/BOE)(1)                       $   17.96    $ 13.52        n/a

      Capital Expenditures
       and net acquisitions                  $   651.8    $ 521.4   $1,006.2
      Net change in Future Development Costs $    93.0    $  70.0    $ 231.1
      Gross company reserve additions (MMBOE)     26.9       25.5       72.0
      FD&A costs ($/BOE)(1)                  $   27.69    $ 23.19    $ 17.18

      Three year average FD&A
       costs ($/BOE)(1)                      $   20.69    $ 14.90    $ 13.46
    -------------------------------------------------------------------------
    (1) Calculated over a three year period.



    F&D and FD&A Costs (Excluding Future
     Development Capital)
    ($ millions except for per BOE amounts)       2007       2006       2005
    -------------------------------------------------------------------------
    Proved Reserves

    Conventional Oil & Gas
    -------------------------------------------------------------------------
      Capital Expenditures                   $   348.3    $ 452.1    $ 335.5
      Gross Reserve additions (MMBOE)             17.9       16.1       28.8
      F&D Cost ($/BOE)                       $   19.46    $ 28.08    $ 11.65
      Three year averages F&D
       costs ($/BOE)(1)                      $   18.09    $ 13.17    $  9.87

      Capital Expenditures
       and net acquisitions                  $   409.8    $ 502.0    $ 973.0
      Gross company reserve additions (MMBOE)     20.4       18.6       53.7
      FD&A costs ($/BOE)                     $   20.09    $ 26.99    $ 18.12
      Three year average FD&A
       costs ($/BOE)(1)                      $   20.33    $ 17.55    $ 14.94

    Oil Sands
    -------------------------------------------------------------------------
      Capital Expenditures                   $    38.9    $  39.1    $  33.2
      Gross Reserve additions (MMBOE)             (0.2)      (0.1)       9.5
      F&D Cost ($/BOE)                       $ (194.50)  $(391.00)   $  3.49
      Three year averages F&D
       costs ($/BOE)(1)                      $   12.09    $  8.57    $  4.81

      Capital Expenditures
       and net acquisitions                  $   242.0    $  19.4    $  33.2
      Gross company reserve additions (MMBOE)     (0.2)      (0.7)       9.5
      FD&A costs ($/BOE)                    $(1,210.00)   $(27.71)   $  3.49
      Three year average FD&A
       costs ($/BOE)(1)                      $   34.26    $  6.92    $  4.81

    Total Fund
    -------------------------------------------------------------------------
      Capital Expenditures                   $   387.2    $ 491.2    $ 368.7
      Gross Reserve additions (MMBOE)             17.7       16.0       38.3
      F&D Cost ($/BOE)                       $   21.88    $ 30.70    $  9.63
      Three year averages F&D
       costs ($/BOE)(1)                      $   17.32    $ 12.65    $  9.26

      Capital Expenditures
       and net acquisitions                  $   651.8    $ 521.4   $1,006.2
      Gross company reserve additions (MMBOE)     20.2       17.9       63.2
      FD&A costs ($/BOE)                     $   32.27    $ 29.13    $ 15.92
      Three year average FD&A
       costs ($/BOE)(1)                      $   21.51    $ 16.88    $ 14.30

    Proved Plus Probable Reserves

    Conventional  Oil & Gas
    -------------------------------------------------------------------------
      Capital Expenditures                   $   348.3    $ 452.1    $ 335.5
      Gross Reserve additions (MMBOE)             15.9       18.3       32.0
      F&D Cost ($/BOE)                       $   21.91    $ 24.70    $ 10.48
      Three year averages F&D
       costs ($/BOE)(1)                      $   17.16    $ 16.66    $ 12.48

      Capital Expenditures
       and net acquisitions                  $   409.8    $ 502.0    $ 973.0
      Gross company reserve additions (MMBOE)     20.1       21.9       66.6
      FD&A costs ($/BOE)                     $   20.39    $ 22.92    $ 14.61
      Three year average FD&A
       costs ($/BOE)(1)                      $   17.36    $ 15.55    $ 13.20

    Oil Sands
    -------------------------------------------------------------------------
      Capital Expenditures                   $    38.9    $  39.1    $  33.2
      Gross Reserve additions (MMBOE)              6.8        6.9        5.4
      F&D Cost ($/BOE)                       $    5.72    $  5.67    $  6.15
      Three year averages F&D
       costs ($/BOE)(1)                      $    5.82    $  1.34    $  0.86

      Capital Expenditures
       and net acquisitions                  $   242.0    $  19.4    $  33.2
      Gross company reserve additions (MMBOE)      6.8        3.6        5.4
      FD&A costs ($/BOE)                     $   35.59    $  5.39    $  6.15
      Three year average FD&A
       costs ($/BOE)(1)                      $   18.65    $  1.07    $  0.86

    Total Fund
    -------------------------------------------------------------------------
      Capital Expenditures                   $   387.2    $ 491.2    $ 368.7
      Gross Reserve additions (MMBOE)             22.7       25.2       37.4
      F&D Cost ($/BOE)                       $   17.06    $ 19.49    $  9.86
      Three year averages F&D
       costs ($/BOE)(1)                      $   14.62    $  8.95    $  6.78

      Capital Expenditures
       and net acquisitions                  $   651.8    $ 521.4   $1,006.2
      Gross company reserve additions (MMBOE)     26.9       25.5       72.0
      FD&A costs ($/BOE)                     $   24.23    $ 20.45    $ 13.98
      Three year average FD&A
       costs ($/BOE)(1)                      $   17.52    $ 11.51    $ 10.09
    -------------------------------------------------------------------------
    (1) Calculated 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. We have shown only conventional
recycle ratios as most of our oil sands portfolio is in the early stages of
development and consequently has no operating income or proved plus probable
reserves.

    Proved plus probable reserves                 2007       2006       2005
    -------------------------------------------------------------------------
    Conventional Recycle Ratio                    1.6x       1.2x       1.7x
    Conventional 3-Year Average                   1.5x       1.4x       1.6x
    -------------------------------------------------------------------------

    PRODUCTION AND RESERVES PER UNIT

    Production and reserves per unit is an effective measure of
sustainability. When adjusted for debt and distributions it also provides an
ability to compare results between our distributing model with other more
traditional oil and gas entities that generally reinvest the majority of their
cash flow into exploration and development activities. The last three years
Enerplus has enjoyed both a growing reserves and production per unit when
adjusted for debt and distributions which we believe compares favorably with
other oil and gas producers, whether they are trusts or traditional oil and
gas entities. Metrics in 2007 have been impacted by the acquisition and equity
financing of the Kirby oil sands project which does not add any current
production or reserves.
    Production per debt-adjusted trust unit is measured in respect of the
average daily production for the year, and the weighted average number of
trust units outstanding during the year. The measurements are then debt-
adjusted by assuming additional trust units are issued at quarter-end unit
prices to replace long-term debt outstanding at each quarter-end. The average
number of trust units created over the four quarters is then added to the
weighted average number of trust units to obtain the debt-adjusted number of
trust units for the year. To distribution-adjust the metric, we utilized the
amount of cash distributions paid each month and retired units using the
quarter-end trust unit price thereby lowering the total number of units
outstanding.

    Production per Debt and
     Distribution-Adjusted Trust Unit             2007       2006       2005
    -------------------------------------------------------------------------
    Average daily production                    82,319     85,779     79,727
    Debt-adjusted weighted
     average trust units (000's)               142,666    132,208    120,875
    Production per debt-adjusted
     trust unit (BOE/unit)                       0.211      0.237      0.241
    Production per debt and distribution
     adjusted trust unit (BOE/unit)              0.392      0.390      0.365
    -------------------------------------------------------------------------

    Reserves per debt-adjusted trust unit is measured in respect of year-end
proved plus probable reserves and the number of units outstanding at year-end.
To eliminate the temporary timing effects of financing decisions, we have
debt- adjusted these measurements by assuming we issue additional trust units
at year-end prices to replace year-end long-term debt. To distribution-adjust
the metric, we utilized the amount of cash distributions paid to unitholders
throughout the year and retired units using the year-end trust unit price
thereby lowering the total number of units outstanding.

    Reserves per Debt and
     Distribution-Adjusted Trust Unit             2007       2006       2005
    -------------------------------------------------------------------------
    Year-end proved plus probable reserves     440,234    443,345    449,137
    Debt-adjusted trust units outstanding
     at year end (000's)                       147,997    136,562    129,172
    Reserves per debt-adjusted
     trust unit (BOE/unit)                        2.97       3.25       3.48
    Reserves per debt and distribution
     adjusted trust unit (BOE/unit)               5.43       5.32       5.19
    -------------------------------------------------------------------------

    HEALTH, SAFETY & ENVIRONMENT ("HS&E")

    Enerplus continued to place a high emphasis on our HS&E program
throughout the year. We maintained our participation in the Canadian
Association of Petroleum Producer's stewardship program at the highest level,
Platinum, reduced our reportable spills and pipeline failures, increased our
remediation, reclamation and abandonment spending and had one of the best
safety records in our history.
    Enerplus' safety performance record in 2007 saw no employee lost-time
injury incidents and only one employee medical aid injury recorded. This
resulted in a recordable injury frequency rate of 0.17 injuries per
200,000 man hours compared to 1.43 injuries per 200,000 man hours in 2006. In
addition, our contractor lost-time injury frequency substantially improved
from 0.97 injuries per 200,000 man hours in 2006 to a rate of 0.10 injuries in
2007. This improvement equates to having only one contractor lost-time injury
incident in all of 2007.
    Remediation, reclamation and abandonment expenditures increased 31% year-
over-year to $20.5 million in 2007. Reclamation and site abandonment
expenditures for 2007 totaled $8.2 million up $2.1 million from 2006
expenditures due mainly to an increase in the number of wells abandoned during
the year. Site abandonment and reclamation occurs when areas are returned to
their original state once operations have been completed. Enerplus' 2007
reclamation activities resulted in 27 reclamation certificates being received
and 111 Phase II environmental assessments being completed. Remediation
expenditures for 2007 totaled $12.3 million up from $9.6 million in 2006.

    MANAGEMENT'S DISCUSSION AND ANALYSIS ("MD&A")

    The following discussion and analysis of financial results is dated
February 27, 2008 and is to be read in conjunction with the audited
consolidated financial statements as at and for the years ended December 31,
2007 and 2006. All amounts are stated in Canadian dollars unless otherwise
specified. All references to GAAP refer to Canadian generally accepted
accounting principles. All note references relate to the notes included with
the consolidated financial statements. In accordance with Canadian practice
revenues are reported on a gross basis, before deduction of Crown and other
royalties, unless otherwise stated. In addition to disclosing reserves under
the requirements of NI 51-101, we also disclose our reserves on a company
interest basis which is not a term defined under NI 51-101. This information
may not be comparable to similar measures presented by other issuers. Where
applicable, natural gas has been converted to barrels of oil equivalent
("BOE") based on 6 Mcf:1 BOE. The BOE rate is based on an energy equivalent
conversion method primarily applicable at the burner tip and does not
represent a value equivalent at the wellhead. Use of BOE in isolation may be
misleading.
    The following MD&A contains forward-looking information and statements.
We refer you to the end of this news release for our disclaimer on forward-
looking information and statements.

    NON-GAAP MEASURES

    Throughout the MD&A we use the term "payout ratio" to analyze operating
performance, leverage and liquidity. We calculate payout ratio by dividing
cash distributions to unitholders ("cash distributions") by cash flow from
operating activities ("cash flow"), both of which appear on our consolidated
statements of cash flows. The term "payout ratio" does not have a standardized
meaning or definition as prescribed by GAAP and therefore may not be
comparable with the calculation of similar measures by other entities.
    Refer to the Liquidity and Capital Resources section of the MD&A for
further information on cash flow, cash distributions and payout ratio.

    2007 OVERVIEW

    Cash flow from operating activities totaled $868.5 million in 2007,
essentially flat over 2006. Higher realized crude oil prices, cash gains
generated from our price risk management program and a decrease in our non-
cash working capital helped to mitigate the impact of lower production,
reduced natural gas prices and increased operating costs. Monthly cash
distributions remained constant at $0.42 per trust unit throughout 2007 for an
annual total of $5.04 per trust unit.
    Our 2007 development capital spending totaled $387.2 million, resulting
in the drilling of 252 net wells with a 99% success rate. On January 31, 2007
we acquired gross-overriding royalty interests in the Jonah natural gas field
in Wyoming U.S. ("Jonah") for approximately $61 million. In the second quarter
we acquired the Kirby Oil Sands Partnership ("Kirby"), an operated Steam
Assisted Gravity Drainage ("SAGD") project, for $203.1 million ($148.3 million
in cash and $54.8 million in equity). An equity offering consisting of
4.25 million trust units for gross proceeds of $210.6 million was also
completed in conjunction with the Kirby acquisition.
    During 2007 production averaged 82,319 BOE/day, in-line with our third
quarter guidance of 82,500 BOE/day and 4% below our 2006 production of
85,779 BOE/day. Reduced development capital spending, unplanned downtime,
lower initial production rates on our third well per section Bakken oil wells
and natural reservoir declines are the primary reasons for the decrease.
    On June 22, 2007 the Federal Government enacted a new tax on publicly
traded income trusts and limited partnerships (specified investment flow-
through entities, or "SIFTs") effective January 1, 2011. As a result we
recorded a $78.1 million future income tax expense. We are currently
evaluating alternatives to determine the optimal structure for Enerplus post
2010 to maximize the return to investors. However, we see value in the
remaining three-year tax exemption period through 2010 and currently look to
maintaining our current structure during this period unless there are
compelling reasons to change. In the fourth quarter of 2007 the Alberta
Government also announced proposed changes to the provincial royalty program
effective January 1, 2009 which have not yet been enacted into law.
    On February 13, 2008 we successfully closed the largest transaction in
our 22 year history, acquiring Focus Energy Trust ("Focus") for total
consideration of approximately $1.7 billion including approximately
$340 million of assumed debt. Under the plan of arrangement, Focus unitholders
received 0.425 of an Enerplus trust unit for each Focus trust unit. We believe
the combined entity is well positioned for future growth with a strong balance
sheet and production expected to be approximately 98,000 BOE/day in 2008.

    RESULTS OF OPERATIONS

    Production

    Production during 2007 averaged 82,319 BOE/day, in-line with our third
quarter guidance of 82,500 BOE/day and 4% lower than 85,779 BOE/day in 2006.
Our 2007 production was impacted by the fact that we spent $104 million or 21%
less development capital than the prior year. In addition we experienced
unexpected down time and turn-around activities at partner operated
facilities. Our third well per section program at our U.S. Bakken property had
lower initial production rates than originally forecast; however the program
continues to deliver attractive economics and reserves. These decreases were
partially offset by production from our acquisition of Jonah that closed
January 31, 2007.
    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, 2007 and 2006 are outlined below:

    Daily Production Volumes                      2007       2006   % change
    -------------------------------------------------------------------------
    Natural gas (Mcf/day)                      262,254    270,972       (3)%
    Crude oil (bbls/day)                        34,506     36,134       (5)%
    Natural gas liquids (bbls/day)               4,104      4,483       (8)%
    Total daily sales (BOE/day)                 82,319     85,779       (4)%
    -------------------------------------------------------------------------

    We exited the year with production of approximately 79,800 BOE/day based
on December's average production rate, 4% below our exit target of 83,000
BOE/day. Approximately 2,000 BOE/day of the decrease related to a previously
announced fire that occurred at our Giltedge property on November 30, 2007. We
expect production from this property to be back on-line by mid-2008. We have
both business interruption insurance and property insurance which we
anticipate will mitigate the majority of these losses. The remainder of the
1,200 BOE/day difference related to tie-in delays primarily on non-operated
capital projects at year end and pipeline problems at our non-operated Mitsue
property.
    Considering our acquisition of Focus that closed on February 13, 2008 and
our current development capital program, we expect 2008 annual production
volumes to average 98,000 BOE/day, weighted 60% to natural gas and 40% to
liquids. We expect to exit 2008 with production of approximately
100,000 BOE/day. This guidance does not contemplate any other 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 2007 with those of 2006. It also
compares the benchmark price indices for the same periods.

    Average Selling Price(1)                      2007       2006   % Change
    -------------------------------------------------------------------------
    Natural gas (per Mcf)                     $   6.45   $   6.81       (5)%
    Crude oil (per bbl)                       $  65.11   $  61.80         5%
    Natural gas liquids (per bbl)             $  51.35   $  50.90         1%
    Per BOE                                   $  50.48   $  50.23         -%
    -------------------------------------------------------------------------
    (1) Net of oil and gas transportation costs, but before the effects of
        commodity derivative instruments



    Average Benchmark Pricing                     2007       2006   % Change
    -------------------------------------------------------------------------
    AECO natural gas - monthly index
     (CDN$/Mcf)                               $   6.61   $   6.99       (5)%
    AECO natural gas - daily index
     (CDN$/Mcf)                               $   6.45   $   6.53       (1)%
    NYMEX natural gas - monthly NX3 index
     (US$/Mcf)                                $   6.92   $   7.26       (5)%
    NYMEX natural gas - monthly NX3 index:
     CDN$ equivalent (CDN$/Mcf)               $   7.44   $   8.25      (10)%
    WTI crude oil (US$/bbl)                   $  72.34   $  66.22         9%
    WTI crude oil: CDN$ equivalent
     (CDN$/bbl)                               $  77.78   $  75.25         3%
    CDN$/US$ exchange rate                        0.93       0.88         6%
    -------------------------------------------------------------------------

    Natural Gas

    Natural gas prices started 2007 in a weak position due to a mild December
2006. However cold weather across key consuming regions of the United States
from the latter part of January 2007 through to March resulted in increased
prices. Early forecasts for an active hurricane season led to an expectation
that strong prices would carry into and through the summer. However, this past
year marked a changing dynamic in global liquefied natural gas ("LNG") trade,
with cargos more readily shifting between Asia, Europe, and North America
depending on spot market prices and access to storage. Accordingly, low demand
in Europe pushed significant volumes of LNG to North America from March
through August. This LNG, along with continued strong North American
production, resulted in high U.S. and Canadian storage balances by the end of
the summer which depressed prices. Natural gas prices during the year traded
within a band that saw highs of approximately $8.00/Mcf during the winter and
lows of around $5.00/Mcf at the end of the summer injection season. This was a
narrower band than was experienced during 2006 where natural gas prices
fluctuated between $12.00/Mcf and $4.00/Mcf.
    Our natural gas portfolio in 2007 was comprised of aggregator, AECO, and
downstream direct sales. In 2007 we sold 40% of our natural gas on the daily
AECO market and 40% on the monthly AECO market, as well as 20% against the day
and month NYMEX indices. During 2007 we realized an average price for our
natural gas sales of $6.45/Mcf (net of transportation costs), a decrease of 5%
from $6.81/Mcf realized in 2006. This reduction is comparable to the price
decreases realized in each of: the AECO monthly index which decreased by 5%;
the AECO daily index which decreased by 1%; and the NYMEX monthly index
(converted to CDN$/Mcf) which decreased by 10%.

    Crude Oil

    Crude prices were weak in the first quarter of 2007, with a low of
US$50.48/bbl. Prices rose steadily through the remaining months reaching a
high of US$98.18/bbl in mid November. In terms of market fundamentals, OPEC
kept its supply constant, non-OPEC production was lower than expected and
growth demands in Asia remained strong. As a result, global crude and refined
product inventories declined. In addition there was growing concern global
production was reaching its peak. These fundamentals placed steady upward
pressure on crude oil prices through the year.
    Our crude oil portfolio in 2007 was approximately 74% light/medium and
26% heavy. The average price received for our crude oil (net of transportation
costs) was CDN$65.11/bbl during 2007, a 5% increase over 2006. The West Texas
Intermediate ("WTI") crude oil benchmark price, after adjusting for the change
in the US$ exchange rate, increased 3% year-over-year. On average for 2007,
the slight narrowing of the light to heavy differential had a positive effect
on our overall crude oil and gas sales. However, in the fourth quarter of
2007, and in particular in December, absolute heavy oil differentials to WTI
widened significantly due to a number of factors, including: outages of
refineries with heavy oil conversion capabilities; drawdown of inventories
prior to year end; and operational issues on key intra-Alberta and export
pipelines. These differentials reverted to historical levels in January 2008.
    The Canadian dollar opened 2007 at an exchange rate of $0.86/US$ and
strengthened throughout the year hitting a high in November of $1.09/US$ and
ending the year at $0.99/US$. On average it strengthened 6% against the U.S.
dollar during 2007 compared to 2006 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.
    Historically we have not attempted to hedge against fluctuations in the
foreign exchange value of our oil and gas sales. In the fourth quarter of 2007
we entered into a foreign exchange swap on our US$54 million debentures which
effectively fixed the principal repayments at a CAN/US dollar exchange rate of
1.02.

    Price Risk Management

    While we believe that the overall energy outlook remains generally
bullish long term, the threat of a U.S. recession reducing demand for crude
oil and natural gas requires prudent management of our commodity price
exposure.
    We have developed a price risk management framework to respond to the
volatile price environment in a measured 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 and maintain participation in upside potential should commodity
prices increase.
    Consistent with our price risk management framework, we entered into
additional commodity contracts during the fourth quarter of 2007 and during
the first quarter of 2008. These contracts are designed to protect a portion
of our natural gas sales for the period January 2008 through March 2009 and to
protect a portion of our crude oil sales for the period January 2008 through
December 2009. We have also hedged electricity volumes for the period January
2008 through December 2009 to protect against rising electricity costs in the
Alberta power market. See Note 12 for a detailed list of our current price
risk management positions including positions we assumed through the Focus
acquisition.
    The following is a summary of the financial contracts in place at
February 20, 2008, including positions entered into by Focus, expressed as a
percentage of our forecasted net production volumes:

                                                      Natural Gas
                                                       (CDN$/Mcf)
                                        -------------------------------------
                                         January 1,     April 1,  November 1,
                                            2008 -       2008 -       2008 -
                                          March 31,  October 31,    March 31,
                                              2008         2008         2009
    -------------------------------------------------------------------------
    Floor Prices (puts)                     $ 8.28       $ 7.06       $ 8.18
    % (net of royalties)                       18%          24%           4%

    Fixed Price (swaps)                     $ 8.73       $ 7.16       $    -
    % (net of royalties)                       11%          16%          - %

    Capped Price (calls)                    $10.12       $ 8.22       $10.10
    % (net of royalties)                       19%          24%           4%
    -------------------------------------------------------------------------


                                                       Crude Oil
                                                       (US$/bbl)
                                        -------------------------------------
                                         January 1,      July 1,   January 1,
                                            2008 -       2008 -       2009 -
                                           June 30, December 31, December 31,
                                              2008         2008         2009
    -------------------------------------------------------------------------
    Floor Prices (puts)                     $70.91       $72.09       $77.63
    % (net of royalties)                       35%          35%          10%

    Fixed Price (swaps)                     $79.95       $79.97       $    -
    % (net of royalties)                       17%          19%          - %

    Capped Price (calls)                    $85.09       $85.48       $92.98
    % (net of royalties)                       23%          22%          10%
    -------------------------------------------------------------------------
    Based on weighted average price (before premiums), estimated average
    annual production of 98,000 BOE/day and assuming a 19% royalty rate.

    Accounting for Price Risk Management

    During 2007, our commodity price risk management program generated cash
gains of $23.6 million on our natural gas contracts and cash losses of
$10.0 million on our crude oil contracts. The natural gas cash gains are due
to contracts in place during 2007 that provided floor protection as the price
of natural gas declined. The crude oil cash losses are due to crude oil prices
rising above our swap positions. In comparison, our 2006 commodity price risk
management program resulted in cash losses of $7.1 million on our natural gas
contracts and $27.2 million on our crude oil contracts.
    At December 31, 2007 the fair value of our natural gas and crude oil
derivative instruments, net of premiums, represents a gain of $9.7 million and
a loss of $52.5 million, respectively. The natural gas gain is recorded as a
current deferred financial asset on our balance sheet and the crude oil loss
is recorded as a current deferred financial credit. In comparison, at
December 31, 2006 the fair value of our natural gas and crude oil derivative
instruments represented gains of $12.7 million and $10.9 million respectively,
both of which were recorded on our balance sheet as deferred financial assets.
The change in the fair value of these financial contracts year-over-year
resulted in unrealized losses of $3.0 million for natural gas and
$63.4 million for crude oil. 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 non-cash
gain in earnings. See Note 3 for details.
    The following table summarizes the effects of our financial contracts on
income for the years ended December 31, 2007 and 2006.

    Risk Management Costs
    ($ millions, except
     per unit amounts)               2007                      2006
    -------------------------------------------------------------------------
    Cash gains/(losses):
      Natural gas         $      23.6  $  0.25/Mcf  $      (7.1) $(0.07)/Mcf
      Crude oil                 (10.0) $(0.79)/bbl        (27.2) $(2.06)/bbl
                          ------------              ------------
    Total cash
     gains/(losses)       $      13.6  $  0.45/BOE  $     (34.3) $(1.10)/BOE

    Non-cash
     (losses)/gains on
     financial contracts:
      Change in fair value
       - natural gas      $      (3.0) $(0.03)/Mcf  $      50.6  $  0.51/Mcf
      Change in fair value
       - crude oil              (63.4) $(5.03)/bbl         30.4  $  2.30/bbl
      Amortization of
       deferred financial
       assets                       -  $    - /BOE        (49.9) $(1.59)/BOE
                          ------------              ------------
    Total non-cash
     (losses)/gains       $     (66.4) $(2.21)/BOE  $      31.1  $  0.99/BOE
                          ------------              ------------
    Total (losses)        $     (52.8) $(1.76)/BOE  $      (3.2) $(0.11)/BOE
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    Cash Flow Sensitivity

    The sensitivities below reflect all commodity contracts as described in
Note 12 (including those entered into by Focus) and are based on 2008 forward
markets as at February 20, 2008. 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.

                                                   Estimated Effect on 2008
    Sensitivity Table                            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                                      $0.06
    Change of 1,000 BOE/day in production                  $0.10
    Change of $0.01 in the US$/CDN$ exchange rate          $0.12
    Change of 1% in interest rate                          $0.07
    -------------------------------------------------------------------------
    (1) Assumes constant working capital and 129,813,000 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, 2007
were $1,517.1 million ($1,539.2 million, net of $22.1 million of
transportation costs), a decrease of 4% or $55.6 million compared to
$1,572.7 million ($1,595.3 million, net of $22.6 million of transportation
costs) during 2006. Decreased production and lower natural gas prices were
partially offset by an increase in realized crude oil prices.

    Analysis of Sales Revenue(1)                          Natural
     ($ millions)                 Crude oil       NGLs        Gas      Total
    -------------------------------------------------------------------------
    2006 Sales Revenue               $815.0      $83.3     $674.4   $1,572.7
    Price variance(1)                  41.8        0.7      (33.8)       8.7
    Volume variance                   (36.7)      (7.1)     (20.5)     (64.3)
    -------------------------------------------------------------------------
    2007 Sales Revenue               $820.1      $76.9     $620.1   $1,517.1
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    (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 2007 and 2006 were approximately 19% of
oil and gas sales, net of transportation costs. Overall, royalties decreased
marginally in 2007 to $285.1 million compared to $296.6 million during 2006
primarily as a result of the decrease in natural gas revenue experienced over
the period.
    We expect royalties to be approximately 19% of oil and gas sales, net of
transportation costs for 2008.

    Alberta Royalty Review

    On October 25, 2007 the Alberta government announced the 'New Royalty
Framework' ("NRF"), an updated royalty regime proposed to be effective
January 1, 2009 which is intended to increase Government royalty revenue by
20%. On conventional oil and gas production during 2007, Alberta Crown
royalties were $122.1 million (43%) of our total royalties. Based on this
royalty rate and in the context of our production and pricing experienced
during 2007, we estimate that the NRF would have increased the royalties on
our conventional production by approximately $15 to $20 million. The
acquisition of Focus in 2008 will help to mitigate the effects of the Alberta
royalty review as the production from Focus is concentrated in Saskatchewan
and British Columbia.
    The moderate royalty increase is a reflection of the NRF's sensitivity to
our portfolio, which includes lower productivity wells combined with the low
natural gas prices experienced in 2007. It is important to note that this
context may not be indicative of the environment in 2009 when the NRF comes
into effect. The fundamental design of the new Alberta regime (which increases
royalty rates as commodity prices increase) has removed some of the price
upside producers had previously factored into their risk assessments for
capital investment. As a result, Alberta will not be as attractive to invest
in as other jurisdictions that allow greater participation in price upside.
    The Alberta government is currently working with industry to address
"unintended consequences" of economic issues related to the NRF and as at the
date of this MD&A the Alberta government had not yet made the necessary
legislative and administration changes to implement the NRF. The NRF
announcement can be found on the Alberta government's website at
www.gov.ab.ca.

    Operating Expenses

    Operating expenses during 2007 were $9.12/BOE or $274.2 million,
representing a 1% decrease from our third quarter guidance of $9.20/BOE and a
14% increase from $8.02/BOE in 2006. Operating expenses for the year were
lower than our guidance primarily due to lower than expected electricity
charges during the fourth quarter. The increase in operating costs over 2006
was due to the combination of increased labour, well servicing, and repairs
and maintenance costs along with lower production volumes during 2007. A field
training initiative in 2007 directed at optimizing production and reducing the
time required to drill, complete and bring new wells on stream also
contributed to the year-over-year increase.
    By combining the lower cost operating expenses associated with the Focus
properties we expect operating costs for 2008 to average $8.65/BOE,
representing a decrease of 5% per BOE compared to 2007.

    General and Administrative Expenses ("G&A")

    G&A expenses were $2.26/BOE or $67.9 million for the year ended
December 31, 2007, approximately 6% lower than our guidance of $2.40/BOE and
18% higher than $1.91/BOE in 2006. G&A expenses were lower than our guidance
primarily due to lower than anticipated long term cash compensation charges
related to our performance trust unit plan ("PTU") which is impacted by our
trust unit price. The increase in general and administrative costs over 2006
was mainly due to increased overall salary and benefits as a result of
continued wage inflation, increased staff and lower production volumes during
2007.
    For the year ended December 31, 2007 our G&A expenses included non-cash
charges for our trust unit rights incentive plan of $8.4 million or $0.28/BOE
compared to $6.3 million or $0.20/BOE for 2006. These amounts relate solely to
our trust unit rights incentive plan and are determined using a binomial
lattice option-pricing model. The volatility of our trust unit price combined
with the increased number of rights outstanding associated with additional
employees increased the non-cash cost of the plan. Although non-cash charges
have increased as a result of the option pricing model, the proportion of
rights that are "in-the-money" has decreased in comparison with 2006. See
Note 10 for further details.

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

    General and Administrative Costs ($ millions)            2007       2006
    -------------------------------------------------------------------------
    Cash                                                    $59.5      $53.6
    Trust unit rights incentive plan (non-cash)               8.4        6.3
    -------------------------------------------------------------------------
    Total G&A                                               $67.9      $59.9
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------



    (Per BOE)                                                2007       2006
    -------------------------------------------------------------------------
    Cash                                                    $1.98      $1.71
    Trust unit rights incentive plan (non-cash)              0.28       0.20
    -------------------------------------------------------------------------
    Total G&A                                               $2.26      $1.91
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    In 2008 we expect total G&A costs to decrease slightly to approximately
$2.20/BOE, including non-cash G&A costs of approximately $0.20/BOE.

    Interest Expense

    With the adoption of the new accounting standards on January 1, 2007
interest expense includes interest on long-term debt, the premium amortization
on our US$175 million senior unsecured notes, unrealized gains and losses
resulting from the change in fair value of our interest rate swaps as well as
the interest component on our cross currency interest rate swap (see Note 8).
    Interest on long-term debt during 2007 totaled $41.9 million, a
$9.7 million increase from $32.2 million in 2006. The increase was due to
higher average indebtedness and a higher weighted average interest rate of
5.1% during 2007 compared to 4.8% in 2006.
    The following table summarizes the cash and non-cash interest expense
recorded.

    Interest Expense ($ millions)                            2007       2006
    -------------------------------------------------------------------------
    Interest on long-term debt                              $41.9      $32.2
    Unrealized gain                                          (8.3)         -
    -------------------------------------------------------------------------
    Total Interest Expense                                  $33.6      $32.2
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    At December 31, 2007 approximately 18% of our debt was based on fixed
interest rates while 82% had floating interest rates.

    Capital Expenditures

    During 2007 we spent $387.2 million on development capital and
facilities, which is $104.0 million or 21% less than 2006. Spending in 2007
was in-line with our guidance of $390.0 million. Development capital spending
was lower in 2007 as we spent less on natural gas development due to
decreasing natural gas prices and increasing drilling and servicing costs.
Development in 2007 focused primarily on Bakken oil and waterfloods. We
achieved a 99% success rate with our drilling program on 252 net wells drilled
during 2007.
    Property acquisitions were $274.2 million during 2007 compared to
$51.3 million in 2006. The majority of our 2007 acquisitions related to the
purchase of Kirby for total consideration of $203.1 million and the purchase
of gross-overriding royalty interests in the Jonah area for approximately
$61.0 million. Property dispositions were $9.6 million during 2007 compared to
$21.1 million in 2006. Our 2007 divestments included $5.6 million of property
interests in the Thorhild area and the sale of 36,000 net acres of undeveloped
land in North Dakota for approximately $3.6 million. Divestments in 2006
primarily related to the $19.7 million sale of a 1% working interest in the
Joslyn property.

    Capital Expenditures ($ millions)                        2007       2006
    -------------------------------------------------------------------------
    Development expenditures                            $   321.3  $   380.5
    Plant and facilities                                     65.9      110.7
    -------------------------------------------------------------------------
      Development Capital                                   387.2      491.2
    Office                                                    6.5        5.0
    -------------------------------------------------------------------------
      Sub-total                                             393.7      496.2
    Acquisitions of oil and gas properties(1)               274.2       51.3
    Dispositions of oil and gas properties(1)                (9.6)     (21.1)
    -------------------------------------------------------------------------
    Total Net Capital Expenditures                      $   658.3  $   526.4
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    Total Capital Expenditures financed with cash flow  $   221.7  $   249.4
    Total Capital Expenditures financed
     with debt and equity                                   443.2      296.5
    Total non-cash consideration
     for property dispositions                               (6.6)     (19.5)
    -------------------------------------------------------------------------
    Total Net Capital Expenditures                      $   658.3  $   526.4
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    (1) Net of post-closing adjustments.

    The following is a summary by play type of our development capital
expenditures during 2007 and 2006, as well as our current expectations for
2008 including Focus.

    Play type ($ millions)               2008 Estimate       2007       2006
    -------------------------------------------------------------------------
    Shallow Gas and CBM                         $128.0      $39.3      $94.0
    Crude Oil Waterfloods                        105.0       54.2       66.0
    Deep Tight Gas                                53.0       34.7       34.1
    Bakken Oil                                    47.0      106.2      116.7
    Other Conventional Oil and Gas               142.0      113.9      141.3
    Oil Sands                                    105.0       38.9       39.1
    -------------------------------------------------------------------------
    Total                                       $580.0     $387.2     $491.2
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    We currently expect total development capital expenditures in 2008 to be
approximately $580 million. Conventional development capital is presently
anticipated to be approximately $475 million with a slight bias to oil related
projects over natural gas projects. Oil sands development capital is currently
projected to be approximately $105 million.

    Oil Sands

    Our Joslyn and Kirby development projects have not commenced commercial
production. As a result all associated costs, net of revenues generated, are
capitalized and excluded from our depletion calculation. During 2007 we
capitalized costs of $35.2 million on Joslyn and $205.4 million on Kirby,
inclusive of acquisition costs, development capital spending, salaries and
benefits, engineering and planning. At December 31, 2007 capitalized costs
life-to-date for Joslyn were $116.4 million and for Kirby were $205.4 million
for a combined total of $321.8 million.

    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, 2007 DDA&A of $15.43/BOE is comparable to $15.38/BOE during the
year ended December 31, 2006.
    No impairment existed at December 31, 2007 using year-end reserves and
management's estimates of future prices. Our future price estimates are more
fully discussed in Note 4.

    Asset Retirement Obligations

    We have estimated our total future asset retirement obligations based on
our net ownership interest in wells and facilities, along with the estimated
cost and timing to abandon and reclaim wells and facilities in future periods.
Our asset retirement obligation was $165.7 million at December 31, 2007
compared to $123.6 million at December 31, 2006. The majority of the
$42.1 million increase was due to increased cost estimates as a result of
enhanced regulatory requirements on abandonment and reclamation activities.
The remainder of the change was due to retirement costs incurred, offset by
accretion expense for the year. See Note 5 for further details.
    The following chart compares the amortization of the asset retirement
cost, accretion of the asset retirement obligation, and asset retirement
obligations settled.

    ($ millions)                                             2007       2006
    -------------------------------------------------------------------------
    Amortization of the asset retirement cost               $11.4      $12.6
    Accretion of the asset retirement obligation              6.7        6.2
    -------------------------------------------------------------------------
    Total Amortization and Accretion                        $18.1      $18.8
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    Asset Retirement Obligations Settled                    $16.3      $11.5
    -------------------------------------------------------------------------

    Actual asset retirement costs are 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 2038
and 2047. 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

    Canadian Government's tax changes

    On June 22, 2007 Bill C-52, which contained legislative provisions to
implement the proposals to tax publicly traded income trusts in Canada became
law. As a result, our second quarter future income tax provision included a
future income tax expense of $78.1 million related to this legislation. This
non-cash expense related to temporary differences between the accounting and
tax basis of the Fund's assets and liabilities at that time and had no
immediate impact on cash flow.
    On December 14, 2007, Bill C-28, which contained legislative provisions
to implement corporate income tax rate reductions announced in the October 30,
2007 fall economic statement, became law. The general corporate tax rate will
decrease by 1.0% in 2008 from 20.5% to 19.5%. There are additional rate
reductions scheduled until the target federal tax rate of 15.0% is reached as
of January 1, 2012. These rate reductions will also apply to the SIFT tax from
income trusts. As a result, our fourth quarter future income tax provision
includes a future income tax recovery of $22.6 million related to this
legislation.

    Future Income Taxes

    Future income taxes arise from differences between the accounting and tax
basis of assets and liabilities. A portion of the future income tax liability
that is recorded on the balance sheet will be recovered through earnings
before 2011. The balance will be realized when future income tax assets and
liabilities are realized or settled.
    As a result of the SIFT tax, all entities within our organization are now
subject to future income taxes whereas prior to the SIFT tax enactment only
incorporated entities in our organization were subject to future income taxes.
As a result our future income tax recovery was $1.0 million for the year ended
December 31, 2007 compared to a recovery of $112.0 million for the same period
in 2006. The changes in future income taxes compared to 2006 are primarily a
result of the following:

    -   The SIFT tax resulted in a future income tax expense of $78.1 million
        in the second quarter of 2007; and
    -   Corporate income tax rate changes enacted during the year have
        resulted in a year-to-date future tax recovery of $22.6 million
        compared to a $35.5 million recovery in 2006.

    After consideration of the above items, the future income tax provisions
were comparable between the periods.

    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. However, effective January 1, 2011 we
will be subject to the SIFT tax should we remain a trust.
    The amount of current taxes recorded throughout the year on our U.S.
operations is dependent upon 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 11% in 2007 compared to our
guidance of 10%. We expect the current income and withholding taxes to average
approximately 20% of cash flow from U.S. operations in 2008 based on our
current development capital program and assuming all funds are repatriated to
Canada after U.S. development capital spending. The increase for 2008 is a
result of plans for reduced development capital spending in the U.S. during
the year.
    During 2007 our U.S. operations incurred income related taxes in the
amount of $23.0 million compared to $18.2 million in 2006. The increase in
current taxes is due to an increase in net income combined with a modest
decrease in drilling and completion expenditures for the year.

    Tax Pools

    We estimate our tax pools at December 31, 2007 to be as follows:

                                                        Operating
    Pool Type ($ millions)                       Trust   entities      Total
    -------------------------------------------------------------------------
    COGPE                                         $470      $ 100      $ 570
    CDE                                              -        340        340
    UCC                                              -        600        600
    Tax losses and other                            30        600        630
    Foreign tax pools                                -        140        140
    -------------------------------------------------------------------------
    Total                                         $500     $1,780     $2,280
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    We acquired approximately $200 million in tax pools related to the Focus
acquisition (net of any pools required to offset partnership deferrals).

    Net Income

    Net income in 2007 was $339.7 million or $2.66 per trust unit compared to
$544.8 million or $4.48 per trust unit in 2006. The $205.1 million decrease in
net income was primarily due to a $111.0 million decrease in future income tax
recovery, a $49.6 million increase in cash and non-cash risk management costs,
a $55.6 million decrease in oil and gas sales (net of transportation costs)
and a $22.9 million increase in operating costs, partially offset by an
increase in other income of $12.5 million and decreased DDA&A charges of
$17.9 million.

    Cash Flow from Operating Activities

    Cash flow from operating activities in 2007 was $868.5 million or $6.80
per trust unit compared to $863.7 million or $7.10 per trust unit in 2006. The
decrease on a per unit basis is largely due to the April 2007 equity offering,
which was primarily used to purchase Kirby, a development project that is not
currently generating cash flow.

    Selected Financial Results

                          Year ended December 31,   Year ended December 31,
                                   2007                       2006
                      Operating Non-Cash         Operating Non-Cash
    Per BOE of             Cash  & Other              Cash  & Other
     production (6:1)    Flow(1)   Items    Total   Flow(1)   Items    Total
    -------------------------------------------------------------------------
    Production per day                     82,319                     85,779
    -------------------------------------------------------------------------
    Weighted average
     sales price(2)      $50.48  $     -   $50.48   $50.23  $     -   $50.23
    Royalties             (9.49)       -    (9.49)   (9.47)       -    (9.47)
    Commodity
     derivative
     instruments           0.45    (2.21)   (1.76)   (1.10)    0.99    (0.11)
    Operating costs       (9.11)   (0.01)   (9.12)   (8.02)       -    (8.02)
    General and
     administrative       (1.98)   (0.28)   (2.26)   (1.71)   (0.20)   (1.91)
    Interest expense,
     net of interest
     income               (1.37)    0.28    (1.09)   (0.95)       -    (0.95)
    Foreign exchange
     gain/(loss)          (0.06)    0.30     0.24     0.02        -     0.02
    Current income tax    (0.77)       -    (0.77)   (0.59)       -    (0.59)
    Restoration and
     abandonment
     cash costs           (0.54)    0.54        -    (0.37)    0.37        -
    Depletion,
     depreciation,
     amortization and
     accretion                -   (15.43)  (15.43)       -   (15.38)  (15.38)
    Future income tax
     (expense)/recovery       -     0.04     0.04        -     3.58     3.58
    Marketable
     securities(3)            -     0.47     0.47        -        -        -
    -------------------------------------------------------------------------
    Total per BOE        $27.61  $(16.30)  $11.31   $28.04  $(10.64)  $17.40
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    (1) Cash Flow from Operating Activities before changes in non-cash
        operating working capital.
    (2) Net of oil and gas transportation costs, but before the effects of
        commodity derivative instruments.
    (3) In addition to non-cash shares of marketable securities, a gain on
        sale of marketable securities was a cash item; however the cash item
        is included in cash flow from investing activities not cash flow from
        operating activities.

    Selected Annual Canadian and U.S. Financial Results

    The following table provides a geographical analysis of key operating and
financial results for 2007 and 2006.


    (CDN$ millions, except                  Year ended December 31, 2007
     per unit amounts)                      Canada         U.S.        Total
    -------------------------------------------------------------------------
    Daily Production Volumes
      Natural gas (Mcf/day)                251,561       10,693      262,254
      Crude oil (bbls/day)                  24,590        9,916       34,506
      Natural gas liquids (bbls/day)         4,104            -        4,104
      Total daily sales (BOE/day)           70,621       11,698       82,319

    Pricing(1)
      Natural gas (per Mcf)             $     6.45  $      6.55  $      6.45
      Crude oil (per bbl)               $    62.27  $     72.17  $     65.11
      Natural gas liquids (per bbl)     $    51.35  $         -  $     51.35

    Capital Expenditures
      Development capital and office    $    287.3  $     106.4  $     393.7
      Acquisitions of oil
       and gas properties               $    213.3  $      60.9  $     274.2
      Dispositions of oil
       and gas properties               $     (6.0) $      (3.6) $      (9.6)

    Revenues
      Oil and gas sales(1)              $  1,230.4  $     286.7  $   1,517.1
      Royalties                         $   (226.4) $  (58.7)(2) $    (285.1)
      Commodity derivative instruments  $    (52.8) $         -  $     (52.8)

    Expenses
      Operating                         $    264.4  $       9.8  $     274.2
      General and administrative        $     62.6  $       5.3  $      67.9
      Depletion, depreciation,
       amortization and accretion       $    359.8  $     103.9  $     463.7
      Current income taxes              $        -  $      23.0  $      23.0
    -------------------------------------------------------------------------


    (CDN$ millions, except                  Year ended December 31, 2006
     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 Expenditures
      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                         $   (244.4) $  (52.2)(2) $    (296.6)
      Commodity derivative instruments  $     (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.

    Three Year Summary of Key Measures

    Overall, lower production volumes have resulted in lower oil and gas sales
and net income during 2007 as compared to 2006. The rise in crude oil prices
during 2005, 2006 and 2007 contributed to higher oil and gas sales, however
sales moderated in 2007 as a result of lower natural gas prices and
production. The following table provides a summary of net income, cash flow
and other key measures.

    ($ millions, except per unit amounts)         2007       2006       2005
    -------------------------------------------------------------------------
    Oil and gas sales(1)                      $1,517.1   $1,572.7   $1,523.7

    Net income                                   339.7      544.8      432.0
    Per unit (Basic)(2)                           2.66       4.48       3.96
    Per unit (Diluted)                            2.66       4.47       3.95

    Cash flow from operating activities          868.5      863.7      774.6
    Per unit (Basic)(2)                           6.80       7.10       7.10

    Cash distributions                           646.8      614.3      498.2
    Per unit (Basic)(2)                           5.07       5.05       4.57
    Payout ratio                                   74%        71%        64%

    Total assets                               4,303.1    4,203.8    4,130.6

    Long-term debt, net of cash                  725.0      679.7      649.8
    -------------------------------------------------------------------------
    (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 actual distributions
        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 producer we have a declining asset base and therefore
rely on ongoing development activities and acquisitions to replace production
and add additional reserves. Our future oil and natural gas production is
highly dependent on our success in exploiting our asset base and acquiring or
developing additional reserves. To the extent we are unsuccessful in these
activities our cash distributions could be reduced.
    Development activities and acquisitions 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 to our unitholders
may be reduced. Should external sources of capital become limited or
unavailable, our ability to make the necessary development expenditures and
acquisitions to maintain or expand our asset base may be impaired and
ultimately reduce the amount of cash distributions.
    Following the completion of the Focus acquisition, Enerplus has
approximately $10 billion of safe harbor growth capacity within the context of
the Government's "normal growth" guidelines associated with Bill C-52. This
amount is calculated in reference to the combined market capitalizations of
Enerplus and Focus on October 31, 2006 and also includes equity that may be
issued to replace existing debt of both entities at that time.

    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. To the extent there is
taxable income at the trust level, determined in accordance with the Canadian
Income Tax Act, the distribution of that taxable income is non-discretionary.

    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 2007 cash distributions
of $646.8 million were funded entirely through cash flow of $868.5 million.
Our payout ratio, which is calculated as cash distributions divided by cash
flow, was 74% for 2007 compared to 71% in 2006.
    Our cash outlays in 2007 were comprised of: $646.8 million of
distributions to unitholders, $393.7 million of development capital and office
expenditures and $209.8 million of acquisitions (net of dispositions) for a
total of $1,250.3 million. These cash outlays were financed with a combination
of: $868.5 million from cash flow from operating activities, $199.6 million
from the equity issue, $56.8 million from our distribution reinvestment plan
and trust unit rights incentive plan and an increase in our credit facility of
$148.8 million.
    In aggregate, our 2007 cash distributions of $646.8 million and our
development capital and office of $393.7 million totaled $1,040.5 million, or
approximately 120% of our cash flow of $868.5 million. We rely on access to
capital markets to the extent cash distributions and development capital
exceeds 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 when we are investing capital in opportunities that do not
immediately generate cash flow (such as our Joslyn and Kirby oil sands
projects) where this relationship will vary. Despite our 2007 cash flow being
less than the aggregate of our cash distributions and development capital, we
continue to have conservative debt levels with a trailing twelve month
debt-to- cash flow ratio of 0.8x at December 31, 2007.
    For the year ended December 31, 2007 our cash distributions exceeded our
net income by $307.1 million (2006 - $69.5 million). Net income includes
$520.3 million of non-cash items (2006 - $344.7 million) such as DDA&A,
changes in the fair value of our derivative instruments and future income
taxes that do not reduce our cash flow from operations. Future income taxes
can fluctuate from period to period as a result of changes in tax rates (such
as the enactment of the SIFT tax during the second quarter of 2007), changes
in the inter-company royalty, interest and dividends from our operating
subsidiaries paid to the Fund. In addition, other non-cash 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 environment.
    The level of investment in a given period may not be sufficient to
replace productive capacity given the natural declines associated with oil and
natural gas assets. In these instances a portion of the cash distributions
paid to unitholders may represent a return of the unitholders' capital.

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

    ($ millions, except per unit amounts)         2007       2006       2005
    -------------------------------------------------------------------------
    Cash flow  from operating activities     $   868.5  $   863.7  $   774.6
    Cash Distributions                           646.8      614.3      498.2
    -------------------------------------------------------------------------
    Excess of cash flow over
     cash distributions                      $   221.7  $   249.4  $   276.4

    Net income                               $   339.7  $   544.8  $   432.0
    Shortfall of net income over
     cash distributions                      $  (307.1) $   (69.5) $   (66.2)

    Cash distributions per
     weighted average trust unit             $    5.07  $    5.05  $    4.57
    Payout ratio(1)                                74%        71%        64%
    -------------------------------------------------------------------------
    (1) Based on cash distributions divided by cash flow from operating
        activities.

    It is not possible to distinguish between capital spent on maintaining
productive capacity and capital spent on growth opportunities in the oil and
gas sector due to the nature of reserve reporting, natural reservoir declines
and the risks involved with capital investment. Therefore we do not disclose
maintenance capital separately from development capital spending.

    Asset Retirement Costs

    Actual asset retirement costs incurred in the period are deducted for
purposes of calculating cash flow. Differences between actual asset retirement
costs incurred and the amortization and accretion of the asset retirement
obligation are discussed in the Asset Retirement Obligations section of the
MD&A and Note 5.

    Long-Term Debt

    Long-term debt at December 31, 2007 was $726.7 million, an increase of
$46.9 million from $679.8 million at December 31, 2006. Long-term debt at
December 31, 2007 is comprised of $497.3 million of bank indebtedness, which
increased $148.8 million from prior year and $229.3 million of senior
unsecured notes. With the adoption of the financial instrument accounting
standards (see Note 2) on January 1, 2007 we adjusted the carrying value of
our US$175 million senior unsecured notes to fair value of $208.2 million from
their previous carrying value of $268.3 million, a decrease of $60.1 million.
Subsequent to this adoption entry, our $175 million senior notes have
decreased a further $32.2 million as a result of the strengthening Canadian
dollar. Increases in long-term debt resulting from the Jonah and Kirby
acquisitions along with our development capital program more than offset
decreases resulting from the April 2007 equity issue and the foreign exchange
impact of the strengthening Canadian dollar on our U.S. dollar denominated
senior notes.
    In the fourth quarter of 2007 we extended our bank credit facility by one
year to November 2010 and increased the facility size to $1.0 billion.
Subsequent to December 31, 2007, in conjunction with the Focus acquisition, we
increased the bank credit facility size to $1.4 billion. On February 13, 2008
an additional $340 million was drawn on the bank credit facility to settle
outstanding indebtedness of Focus.

    Our working capital, excluding cash, at December 31, 2007 decreased
$73.2 million compared to December 31, 2006. Excluding deferred financial
assets and credits, working capital decreased $7.3 million compared to the
prior year. This is primarily due to lower accounts receivable in 2007 as a
result of lower sales in December 2007 compared to 2006.
    We continue to maintain a conservative balance sheet as demonstrated
below:

                                                   Year ended     Year ended
    Financial Leverage and Coverage             Dec. 31, 2007  Dec. 31, 2006
    -------------------------------------------------------------------------
    Long-term debt to trailing cash flow                0.8 x          0.8 x
    Cash flow to interest expense                      25.8 x         26.8 x
    Long-term debt to long-term debt plus equity          22%            20%
    -------------------------------------------------------------------------
    Long-term debt is measured net of cash.
    Cash flow and interest expense are 12-months trailing.

    Enerplus currently has a $1.4 billion ($1.0 billion at December 31, 2007)
unsecured covenant based three-year term bank facility ending November 2010,
through its wholly-owned subsidiary EnerMark Inc.  We have the ability to
extend the facility each year or repay the entire balance at the end of the
three-year term.  This bank debt carries floating interest rates that we
expect 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 Fund's operating
subsidiaries to make payments to the Fund and consequently the Fund's ability
to make distributions to the unitholders may be restricted. At December 31,
2007 we are in compliance with our debt covenants, the most restrictive of
which limits our long-term debt to three times trailing cash flow reflecting
acquisitions on a pro forma basis. Refer to "Debt of Enerplus" in our Annual
Information Form for the year ended December 31, 2006 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 2008 through a combination of cash
flow retained by the business and debt.

    Commitments

    Enerplus has contracted to transport 104 MMcf/day of natural gas on the
Nova system in the province of Alberta as well as 20 MMcf/day of natural gas
on various pipelines to the U.S. midwest. Enerplus also has a contract to
transport a minimum of 2,480 bbls/day of crude oil from field locations to
suitable marketing sales points within western Canada.
    Including Focus, approximately 24% 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.
    In 2007 we extended our Canadian office lease commitments. Our Canadian
and U.S. leases now expire in 2014 and 2011, respectively. Annual costs of
these lease commitments, include rent and operating fees. The Fund's
commitments, contingencies and guarantees are more fully described in Note 13.
    As at December 31, 2007 Enerplus has the following minimum annual
commitments including long-term debt:

                                                                       Total
                              Minimum Annual Commitment Each Year   Committed
                            ----------------------------------------   after
    ($ millions)     Total    2008    2009     2010    2011    2012     2012
    -------------------------------------------------------------------------
    Bank credit
     facility     $497.3(1)    $ -     $ -   $497.3     $ -     $ -      $ -
    Senior
     unsecured
     notes      323.4(1)(2)      -       -     53.7    64.7    64.7    140.3
    Pipeline
     commitments      31.1    10.0     5.9      4.0     2.8     2.4      6.0
    Office
     lease            67.9     6.9     7.6     10.3    10.8    11.1     21.2
    -------------------------------------------------------------------------
    Total
     commit-
     ments(3)       $919.7   $16.9   $13.5   $565.3   $78.3   $78.2   $167.5
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    (1) Interest payments have not been included since future debt levels and
        interest rates are not known at this time.
    (2) Includes the economic impact of derivative instruments directly
        related to the senior unsecured notes (CCIRS and foreign exchange
        swap - see Note 12).
    (3) 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.

    Not reflected in the above schedule are those term contracts for
transportation and the office lease that Enerplus assumed upon the completion
of the Focus acquisition. The Focus term transportation contracts consist of
45 MMcf/day of natural gas in British Columbia, and 60 MMcf/day of natural gas
in Saskatchewan.

    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, derivative instrument mark-to-market gains and
losses, unit based compensation charges, future income tax provisions and non-
cash charges resulting from the adoption of the financial instrument
accounting standards (see Note 2).

    Trust Unit Information

    We had 129,813,000 trust units outstanding at December 31, 2007 compared
to 123,151,000 trust units at December 31, 2006. The weighted average number
of trust units outstanding during 2007 was 127,691,000 (2006 - 121,588,000).
At February 20, 2008 we had 160,022,000 trust units outstanding, which
reflects the additional trust units issued to acquire Focus, and 9,087,000
exchangeable partnership units outstanding that were assumed with the Focus
acquisition and are convertible at the option of the holder into 0.425 of an
Enerplus trust unit (3,862,000 trust units).
    On April 10, 2007 in conjunction with the acquisition of Kirby we issued
1,105,000 trust units as part of the purchase price consideration representing
$54.8 million and also closed a public offering of 4,250,000 trust units for
net proceeds of $199.6 million.
    In addition 1,307,000 trust units (2006 - 1,242,000) were issued pursuant
to the Trust Unit Monthly Distribution Reinvestment and Unit Purchase Plan
("DRIP") and the trust unit rights incentive plan, net of redemptions. This
resulted in $56.8 million (2006 - $55.9 million) of additional equity to the
Fund.

    Income Taxes

    The following is a general discussion of the Canadian and U.S. tax
consequences of holding Enerplus trust units as capital property. The summary
is not exhaustive in nature and is not intended to provide legal or tax
advice. Investors or potential unitholders should consult their own legal or
tax advisors as to their particular tax consequences, as well as consider the
Government's proposal to implement a tax on trusts.

    Canadian Unitholders

    The Fund qualifies as a mutual fund trust under the Income Tax Act
(Canada) and accordingly, trust units of the Fund are qualified investments
for RRSPs, RRIFs, RESPs, and DPSPs. Each year the Fund has historically
transferred all of its taxable income to the unitholders by way of
distributions.
    In computing income, unitholders are required to include the taxable
portion of distributions received in that year. An investor's adjusted cost
base ("ACB") in a trust unit equals the purchase price of the trust unit less
any non-taxable cash distributions received from the date of acquisition. To
the extent a unitholder's ACB is reduced below zero, such amount will be
deemed to be a capital gain to the unitholder and the unitholder's ACB will be
brought to $nil.
    We paid $5.04 per trust unit in cash distributions to unitholders on
record during 2007. For Canadian tax purposes, approximately 2% of these
distributions, or $0.12 per trust unit was a tax deferred return of capital,
approximately 98% or $4.92 per trust unit was taxable to unitholders as other
income, and there was no eligible dividend income.
    For 2008, we estimate that 95% of cash distributions will be taxable and
5% will be a tax deferred return of capital. Actual taxable amounts may vary
depending on actual distributions which are dependent upon, among other
things, production, commodity prices and cash flow experienced throughout the
year.

    U.S. Unitholders

    U.S. unitholders who received cash distributions were subject to at least
a 15% Canadian withholding tax. The withholding tax is applied to both the
taxable portion of the distribution as computed under Canadian tax law and the
non-taxable portion of the distribution. U.S. taxpayers may be eligible for a
foreign tax credit with respect to Canadian withholding taxes paid.
    For U.S. taxpayers the taxable portion of cash distributions are
considered to be a dividend for U.S. tax purposes. For most U.S. taxpayers
this should be a "Qualified Dividend" eligible for the reduced tax rate. This
preferential rate of tax for "Qualified Dividends" is set to expire at the end
of 2010. On March 24, 2007, Bill 1672 was introduced into the U.S. House of
Representatives which, if enacted as presented, would make dividends from
Canadian income funds such as Enerplus ineligible for treatment as a
"Qualified Dividend". The dividends would then become a "non-qualified
dividend from a foreign corporation" subject to the normal rates of tax
commencing with dividends received after the date of enactment. The proposed
bill still requires the approval of the House of Representatives, the Senate
and the President prior to it being enacted. Therefore, we are unable to
determine when or even if the bill will become enacted as presented.
    We paid US$4.71 per trust unit to U.S. residents during the 2007 calendar
year of which 7% or US$0.33 per trust unit was a tax deferred return of
capital and 93% or US$4.38 per unit was a taxable qualified dividend.
    For 2008, we estimate that 90% of cash distributions will be taxable to
most U.S. investors and 10% will be a tax deferred return of capital. Actual
taxable amounts may vary depending on actual distributions which are dependent
upon production, commodity prices and cash flow experienced throughout the
year.

    Quarterly Financial Information

    In general, oil and gas sales have been decreasing since the first
quarter of 2006 due mainly to lower natural gas prices and lower production.
Sales increased slightly in the fourth quarter of 2007 due to higher crude oil
prices.
    Net income has been affected by fluctuating commodity prices and risk
management costs, the fluctuating Canadian dollar, higher operating and G&A
costs, changes in future tax provisions due to changes in government
legislation (SIFT tax and corporate rate reductions) as well as changes to
accounting policies adopted during 2007. Furthermore, changes in the fair
value of our commodity derivative instruments along with changes in fair value
of other financial instruments cause net income to fluctuate between quarters.

    Quarterly Financial
     Information
    (CDN$ millions,
     except per trust         Oil and              Net Income Per Trust Unit
     unit amounts)        Gas Sales(1)  Net Income        Basic      Diluted
    -------------------------------------------------------------------------
    2007
    Fourth Quarter        $     389.8  $      98.7  $      0.76  $      0.76
    Third Quarter               364.8         93.0         0.72         0.72
    Second Quarter              382.5         40.1         0.31         0.31
    First Quarter               380.0        107.9         0.88         0.87
    -----------------------------------------------
    Total                 $   1,517.1  $     339.7  $      2.66  $      2.66
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    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
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    (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 2007 with the same period in 2006:
    -   Net income decreased 10% to $98.7 million due to increased commodity
        derivative instrument losses, partially offset by higher oil and gas
        sales.
    -   Cash flow was $205.1 million in 2007 similar to $207.1 million in
        2006.
    -   Average daily production decreased 7% to 80,959 BOE/day due to the
        fire at Giltedge, operational interruptions and reductions in our
        development capital program.
    -   The average selling price per BOE increased 13% to $52.33 due to
        stronger crude oil prices.
    -   Operating expenses of $8.57/BOE (including non-cash amounts) were
        similar to the fourth quarter of 2006 at $8.52/BOE.
    -   G&A expenses including non-cash amounts increased 4% on a BOE basis
        to $2.21/BOE from $2.13/BOE as a result of lower production.
    -   Development capital spending decreased 14% compared to the fourth
        quarter of 2006 as a result of a reduced development capital spending
        program in 2007.


    The following tables provide an analysis of key financial and operating
results for the three months ended December 31, 2007 and 2006.

                                                          Three        Three
                                                         Months       Months
    (CDN$ millions,                                       Ended        Ended
     except per                                     December 31, December 31,
     unit amounts)                                         2007         2006
    -------------------------------------------------------------------------
    Financial (000's)
      Net Income                                    $      98.7  $     110.2
      Cash Flow from Operating Activities           $     205.1  $     207.1
      Cash Distributions to Unitholders(1)          $     163.4  $     155.0

    Financial per Unit(2)
      Net Income                                    $      0.76  $      0.90
      Cash Flow from Operating Activities           $      1.58  $      1.69
      Cash Distributions to Unitholders(1)          $      1.26  $      1.26

      Payout Ratio(3)                                       80%          75%

    Average Daily Production                             80,959       87,092

    Selected Financial Results per BOE(4)
    Oil and Gas Sales(5)                            $     52.33  $     46.11
    Royalties                                             (9.83)       (8.26)
    Commodity Derivative Instruments                      (0.08)        0.75
    Operating Costs                                       (8.53)       (8.52)
    General and Administrative                            (1.94)       (1.88)
    Interest and Foreign Exchange                         (1.70)       (1.02)
    Taxes                                                 (1.70)       (0.64)
    Restoration and Abandonment                           (0.75)       (0.54)
    -------------------------------------------------------------------------
    Cash Flow from Operating Activities before
     changes in non-cash working capital            $     27.80  $     26.00
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    Weighted Average Number of Units
     Outstanding (thousands)                            129,658      122,971

    Development Capital                                   106.1        123.1
    Net Wells Drilled                                        76           89
    Success Rate                                           100%         100%

    Average Benchmark Pricing
    AECO natural gas - monthly index (CDN$/Mcf)     $      6.00  $      6.36
    AECO natural gas - daily index (CDN$/Mcf)       $      6.14  $      6.91
    NYMEX natural gas - monthly NX3 index (US$/Mcf) $      7.03  $      6.62
    NYMEX natural gas - monthly NX3 index:
     CDN$ equivalent (CDN$/Mcf)                     $      6.89  $      7.52
    WTI crude oil (US$/bbl)                         $     90.68  $     60.21
    WTI crude oil: CDN$ equivalent (CDN$/bbl)       $     88.90  $     68.42
    CDN$/US$ exchange rate                                 1.02         0.88
    -------------------------------------------------------------------------
    (1) Calculated based on distributions paid or payable. Cash distributions
        to unitholders per unit may not correspond to actual distributions of
        $1.26 per trust unit as a result of using the annual weighted average
        trust units outstanding.
    (2) Based on weighted average trust units outstanding.
    (3) Based on cash distributions 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.


    Selected Quarterly Canadian and U.S. Financial Results

    (CDN$ millions,    Three months ended           Three months ended
     except per         December 31, 2007            December 31, 2006
     unit amounts)  Canada      U.S.     Total    Canada      U.S.     Total
    -------------------------------------------------------------------------
    Daily
     Production
     Volumes
      Natural gas
       (Mcf/day)   245,219    12,196   257,415   271,061     6,654   277,715
      Crude oil
       (bbls/day)   24,248     9,973    34,221    25,903    10,436    36,339
      Natural gas
       liquids
       (bbls/day)    3,836         -     3,836     4,467         -     4,467
      Total daily
       sales
       (BOE/day)    68,953    12,006    80,959    75,547    11,545    87,092

    Pricing(1)
      Natural
       gas
       (per Mcf)     $5.91     $5.98     $5.91     $6.57     $6.81     $6.58
      Crude oil
       (per bbl)    $68.94    $80.16    $72.21    $52.39    $59.85    $54.53
      Natural gas
       liquids
       (per bbl)    $58.12        $-    $58.12    $46.15        $-    $46.15

    Capital
     Expenditures
      Development
       capital
       and office    $94.3     $13.7    $108.0     $96.7     $29.1    $125.8
      Acquisitions
       of oil and
       gas
       properties     $5.0      $0.1      $5.1      $4.1      $0.7      $4.8
      Dispositions
       of oil and
       gas
       properties    $(0.4)    $(3.6)    $(4.0)    $(0.1)       $-     $(0.1)

    Revenues
      Oil and gas
       sales(1)     $309.5     $80.3    $389.8    $307.9     $61.6    $369.5
      Royalties     $(56.1) $(17.1)(2)  $(73.2)   $(54.1) $(12.1)(2)  $(66.2)
      Commodity
       derivative
       instru-
       ments       $(48.8)       $-     $(48.8)    $(5.4)       $-     $(5.4)

    Expenses
      Operating     $61.0      $2.8      $63.8     $66.4      $1.9     $68.3
      General and
       admini-
       strative     $16.5     $(0.1)     $16.4     $14.6      $2.5     $17.1
      Depletion,
       depreciation,
       amortization
       and
       accretion    $89.9     $21.8     $111.7     $93.3     $26.2    $119.5
      Current
       income taxes    $-     $12.6      $12.6        $-      $5.1      $5.1
    -------------------------------------------------------------------------
    (1) Net of oil and gas transportation costs, but before the effects of
        commodity derivative instruments.
    (2) Royalties include U.S. state production tax.

    Critical Accounting Policies

    The financial statements have been prepared in accordance with GAAP. A
summary of significant accounting policies is presented in Note 1. A
reconciliation of differences between Canadian and United States GAAP is
presented in Note 16. Most accounting policies are mandated under GAAP.
However, in accounting for oil and gas activities, we have a choice between
two acceptable accounting policies: the full cost and the successful efforts
methods of accounting.
    The Fund follows the full cost method of accounting for oil and natural
gas activities. Using the full cost method of accounting, all costs of
acquiring, exploring and developing oil and natural gas properties are
capitalized, including unsuccessful drilling costs and administrative costs
associated with acquisitions and development. Under the successful efforts
method of accounting, all exploration costs, except costs associated with
drilling successful exploration wells, are expensed in the period in which
they are incurred. The difference between these two methodologies is not
expected to be significant to the Fund's net income or net income per unit as
the majority of the Fund's drilling activity is not exploration in nature and
is more focused on low risk development drilling that has traditionally
achieved high success rates.
    Under the full cost method of accounting, an impairment test is applied
to the overall carrying value of property, plant and equipment, on a country
by country cost centre basis with the reserves valued using estimated future
commodity prices at period end. Under the successful efforts method of
accounting, the costs are aggregated on a property-by-property basis. The
carrying value of each property is subject to an impairment test. Each method
may generate a different carrying value of property, plant and equipment and a
different net income depending on the circumstances at period end. Net costs
related to operating and administrative activities during the development of
large capital projects are capitalized until commercial production has
commenced and are tested for impairment separately.

    Critical Accounting Estimates

    The preparation of financial statements in accordance with GAAP requires
management to make certain judgments and estimates. Due to the timing of when
activities occur compared to the reporting of those activities, management
must estimate and accrue operating results and capital spending. Changes in
these judgments and estimates could have a material impact on our financial
results and financial condition.

    Reserves

    The process of estimating reserves is critical to several accounting
estimates. It requires significant judgments based on available geological,
geophysical, engineering and economic data. These estimates may change
substantially as data from ongoing development and production activities
becomes available, and as economic conditions impacting oil and gas prices,
operating costs and royalty burdens change. Reserve estimates impact net
income through depletion, the determination of asset retirement obligations
and the application of an impairment test. Revisions or changes in the reserve
estimates can have either a positive or a negative impact on net income and
the asset retirement obligation.

    Asset Retirement Obligation

    Management calculates the asset retirement obligation based on estimated
costs to abandon and reclaim its net ownership interest in all wells and
facilities and the estimated timing of the costs to be incurred in future
periods. The fair value estimate is capitalized to PP&E as part of the cost of
the related asset and amortized over its useful life.

    Business Combinations

    Management makes various assumptions in determining the fair values of
any acquired company's assets and liabilities in a business combination. The
most significant assumptions and judgments made relate to the estimation of
the fair value of the oil and gas properties. To determine the fair value of
these properties, we estimated (a) oil and gas reserves in accordance with
NI 51-101 reserve standards, and (b) future prices of oil and gas.

    Commodity Prices

    Management's estimates of future crude oil and natural gas prices are
critical as these prices are used to determine the carrying amount of PP&E,
amounts recorded for depletion, impairment in the cost centre, and the change
in fair value of financial contracts.

    Trust Unit Rights

    Management calculates the fair value of rights granted under our trust
unit rights incentive plan using a binomial lattice option-pricing model. This
process involves the use of significant estimates and assumptions, which may
change over time. The values calculated under the option-pricing model may not
reflect the actual value realized by trust unit rights holders.

    Derivative Financial Instruments

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

    RECENT CANADIAN ACCOUNTING AND RELATED PRONOUNCEMENTS

    Convergence of Canadian GAAP with International Financial Reporting
    Standards

    In 2006, Canada's Accounting Standards Board (AcSB) ratified a strategic
plan that will result in Canadian GAAP, as used by public entities, being
converged with International Financial Reporting Standards ("IFRS") by 2011.
On February 13, 2008 the AcSB confirmed that use of IFRS will be required for
public companies beginning January 1, 2011. We continue to assess the impact
of adopting IFRS and implementing plans for transition.

    Financial Instruments, Comprehensive Income and Hedges

    CICA Section 3862 - Financial Instruments - Disclosures

    This standard requires entities to provide disclosures in their financial
statements that enable users to evaluate the significance of financial
instruments to the entity's financial position and performance. It also
requires that entities disclose the nature and extent of risks arising from
financial instruments and how the entity manages those risks.
    This standard is effective for reporting periods beginning January 1,
2008 and will result in additional disclosures for our financial instruments.

    CICA Section 3863 - Financial Instruments - Presentation

    This standard establishes presentation guidelines for financial
instruments and non-financial derivatives and deals with the classification of
financial instruments, from the perspective of the issuer, between liabilities
and equity, the classification of related interest, dividends, losses and
gains, and the circumstances in which financial assets and financial
liabilities are offset.
    This standard is effective for reporting periods beginning January 1,
2008 and should have a minimal impact on our reporting.

    CICA Section 1535 - Capital Disclosures

    This section details disclosures that must be made regarding an entity's
capital and how it is managed. The standard requires qualitative information
about an entity's objectives, policies and processes for managing capital and
quantitative data about what the entity regards as capital. It requires
disclosure of compliance with any capital requirements and consequences of any
non-compliance.
    This standard is effective for reporting periods beginning January 1,
2008 and will result in additional disclosures around managing capital.

    RISK FACTORS AND RISK MANAGEMENT

    Enerplus investors are participating in the net cash flow from a
portfolio of crude oil and natural gas producing properties. As such, the cash
distributions and the value of Enerplus units are subject to numerous risk
factors. These risk factors, many of which are associated with the oil and gas
industry, include, but are not limited to, the following influences:

    Canadian Government Tax on Income Trusts

    On June 22, 2007, Bill C-52 was passed by the Senate and was given royal
assent by the Governor General. As a result, our second quarter future income
tax provision includes a future income tax expense of $78.1 million related to
this legislation. This non-cash expense relates to temporary differences
between the accounting and tax basis of the Fund's assets and liabilities and
has no immediate impact on cash flow. Tax pools in 2011 may not be sufficient
to shelter taxable income from the new SIFT tax and as a result increased tax
may reduce cash flow available for distributions and development spending.
    We are currently evaluating alternatives to determine the optimal
business structure for our unitholders. However, we currently see value in the
three-year tax exemption period through 2010 as a distributing entity and
would be hesitant to make major structural changes during this period without
compelling reasons that we do not currently foresee.

    Commodity Price Risk

    Enerplus' operating results and financial condition are dependent on the
prices we receive for our crude oil and natural gas production. These prices
may fluctuate widely in response to a variety of factors including global and
domestic economic conditions, weather conditions, the supply and price of
imported oil and liquefied natural gas, the production and storage levels of
North American natural gas, political stability, transportation facilities,
the price and availability of alternative fuels and government regulations.
    We may use financial derivative instruments and other hedging mechanisms
to help limit the adverse effects of natural gas and oil price volatility.
However, we do not hedge all of our production and expect there will always be
a portion that remains unhedged. Furthermore, we may use financial instruments
that offer only limited protection within selected price ranges. To the extent
price exposure is hedged, we may forego the benefits that would otherwise be
experienced if commodity prices increase, and may be exposed to risk of
default by the counterparties. Refer to the price risk management section.

    Oil and Gas Reserves and Resources Risk

    The value of our trust units are based on, among other things, the
underlying value of the oil and gas reserves and resources. Geological and
operational risks can affect the quantity and quality of reserves and
resources and the cost of ultimately recovering those reserves and resources.
Lower oil and natural gas prices may increase the risk of write-downs of our
oil and gas property investments. Regulatory changes to reporting practices
can also result in reserve or resource write-downs.
    We strive to acquire low risk, mature properties with a high proportion
of proved reserves, positive operating metrics, long reserve lives and
predictable production. Similarly, we generally participate in lower-risk
development projects while farming out or monetizing higher risk exploratory
prospects.
    Each year, independent engineers evaluate a significant portion of our
proved and probable reserves as well as the resources attributable to our oil
sands properties. Sproule Associates Limited ("Sproule") evaluated 92% of the
total proved plus probable value (discounted at 10%) of our Canadian
conventional year-end reserves, in accordance with NI 51-101 and has reviewed
the remainder of the reserves Enerplus evaluated internally. GLJ Petroleum
Consultants Ltd. ("GLJ") evaluated the Joslyn bitumen reserves as they have
previously performed such evaluations for the operator of the Joslyn project.
Netherland, Sewell & Associates Inc. ("NSA") of Dallas, Texas, evaluated the
reserves attributed to our assets in the United States. Both GLJ and NSA
evaluated 100% of the reserves in their respective areas. Both GLJ and NSA
utilized Sproule's forecast and constant price and cost assumptions as of
December 31, 2007 in their evaluations to maintain consistency. GLJ also
evaluated the resources attributable to our Joslyn and Kirby oil sands
projects. The Reserves Committee of the Board of Directors has reviewed and
approved the reserve and resource reports of the independent evaluators.

    Operational Inflation Risk

    Over the last few years we have experienced inflationary pressures on
both our development capital costs and our operating costs. Higher costs
decrease the amount of cash flow from our operating activities which may
affect the amount of distributions to unitholders.
    We strive to control costs through incentive-based compensation plans
that reward employees for such things as cost control and value-added
initiatives. We attempt to minimize costs by exploiting our purchasing
strength with suppliers. We use detailed budgeting and accounting practices to
monitor costs. Multi-functional teams regularly perform integrated field
reviews designed to reduce costs and increase revenues from our properties.
    Despite these efforts, it can be difficult to control costs in the oil
and gas industry, especially in periods of high commodity prices when the
demand for goods and services is strong. Oil and gas production involves a
significant amount of fixed costs that are difficult to reduce without
decreasing production. In addition, subsequent to the Focus acquisition,
approximately 30% of our production is operated by third parties. We have
limited ability to influence costs on partner-operated properties.

    Access to Transportation Capacity

    Market access for crude oil and natural gas production in Canada and the
United States is dependent on the ability of Enerplus and the buyers of our
production to access sufficient transportation capacity on third party
pipelines to transport all production volumes. While the third party pipelines
generally expand capacity to meet market needs, there can be differences in
timing between the growth of production and the growth of pipeline capacity.
There are also occasionally operational reasons for curtailing transportation
capacity. Accordingly, there can be periods where pipeline capacity is
insufficient to transport all of the production from a given region, causing
volume curtailments for all shippers, including Enerplus and its production
buyers.
    We continuously monitor this risk for both the short and longer term
through dialogue with the third party pipelines and other market participants,
as well as by review of supply and demand studies prepared by third party
experts. Where available and commercially appropriate given the production
profile and commodity, we attempt to mitigate this risk by contracting for
firm transportation capacity or by using other means of transportation.

    Production Replacement Risk

    Oil and natural gas reserves naturally deplete as they are produced over
time. Our ability to replace production depends on our success in acquiring
new reserves and resources and developing existing reserves and resources.
Acquisitions of oil and gas assets depend on our assessment of value at the
time of acquisition. Incorrect assessments of value can adversely affect
distributions to unitholders and the value of our trust units.
    Acquisitions and our development capital program are subject to
investment guidelines, due diligence and review. Major acquisitions are
approved by the Board of Directors and, where appropriate, independent reserve
engineer evaluations are obtained.

    Non-Resident Ownership and Mutual Fund Trust Status

    Since our listing on the New York Stock Exchange in November of 2000, we
have seen increased trading volumes and levels of ownership by non-residents
of Canada. Based on information received from our transfer agent and financial
intermediaries in February 2008, an estimated 72% of our outstanding trust
units were held by non-residents. Immediately after the acquisition of Focus,
on February 13, 2008, we estimate that approximately 63% of our trust units
were held by non-residents. However, this estimate may not be accurate as it
is based on certain assumptions and data from the securities industry that
does not have a well-defined methodology to determine the residency of
beneficial holders of securities.
    Enerplus currently meets the requirements of a Mutual Fund Trust as
defined in the Income Tax Act (Canada). Our trust indenture does not have a
specific limit on the percentage of trust units that may be owned by non-
residents.
    At this time, management does not anticipate any legislative changes that
would affect our status as a mutual fund trust; however, we have implemented
provisions in our trust indenture to allow the Board of Directors to adopt
non- resident ownership constraints, if required, in order to ensure Enerplus
maintains its mutual fund trust status.

    Regulatory Risk

    Government royalties, income tax laws, environmental laws and regulatory
requirements can have a significant financial and operational impact on
Enerplus. During 2007 the Alberta government announced proposed changes to the
provincial royalty program, expected to be effective on January 1, 2009 (see
the Royalties section of the MD&A for further details). Canada ratified the
Kyoto Protocol in late 2002, which requires countries to reduce their
emissions of carbon dioxide and other greenhouse gases. The Canadian federal
government is currently gathering information to set emission targets for the
industry. The details are projected to be announced by 2010 and could affect
capital expenditures and operating costs.
    Our operations expose us to possible regulatory changes by both Canadian
and U.S. governments. As an oil and gas producer, we are subject to a broad
range of regulatory requirements. Similarly, as a mutual fund trust, we have a
unique structure that is vulnerable to changes in legislation or income tax
law.
    Although we have no control over these regulatory risks, we continuously
monitor changes in these areas through such activities as participating in
industry organizations and conferences, the exchange of information with third
party experts and employing qualified individuals to assess the impact of such
changes on our financial and operating results.

    Access to Capital Markets

    Our access to capital has allowed us to fund a portion of our
acquisitions and development capital program through equity and debt and as a
result distribute the majority of our cash flow to our unitholders. As such,
we are dependent on continued access to the capital markets to fund our
activities directed towards maintaining and increasing value for our
unitholders. To the extent the cash flow retained by the Fund together with
new equity and debt financing is not sufficient to cover required capital
expenditures then cash distributions to unitholders may be reduced.
Furthermore, current tightening global credit markets may have an adverse
effect on our ability to access these capital markets.
    Enerplus has listings on the Toronto and New York stock exchanges and
maintains an active investor relations program.
    We maintain a prudent capital structure by retaining a portion of cash
flow for capital spending and utilizing the equity markets when deemed
appropriate.
    Continued access to capital is dependent on our ability to maintain our
track record of performance and to demonstrate the advantages of the
acquisition or development program that we are financing at the time.

    Health, Safety and Environmental Risk ("HSE")

    Health, safety and environmental risks influence the workforce, operating
costs and the establishment of regulatory standards.

    We have established a HSE Management System designed to:

    -   provide staff with the training and resources needed to complete work
        safely and effectively;
    -   incorporate hazard assessment and risk management as an integral part
        of everyday business;
    -   monitor performance to ensure that our operations comply with legal
        obligations and the standards we set for ourselves; and
    -   identify and manage environmental liabilities associated with our
        existing asset base and potential acquisitions.

    We have a site inspections program and a corrosion risk management
program designed to ensure compliance with environmental laws and regulations.
We carry insurance to cover a portion of our property losses, liability and
business interruption. HSE risks are reviewed regularly by the HSE committee
comprised of members of the Board of Directors.

    Interest Rate Exposure

    The Fund has exposure to movements in interest rates. Changing interest
rates can affect borrowing costs and the trust unit price of yield-based
investments such as Enerplus.
    We monitor the interest rate forward market and have fixed the interest
rate on approximately 18% of our debt through our senior unsecured notes and
interest rate swaps.

    Foreign Currency Exposure

    We have exposure to fluctuations in foreign currency as a result of the
issuance of senior unsecured notes denominated in U.S. dollars. Our U.S.
operations are directly exposed to fluctuations in the U.S. dollar when
translated to our Canadian dollar denominated financial statements.
    We also have indirect exposure to fluctuations in foreign currency as our
crude oil sales and a portion of our natural gas sales are based on U.S.
dollar indices. Our oil and gas revenues are negatively impacted as the
Canadian dollar strengthens relative to the U.S. dollar.
    We have hedged our foreign currency exposure on both our US$175 million
and US$54 million of senior unsecured notes using financial swaps that convert
the U.S. denominated debt to Canadian dollar debt.  In addition we have hedged
our interest obligation on our US$175 million notes.
    We have not entered into any other foreign currency derivatives with
respect to oil and gas sales or our U.S. operations.

    Counterparty Risk

    We assume customer credit risk associated with oil and gas sales,
financial hedging transactions and joint  venture participants.
    We have established credit policies and controls designed to mitigate the
risk of default or non-payment with respect to oil and gas sales, financial
hedging transactions and joint venture participants. We maintain a diversified
sales customer base and we review our single-entity exposure on a regular
basis.  We do not have exposure to asset backed commercial paper, however we
do have exposure to Canadian and U.S. banks as a counterparty to financial
hedging transactions.

    Unitholder Liability

    In the past, there has been some concern that trust unitholders might be
held personally liable for the indebtedness of the Fund.
    Enerplus is registered in Alberta, which passed legislation in June 2005
to provide statutory protection for unitholders similar to the protection
afforded shareholders in a corporation. Three other provinces (Ontario,
Quebec, and Manitoba) also have statutory protection for unitholders. Our bank
credit agreement and our debenture agreements do not allow the creditors to
extend recourse to unitholders beyond the unitholders' equity investment in
the Fund.

    Recruitment and Retention of Qualified Personnel

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

    Summary 2008 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 2008 outlook should be taken within the context of the
current commodity price environment.
    The following summarizes Enerplus' 2008 guidance as provided throughout
this MD&A and includes the acquisition of Focus at the closing date of
February 13, 2008. 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 2008 Expectations    Target           Comments
    -------------------------------------------------------------------------
    Average annual production       98,000 BOE/day   Does not include any
                                                     further potential
                                                     acquisitions/divestments

    Exit rate December 2008         100,000 BOE/day  Assumes $580 million
     production                                      development capital
                                                     spending

    2008 production mix             60% gas,
                                    40% liquids

    Average royalty rate            19%              Percentage of gross
                                                     unhedged sales

    Operating costs                 $8.65/BOE

    G&A costs                       $2.20/BOE        Includes non-cash
                                                     charges of $0.20/BOE
                                                     (unit rights incentive
                                                     plan)

    U.S. income and                                  Applied to net cash flow
     withholding tax - cash costs   20%                 generated by U.S.
                                                     operations and assumes
                                                     repatriation of the
                                                     funds to Canada after
                                                     U.S. development capital
                                                     spending

    Average interest cost           4.5%             Based on current fixed
                                                     rates and forward market

    Payout ratio                    60% - 90%

    Development capital spending    $580 million
    -------------------------------------------------------------------------

    We expect our 2008 development capital spending to be $580 million, which
is 50% higher than our 2007 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 2008, 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.

    DISCLOSURE CONTROLS AND PROCEDURES AND INTERNAL CONTROL OVER FINANCIAL
    REPORTING

    Under the supervision of our Chief Executive Officer and Chief Financial
Officer we have evaluated the effectiveness of our disclosure controls and
procedures as of the end of the period covered by this report and concluded
that our disclosure controls and procedures are effective. There were no
changes in our internal control over financial reporting during the quarter
ended December 31, 2007 that have materially affected, or are reasonably
likely to materially affect, our internal control over financial reporting.

    ADDITIONAL INFORMATION

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

    CONSOLIDATED BALANCE SHEETS

    As at December 31 (CDN$ thousands)                     2007         2006
    -------------------------------------------------------------------------
    Assets
    Current assets
      Cash                                          $     1,702  $       124
      Accounts receivable                               145,602      175,454
      Deferred financial assets (Notes 2 and 3)          10,157       23,612
      Future income taxes (Note 11)                      10,807            -
      Other current                                       6,373        6,715
    -------------------------------------------------------------------------
                                                        174,641      205,905
    Property, plant and equipment (Note 4)            3,872,818    3,726,097
    Goodwill (Note 1(f))                                195,112      221,578
    Other assets (Note 12)                               60,559       50,224
    -------------------------------------------------------------------------

                                                    $ 4,303,130  $ 4,203,804
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    Liabilities
    Current liabilities
      Accounts payable                              $   269,375  $   284,286
      Distributions payable to unitholders               54,522       51,723
      Deferred financial credits (Notes 2 and 3)         52,488            -
    -------------------------------------------------------------------------
                                                        376,385      336,009
    -------------------------------------------------------------------------
    Long-term debt (Note 7)                             726,677      679,774
    Deferred financial credits (Notes 2 and 3)           90,090            -
    Future income taxes (Note 11)                       304,259      331,340
    Asset retirement obligations (Note 5)               165,719      123,619
    -------------------------------------------------------------------------
                                                      1,286,745    1,134,733
    -------------------------------------------------------------------------
    Equity
    Unitholders' capital (Note 10)
      Trust Units
      Authorized:                Unlimited
      Issued and Outstanding:    2007 - 129,813,445
                                 2006 - 123,150,820   4,032,680    3,713,126

    Accumulated deficit                              (1,283,953)    (971,085)
    Accumulated other comprehensive income
     (Notes 1(j) and 2)                                (108,727)      (8,979)
    -------------------------------------------------------------------------
                                                     (1,392,680)    (980,064)
                                                      2,640,000    2,733,062
    -------------------------------------------------------------------------

                                                    $ 4,303,130  $ 4,203,804
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------



    CONSOLIDATED STATEMENTS OF ACCUMULATED DEFICIT

    For the year ended December 31 (CDN$ thousands)        2007         2006
    -------------------------------------------------------------------------

    Accumulated income, beginning of year           $ 1,952,960  $ 1,408,178
    Adjustment for adoption of financial
     instruments standards (Note 2)                      (5,724)           -
    -------------------------------------------------------------------------
    Revised Accumulated income, beginning of year     1,947,236    1,408,178
    Net income                                          339,691      544,782
    -------------------------------------------------------------------------
    Accumulated income, end of year                 $ 2,286,927  $ 1,952,960

    Accumulated cash distributions,
     beginning of year                              $(2,924,045) $(2,309,705)
    Cash distributions                                 (646,835)    (614,340)
    -------------------------------------------------------------------------
    Accumulated cash distributions, end of year     $(3,570,880) $(2,924,045)

    -------------------------------------------------------------------------
    Accumulated deficit, end of year                $(1,283,953) $  (971,085)
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------



    CONSOLIDATED STATEMENTS OF ACCUMULATED OTHER COMPREHENSIVE INCOME

    For the year ended December 31 (CDN$ thousands)        2007         2006
    -------------------------------------------------------------------------

    Balance, beginning of year                      $    (8,979) $   (15,568)
      Transition adjustments (Note 2):
        Cash flow hedges                                    660            -
        Available for sale marketable securities         14,252            -
    Other comprehensive (loss)/income                  (114,660)       6,589
    -------------------------------------------------------------------------
    Balance, end of year                            $  (108,727) $    (8,979)
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------



    CONSOLIDATED STATEMENTS OF INCOME

    For the year ended December 31
    (CDN$ thousands except per trust unit amounts)         2007         2006
    -------------------------------------------------------------------------
    Revenues
      Oil and gas sales                             $ 1,539,153  $ 1,595,324
      Royalties                                        (285,148)    (296,554)
      Commodity derivative instruments (Notes 3
       and 12)                                          (52,841)      (3,226)
      Other income (Note 12)                             14,991        2,465
    -------------------------------------------------------------------------
                                                      1,216,155    1,298,009
    -------------------------------------------------------------------------
    Expenses
      Operating                                         274,150      251,239
      General and administrative (Note 10(b))            67,921       59,937
      Transportation                                     22,098       22,611
      Interest (Note 8)                                  33,627       32,168
      Foreign exchange (Note 9)                          (7,071)        (528)
      Depletion, depreciation, amortization
       and accretion                                    463,718      481,598
    -------------------------------------------------------------------------
                                                        854,443      847,025
    -------------------------------------------------------------------------
    Income before taxes                                 361,712      450,984
    Current taxes                                        23,011       18,236
    Future income tax recovery (Note 11)                   (990)    (112,034)
    -------------------------------------------------------------------------
    Net Income                                      $   339,691  $   544,782
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    Net income per trust unit
      Basic                                         $      2.66  $      4.48
      Diluted                                       $      2.66  $      4.47
    -------------------------------------------------------------------------
    Weighted average number of trust units
     outstanding (thousands)
      Basic                                             127,691      121,588
      Diluted                                           127,752      121,858
    -------------------------------------------------------------------------



    CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

    For the year ended December 31 (CDN$ thousands)        2007         2006
    -------------------------------------------------------------------------

    Net income                                      $   339,691  $   544,782
    -------------------------------------------------------------------------

    Other comprehensive (loss)/income, net of tax:
      Unrealized gain on marketable securities              629            -
      Realized gains on marketable securities
       included in net income                           (11,302)           -
      Gains and losses on derivatives designated as
       hedges in prior periods included in net income      (733)           -
    Change in cumulative translation adjustment        (103,254)       6,589
    -------------------------------------------------------------------------
    Other comprehensive (loss)/income                  (114,660)       6,589

    -------------------------------------------------------------------------
    Comprehensive income (Note 2)                   $   225,031  $   551,371
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------



    CONSOLIDATED STATEMENTS OF CASH FLOWS

    For the year ended December 31 (CDN$ thousands)        2007         2006
    -------------------------------------------------------------------------
    Operating Activities
    Net income                                      $   339,691  $   544,782
    Non-cash items add/(deduct):
      Depletion, depreciation, amortization and
       accretion                                        463,718      481,598
      Change in fair value of derivative
       instruments (Note 3)                              91,852      (31,106)
      Unit based compensation (Note 10(b))                8,435        6,323
      Foreign exchange on translation of senior
       notes (Note 9)                                   (41,182)         (32)
      Future income tax (Note 11)                          (990)    (112,034)
      Amortization of senior notes premium                 (631)           -
      Reclassification adjustments from AOCI to
       net income                                          (733)           -
      Other                                                (132)           -
    Gain on sale of marketable securities (Note 12)     (14,055)           -
    Asset retirement obligations settled (Note 5)       (16,280)     (11,514)
    -------------------------------------------------------------------------
                                                        829,693      878,017
    Decrease/(Increase) in non-cash operating
     working capital                                     38,855      (14,321)
    -------------------------------------------------------------------------
    Cash flow from operating activities                 868,548      863,696
    -------------------------------------------------------------------------

    Financing Activities
    Issue of trust units, net of issue costs (Note 10)  256,369      296,189
    Cash distributions to unitholders                  (646,835)    (614,340)
    Increase in bank credit facilities (Note 7)         148,827       19,888
    Decrease in non-cash financing working capital        2,799        2,356
    -------------------------------------------------------------------------
    Cash flow from financing activities                (238,840)    (295,907)
    -------------------------------------------------------------------------

    Investing Activities
    Capital expenditures                               (393,655)    (496,201)
    Property acquisitions (Note 6)                     (226,480)     (51,313)
    Property dispositions                                 2,947        1,599
    Proceeds on sale of marketable securities            16,467            -
    Purchase of investments                              (2,927)     (29,172)
    Increase in non-cash investing working capital      (21,046)      (3,535)
    -------------------------------------------------------------------------
    Cash flow from investing activities                (624,694)    (578,622)
    -------------------------------------------------------------------------

    Effect of exchange rate changes on cash              (3,436)         864
    -------------------------------------------------------------------------
    Change in cash                                        1,578       (9,969)
    Cash, beginning of year                                 124       10,093
    -------------------------------------------------------------------------
    Cash, end of year                               $     1,702  $       124
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    Supplementary Cash Flow Information
    Cash income taxes paid                          $    17,431  $    14,060
    Cash interest paid                              $    42,861  $    34,924



    NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

    1.  SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

    The management of Enerplus Resources Fund ("Enerplus" or the "Fund")
    prepares the consolidated financial statements in accordance with
    Canadian generally accepted accounting principles ("GAAP"). 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. Actual results could differ from
    those estimated. In particular, the amounts recorded for depletion and
    depreciation of the petroleum and natural gas properties and for asset
    retirement obligations are based on estimates of reserves and future
    costs. By their nature, these estimates, and those related to future cash
    flows used to assess impairment, are subject to measurement uncertainty
    and the impact on the financial statements of future periods could be
    material.

    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. Net costs related to
    projects in the pre-commercial phase of development are excluded from the
    country by country impairment test and are tested for impairment
    separately.

    (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.

    Changes in goodwill during 2007 represent the effects of foreign exchange
    recorded in our U.S. subsidiary.

    (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.

    Effective January 1, 2011, the Fund will be subject to a 28.0% SIFT
    (specified investment flow-through entities) tax on Canadian income that
    has not been subject to a Canadian corporate income tax in the Canadian
    operating entities. Therefore, the future tax liability associated with
    Canadian assets recorded on the balance sheet as at that date will be
    realized over time as the temporary differences between the carrying
    value of assets in the consolidated financial statements and their
    respective tax bases are realized. Current Canadian income taxes will be
    accrued for at that time to the extent that there is taxable income in
    the Trust or its underlying operating entities.

    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 the temporary differences
    between the carrying value of the assets and liabilities on the
    consolidated financial statements 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

    Commencing on January 1, 2007 financial assets and financial liabilities
    classified as held-for-trading are measured at fair value with changes in
    fair value recognized in net income. Financial assets classified as loans
    and receivables along with financial liabilities classified as other
    liabilities are measured at amortized cost using the effective interest
    rate method. Financial assets classified as available-for-sale are
    measured at fair value with changes in fair value recognized in other
    comprehensive income ("OCI"). Investments in equity instruments
    classified as available-for-sale that do not have a quoted price in an
    active market or a readily determinable fair value are measured at cost.
    Transaction costs or fees attributable to the acquisition, issue, or
    disposal of a financial asset or liability are expensed immediately to
    net income.

    Derivative instruments are recorded on the consolidated balance sheets at
    fair value, including those derivatives that are embedded in financial or
    non-financial contracts that are not closely related to the host
    contracts. Changes in the fair values of derivative instruments are
    recognized in net income.

    (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 ("CTA") which is part of accumulated other comprehensive
    income ("AOCI").

    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.  CHANGES IN ACCOUNTING POLICIES

    Financial Instruments

    Effective January 1, 2007, the Fund adopted five new accounting standards
    that were issued by the CICA: Handbook Section 1530, Comprehensive
    Income, Handbook Section 3251, Equity, Handbook Section 3855, Financial
    Instruments - Recognition and Measurement, Handbook Section 3861,
    Financial Instruments - Disclosure and Presentation and Handbook Section
    3865, Hedges. These standards were adopted retrospectively without
    restatement, with the exception of CTA amounts which have been
    reclassified to AOCI.

           Comprehensive Income

           CICA Handbook Section 1530 introduces comprehensive income, which
           consists of net income and other comprehensive income ("OCI").
           Comprehensive income represents changes in equity during a period
           arising from transactions and other events and circumstances with
           non-owner sources. OCI comprises revenues, expenses, gains and
           losses that are recognized in comprehensive income but excluded
           from net income. Examples of these gains and losses are unrealized
           gains and losses on marketable securities classified as available-
           for-sale along with unrealized foreign currency translation gains
           or losses arising from self-sustaining foreign operations. The
           Consolidated Statements of Comprehensive Income include a
           calculation of comprehensive income, while the cumulative changes
           in OCI are included in the Statements of Accumulated Other
           Comprehensive Income (AOCI). CICA Handbook Section 3251
           establishes standards for the presentation of equity and changes
           in equity during the period.

           Financial Instruments - Recognition and Measurement

           CICA Handbook Section 3855 establishes the criteria for
           recognizing and measuring financial assets, financial liabilities
           and non-financial derivatives. Under this standard, all financial
           instruments are required to be measured at fair value on
           recognition except for certain related party transactions.
           Measurement in subsequent periods depends on whether the financial
           instrument has been classified as held-for-trading, available-for-
           sale, held-to-maturity, loans and receivables, or other financial
           liabilities.

           Financial assets and financial liabilities classified as held-for-
           trading are measured at fair value with changes in fair value
           recognized in net income. Financial assets classified as loans and
           receivables along with financial liabilities classified as other
           liabilities are measured at amortized cost using the effective
           interest rate method. Financial assets classified as available-
           for-sale are measured at fair value with changes in fair value
           recognized in OCI. Investments in equity instruments classified as
           available-for-sale that do not have a quoted price in an active
           market are measured at cost. Transaction costs or fees
           attributable to the acquisition, issue, or disposal of a financial
           asset or liability are expensed immediately to net income.

           Derivative instruments are recorded on the consolidated balance
           sheets at fair value, including those derivatives that are
           embedded in financial or non-financial contracts that are not
           closely related to the host contracts. Embedded derivatives are
           included as of January 1, 2003. Changes in the fair values of
           derivative instruments are recognized in net income with the
           exception of derivatives that are designated as effective cash
           flow hedges. Refer to the Hedges section for further detail.

           CICA Handbook Section 3861 establishes standards for the
           presentation and disclosure of financial instruments and non-
           financial derivatives.

           Hedges

           CICA Handbook Section 3865 specifies the criteria and method of
           accounting for each of the designated hedging strategies.

           When hedge accounting is discontinued for a cash flow hedge, the
           amounts previously recognized in AOCI are reclassified to net
           income over the remaining term of the hedged item.

           When hedge accounting is discontinued for a fair value hedge, the
           carrying value of the hedged item is no longer adjusted. Any
           difference between the carrying value and the face value or
           principal amount of the hedged item is amortized to net income
           over the remaining term of the original hedging relationship using
           the effective interest method.

    Impact upon Adoption of Sections 1530, 3251, 3855, 3861 and 3865

    As a result of the adoption of these standards on January 1, 2007 the
    Fund elected to stop designating its interest rate and electricity swaps
    as cash flow hedges and recorded these items on the consolidated balance
    sheet at their fair values with the offset recorded to opening
    accumulated other comprehensive income. In addition, the Fund elected to
    stop designating its cross currency and interest rate swap ("CCIRS") as a
    fair value hedge and recorded the CCIRS on the consolidated balance sheet
    at fair value with the offset recorded to opening accumulated deficit. In
    conjunction, the underlying US$175,000,000 senior unsecured notes were
    recorded at fair value with the offset recorded to opening accumulated
    deficit.

    The Fund's investments in marketable securities have been classified as
    available-for-sale and therefore those that have a quoted price in an
    active market were recorded on the consolidated balance sheet at fair
    value with the offset recorded to opening AOCI.

    Deferred charges of $1,523,000 associated with issuance of the senior
    unsecured notes were recorded to the opening accumulated deficit.

    Amounts previously recorded in the cumulative translation adjustment were
    reclassified into opening AOCI. Our prior year comparative statements
    have been restated to reflect this change.

    The Fund has recorded the following transition adjustments as of
    January 1, 2007 in the Consolidated Financial Statements: (a) an increase
    of $1,494,000 to deferred financial assets to record the electricity
    swaps at fair value; (b) an increase to other current assets of
    $14,493,000 to record publicly traded marketable securities at fair
    value; (c) an increase of $1,708,000 to other assets, consisting of
    $3,231,000 to record publicly traded marketable securities at fair value
    less $1,523,000 to write-off the deferred charges associated with the
    issuance of the senior unsecured notes; (d) an increase of $65,675,000 to
    deferred financial credits to record the CCIRS and interest rates swaps
    at fair value; (e) a decrease to long-term debt of $60,111,000 to record
    the US$175,000,000 senior unsecured note at fair value; (f) an increase
    to future income taxes of $ 2,943,000 to reflect the tax impact of the
    adoption entries; (g) an increase of $5,724,000, net of taxes, to the
    opening accumulated deficit; (h) recognition in AOCI of $14,912,000, net
    of taxes, related to the net gains on marketable securities classified as
    available-for-sale along with the fair value of the interest rate and
    power swaps formerly designated as cash flow hedges. In addition, the
    Fund reclassified to AOCI $8,979,000 of net unrealized foreign currency
    losses that were previously presented as a separate item in equity. These
    transition adjustments are summarized below.

    Impact of transition adjustment on selected consolidated balance sheets
    line items:

                                                       Transition adjustment
    Increase/decrease (CDN$ thousands)                 as at January 1, 2007
    -------------------------------------------------------------------------
    Deferred financial assets                                    $     1,494
    Other current assets                                              14,493
    Other assets                                                       1,708
    Deferred financial credits                                        65,675
    Long-term debt                                                   (60,111)
    Future income taxes                                                2,943
    Accumulated deficit                                               (5,724)
    Cumulative translation adjustment                                  8,979
    Accumulated other comprehensive income                             5,933
    -------------------------------------------------------------------------

    As a result of these changes, net income increased by $5,619,000
    ($7,943,000 before future income taxes of $2,324,000) for the year ended
    December 31, 2007. Both the basic and diluted net income per trust unit
    calculations for the year ended December 31, 2007 increased by $0.04.

    Recent Canadian Accounting Pronouncements

    CICA Section 3862 - Financial Instruments - Disclosures

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

    This standard is effective for reporting periods beginning after
    January 1, 2008 and will result in additional disclosures for our
    financial instruments.

    CICA Section 3863 - Financial Instruments - Presentation

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

    This standard is effective for reporting periods beginning after
    January 1, 2008 and should have a minimal impact on our reporting.

    CICA Section 1535 - Capital Disclosures

    This section details disclosures that must be made regarding an entity's
    capital and how it is managed. The standard requires qualitative
    information about an entity's objectives, policies and processes for
    managing capital and quantitative data about what the entity regards as
    capital. It requires disclosure of compliance with any capital
    requirements and consequences of any non-compliance.

    This standard is effective for reporting periods beginning after
    January 1, 2008 and will result in additional disclosures around managing
    capital.

    3.  DEFERRED FINANCIAL ASSETS AND DEFERRED FINANCIAL CREDITS

    The deferred financial assets and credits result from recording our
    derivative financial instruments at fair value. At December 31, 2007 a
    current deferred financial asset of $10,157,000, a current deferred
    financial credit of $52,488,000 and a long-term deferred financial credit
    of $90,090,000 are recorded on the consolidated balance sheet.

    The deferred financial credit relating to crude oil instruments of
    $52,488,000 at December 31, 2007 consists of the fair value of the
    financial instruments, representing a loss position of $44,749,000, plus
    the related deferred premiums of $7,739,000. The deferred financial asset
    relating to natural gas instruments of $9,707,000 at December 31, 2007
    consists of the fair value of the financial instruments of $10,628,000
    less the related deferred premiums of $921,000.



                                             Cross
                                          Currency      Foreign
                             Interest     Interest     Exchange  Electricity
    ($ thousands)          Rate Swaps   Rate Swaps        Swaps        Swaps
    -------------------------------------------------------------------------
    Deferred financial
     assets/(credits) as
     at December 31,
     2006                 $         -  $         -  $         -  $         -
    Adoption of financial
     instruments standards
     (Note 2)                    (673)     (65,002)           -        1,494
    Change in fair value
     asset/(credits)
     (Note 12)                  447(1)  (24,437)(2)     (425)(3)   (1,044)(4)
    -------------------------------------------------------------------------
    Deferred financial
     assets/(credits) as
     at December 31,
     2007                 $      (226) $   (89,439) $      (425) $       450
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    Balance sheet
     classification:
    Current asset/
     (credit)             $         -  $         -  $         -  $       450
    Long-term asset/
     (credit)             $      (226) $   (89,439) $      (425) $         -
    -------------------------------------------------------------------------

                                     Commodity
                                     Derivative
                                    Instruments

    ($ thousands)                 Oil          Gas        Total
    -------------------------------------------------------------
    Deferred financial
     assets/(credits) as
     at December 31,
     2006                 $    10,922  $    12,690  $    23,612
    Adoption of financial
     instruments standards
     (Note 2)                       -            -      (64,181)
    Change in fair value
     asset/(credits)
     (Note 12)             (63,410)(5)   (2,983)(5)     (91,852)
    -------------------------------------------------------------
    Deferred financial
     assets/(credits) as
     at December 31,
     2007                 $   (52,488) $     9,707  $  (132,421)
    -------------------------------------------------------------
    -------------------------------------------------------------

    Balance sheet
     classification:
    Current asset/
     (credit)             $   (52,488) $     9,707  $   (42,331)
    Long-term asset/
     (credit)             $         -  $         -  $   (90,090)
    -------------------------------------------------------------
    (1) Recorded in interest expense.
    (2) Recorded in foreign exchange expense (loss of $31,777) and interest
        expense (gain of $7,340).
    (3) Recorded in foreign exchange expense.
    (4) Recorded in operating expense.
    (5) Recorded in commodity derivative instruments (see below).

    The following table summarizes the income statement effects of commodity
    derivative instruments:

    ($ thousands)                                          2007         2006
    -------------------------------------------------------------------------
    Change in fair value loss/(gain)                $    66,393  $   (80,980)
    Amortization of deferred financial assets                 -       49,874
    Realized cash (gains)/losses, net                   (13,552)      34,332
    -------------------------------------------------------------------------
    Commodity derivative instruments loss           $    52,841  $     3,226
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    4.  PROPERTY, PLANT AND EQUIPMENT

    ($ thousands)                                          2007         2006
    -------------------------------------------------------------------------
    Property, plant and equipment                   $ 6,429,241  $ 5,855,511
    Accumulated depletion, depreciation and
     accretion                                       (2,556,423)  (2,129,414)
    -------------------------------------------------------------------------
    Net property, plant and equipment               $ 3,872,818  $ 3,726,097
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    Capitalized development general and administrative ("G&A") expenses of
    $17,185,000 (2006 - $14,111,000) are included in PP&E. The depletion and
    depreciation calculation includes future capital costs of $521,650,000
    (2006 - $472,567,000) as indicated in our reserve reports. Excluded from
    PP&E for the depletion and depreciation calculation is $321,801,000 (2006
    - $81,183,000) related to the Joslyn development project and the Kirby
    Oil Sands project, both of which have not yet commenced commercial
    production.

    An impairment test calculation was performed on a country by country
    basis on the PP&E values at December 31, 2007 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, 2007:

                                                                 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
    -------------------------------------------------------------------------
    2008                  $     89.61  $      1.00  $     88.17  $      6.51
    2009                        86.01         1.00        84.54         7.22
    2010                        84.65         1.00        83.16         7.69
    2011                        82.77         1.00        81.26         7.70
    2012                        82.26         1.00        80.73         7.61
    Thereafter                     (*)        1.00           (*)          (*)
    -------------------------------------------------------------------------
    (1) Actual prices used in the impairment test were adjusted for commodity
        price differentials specific to the Fund.
    (*) Escalation varies after 2012.

    5.  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 $165,719,000 at December 31, 2007 compared to
    $123,619,000 at December 31, 2006 based on a total undiscounted liability
    of $542,781,000 and $436,663,000 respectively. These payments are
    expected to be made over the next 66 years with the majority of costs
    incurred between 2038 and 2047. To calculate the present value of the
    asset retirement obligations for 2007 the Fund used a weighted credit-
    adjusted rate of approximately 6.1% and an inflation rate of 2.0%, (2006
    - 6.3% and 2.0%). 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)                                          2007         2006
    -------------------------------------------------------------------------
    Asset retirement obligations, beginning of year $   123,619  $   110,606
    Changes in estimates                                 46,000       12,757
    Acquisition and development activity                  6,441        5,574
    Dispositions                                           (756)         (45)
    Asset retirement obligations settled                (16,280)     (11,514)
    Accretion expense                                     6,695        6,241
    -------------------------------------------------------------------------
    Asset retirement obligations, end of year       $   165,719  $   123,619
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    6.  PROPERTY ACQUISITIONS

    Kirby Oil Sands Partnership

    On April 10, 2007 the Fund acquired a 90% interest in Kirby for total
    consideration of $182,800,000, consisting of $128,050,000 in cash and the
    issuance of 1,104,945 trust units at a price of $49.55 per unit
    ($54,750,000 of equity). On June 22, 2007, the Fund acquired the
    remaining 10% interest in Kirby for cash consideration of $20,276,000.
    The acquisition of Kirby has been accounted for as an asset acquisition
    pursuant to the guidance in the Emerging Issues Committee Abstract 124.

    7.  LONG-TERM DEBT

    ($ thousands)                                          2007         2006
    -------------------------------------------------------------------------
    Bank credit facilities(a)                       $   497,347  $   348,520
    Senior notes(b)
      US$175 million (issued June 19, 2002)             175,973      268,328
      US$54 million (issued October 1, 2003)             53,357       62,926
    -------------------------------------------------------------------------
    Total long-term debt                            $   726,677  $   679,774
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    (a) Unsecured Bank Credit Facility

    Enerplus currently has a $1.4 billion unsecured covenant based three year
    term facility ($1.0 billion at December 31, 2007). The facility is
    extendible each year with a bullet payment required at the end of the
    three year term. In the first quarter of 2008 the bank credit facility
    size was increased in conjunction with the acquisition of Focus Energy
    Trust ("Focus") (see Note 15). At December 31, 2007 Enerplus had
    available credit of $502,653,000 based on a facility size of $1.0 billion
    at that time. In conjunction with the Focus acquisition, Enerplus
    acquired approximately $340 million in Focus debt. 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,
    2007 was 5.1% (2006 - 4.8%).

    (b) Senior Unsecured Notes

    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. Concurrent with the
    issuance of the notes on June 19, 2002, the Fund entered into a CCIRS
    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%.

    On October 1, 2003 when the CDN/US exchange rate was 1.35 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. The notes are translated into Canadian dollars using the
    period end foreign exchange rate.

    During September 2007 Enerplus entered into foreign exchange swaps that
    effectively fix the five principal payments on the US$54,000,000 senior
    unsecured notes at a CAD/US exchange rate of 1.02.

    On January 1, 2007 in conjunction with the adoption of CICA Sections 3855
    and 3865, the Fund elected to stop designating the CCIRS as a fair value
    hedge on the US$175,000,000 senior notes. As a result, the Fund recorded
    the senior notes at their fair value of US$178,681,000 (CDN $208,217,000)
    with the offset to opening accumulated deficit. In addition, the Fund
    recorded a liability of $65,002,000 with the offset to opening
    accumulated deficit, which represented the fair value of the CCIRS. The
    premium amount of US$3,681,000, representing the difference between the
    January 1, 2007 fair value and the face amount of the senior notes, will
    be amortized to net income over the remaining term of the notes using the
    effective interest method. The effective interest rate over the remaining
    term of the senior notes is 6.16%. The senior notes are carried at
    amortized cost and are translated into Canadian dollars using the period
    end foreign exchange rate. At December 31, 2007 the amortized cost of the
    US$175,000,000 senior notes was US$178,093,000

    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.  INTEREST EXPENSE

    ($ thousands)                                          2007         2006
    -------------------------------------------------------------------------
    Realized
      Interest on long-term debt                    $    41,934  $    32,168
    Unrealized
      Gain on cross currency interest rate swap          (7,340)           -
      Gain on interest rate swaps                          (447)           -
      Amortization of the premium on senior
       unsecured notes                                     (631)           -
      Other                                                 111            -
    -------------------------------------------------------------------------
    Interest Expense                                $    33,627  $    32,168
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    9.  FOREIGN EXCHANGE

    ($ thousands)                                          2007         2006
    -------------------------------------------------------------------------
    Unrealized foreign exchange gain on translation
     of U.S. dollar denominated senior notes        $   (41,182) $       (32)
    Unrealized foreign exchange loss on cross
     currency interest rate swap                         31,777            -
    Unrealized foreign exchange loss on foreign
     exchange swaps                                         425            -
    Realized foreign exchange loss/(gain)                 1,909         (496)
    -------------------------------------------------------------------------
    Foreign exchange gain                           $    (7,071) $      (528)
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    The US$54,000,000 and US$175,000,000 senior unsecured notes are exposed
    to foreign currency fluctuations and are translated into Canadian dollars
    at the exchange rate in effect at the balance sheet date. Foreign
    exchange gains and losses are included in the determination of net income
    for the period.

    10. FUND CAPITAL

    (a) Unitholders' Capital

    Trust Units

    Authorized: Unlimited number of trust units

    (thousands)                      2007                      2006
    Issued:                     Units       Amount        Units       Amount
    -------------------------------------------------------------------------
    Balance before
     Contributed Surplus,
     beginning of year        123,151  $ 3,706,821      117,539  $ 3,407,567
    Issued for cash:
      Pursuant to public
       offerings                4,250      199,558        4,370      240,287
      Pursuant to rights
       incentive plan             205        6,758          640       22,974
    Trust unit rights
     incentive plan
     (non-cash) - exercised         -        2,288            -        3,065
    DRIP(*), net of
     redemptions                1,102       50,053          602       32,928
    Issued for acquisition
     of corporate and
     property interests
     (non-cash)                 1,105       54,750            -           -
    -------------------------------------------------------------------------
                              129,813    4,020,228      123,151   3,706,821
    Contributed Surplus
     (Trust Unit Rights
     Incentive Plan)                -       12,452            -       6,305
    -------------------------------------------------------------------------
    Balance, end of year      129,813  $ 4,032,680      123,151 $ 3,713,126
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    (*) Distribution Reinvestment and Unit Purchase Plan

    Contributed surplus ($ thousands)                      2007         2006
    -------------------------------------------------------------------------
    Balance, beginning of year                      $     6,305  $     3,047
    Trust unit rights incentive plan (non-cash) -
     exercised                                           (2,288)      (3,065)
    Trust unit rights incentive plan (non-cash) -
     expensed                                             8,435        6,323
    -------------------------------------------------------------------------
    Balance, end of year                            $    12,452  $     6,305
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    On April 10, 2007 the Fund closed an equity offering of 4,250,000 trust
    units at a price of $49.55 per unit for gross proceeds of $210,588,000
    ($199,558,000 net of issuance costs). These trust units were eligible for
    the April 20, 2007 cash distribution paid to unitholders of record at the
    close of business on April 10, 2007.

    In conjunction with the acquisition of Kirby on April 10, 2007, the Fund
    issued 1,105,000 trust units at a price of $49.55 per unit for gross
    proceeds of $54,750,000.

    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).

    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, 2007 a total of 3,404,000 rights issued pursuant to
    the Trust Unit Rights Incentive Plan ("Rights Incentive Plan") were
    outstanding at an average exercise price of $47.59. This represents 2.6%
    of the total trust units outstanding of which 1,635,000 rights, with an
    average exercise price of $44.84, were exercisable. Under the Rights
    Incentive 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, 2007 reduced the exercise price of the outstanding rights by
    $2.05 per trust unit of which a $0.52 reduction is effective January 2008
    and a $0.51 reduction is effective April 2008. 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:

                                                           2007         2006
    -------------------------------------------------------------------------
    Dividend yield                                        10.37%        9.26%
    Volatility                                            26.35%       25.61%
    Risk-free interest rate                                4.41%        4.13%
    Forfeiture rate                                        6.20%        2.80%
    Right's exercise price reduction                      $1.75        $1.61
    -------------------------------------------------------------------------

    The fair value of the rights granted under the plan during 2007 ranged
    between 9% and 12% (2006 - 12% and 14% of the underlying market price of
    a trust unit on the grant date.

    During the year the Fund expensed $8,435,000 or $0.07 per unit (2006 -
    $6,323,000 or $0.05 per unit) of unit based compensation expense using
    the fair value method. The remaining future fair value of the rights of
    $6,195,000 at December 31, 2007 (2006 - $10,113,000) will be recognized
    in earnings over the vesting period of the rights. Activity for the
    rights issued pursuant to the Rights Incentive Plan is as follows:

                                     2007                      2006
    -------------------------------------------------------------------------
                                          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           3,079  $     48.53        2,621  $     42.80
      Granted                     816        48.71        1,473        54.49
      Exercised                  (205)       32.90         (640)       35.94
      Cancelled                  (286)       50.74         (375)       46.35
    -------------------------------------------------------------------------
    End of year                 3,404        47.59        3,079        48.53
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    Rights exercisable
     at the end of the
     year                       1,635  $     44.84          809  $     39.81
    -------------------------------------------------------------------------
    (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, 2007. Rights vest between one and three years
    and expire between four and six years.

            Rights                 Exercise                           Rights
       Outstanding    Original  Price after                      Exercisable
    at December 31,   Exercise        Price     Expiry Date   at December 31,
       2007 (000's)      Price   Reductions     December 31      2007 (000's)
    -------------------------------------------------------------------------
                16     $ 26.09      $ 18.30            2008               16
                 4       27.70        20.11     2008 - 2009                4
                 8       33.00        25.72     2008 - 2009                8
                 7       36.00        29.10     2008 - 2009                7
               128       37.62        31.11     2008 - 2009              128
                 8       40.70        34.58     2008 - 2010                8
                23       37.25        31.50     2008 - 2010               23
                49       38.83        33.48     2008 - 2010               49
               341       40.80        35.80     2008 - 2010              341
                68       45.55        40.87     2009 - 2011               45
                72       44.86        40.53     2009 - 2011               46
               126       49.75        45.82     2009 - 2011               96
               532       56.93        53.41     2009 - 2011              364
               145       56.55        53.51     2010 - 2012               63
               402       54.21        51.67     2010 - 2012              156
               252       56.00        53.97     2010 - 2012              114
               443       52.90        51.38     2010 - 2012              167
               168       48.86        47.84     2011 - 2013                -
               444       50.25        49.74     2011 - 2013                -
               153       45.14        45.14     2011 - 2013                -
                15       38.70        38.70     2011 - 2013                -
    -------------------------------------------------------------------------
             3,404     $ 50.32      $ 47.59                            1,635
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    (c) Basic and Diluted per Trust Unit Calculations

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

    (thousands)                                            2007         2006
    -------------------------------------------------------------------------
    Weighted average units                              127,691      121,588
    Dilutive impact of rights                                61          270
    -------------------------------------------------------------------------
    Diluted trust units                                 127,752      121,858
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    In 2007 we excluded 222,347 rights because their exercise price was
    greater than the annual average unit market price of $47.11. No rights
    were excluded in calculating the weighted average number of diluted units
    for the year ended December 31, 2006. During the last two years,
    outstanding rights were the only potential dilutive instrument.

    (d) Performance Trust Unit Plan

    In 2007 the Board of Directors, upon recommendation of the Compensation
    Committee, approved new Performance Trust Unit ("PTU") plans for
    executives and employees. These plans will result in employees and
    officers receiving cash compensation in relation to the value of a
    specified number of underlying notional trust units. The number of
    notional trust units awarded is variable to individuals and they vest at
    the end of three years.

    Upon vesting, the plan participant receives a cash payment based on the
    fair value of the underlying trust units plus notional accrued
    distributions. The value determined upon vesting of the PTU Plans is
    dependent upon the performance of the Fund compared to its peers over the
    three year period. The level of performance within the peer group then
    determines a performance multiplier.

    At December 31, 2007 there were 179,000 performance trust units
    outstanding.

    11. INCOME TAXES

    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 2007, the Fund had taxable income of $632,000,000 (2006 -
    $588,000,000) or $4.92 per trust unit (2006 - $4.81 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.

    There were no dividend income and COGPE deductions for 2007. The amounts
    of COGPE and issue costs in the fund remaining as at December 31, 2007
    are $466,700,000 and $30,289,000 respectively.

    Canadian Government's tax on income trusts

    On June 22, 2007 Bill C-52, which contained legislative provisions to
    implement the proposals to tax publicly traded income trusts in Canada
    became law. As a result, our second quarter future income tax provision
    included a future income tax expense of $78,110,000 related to this
    legislation. This non- cash expense related to temporary differences
    between the accounting and tax basis of the Fund's assets and liabilities
    at that time and had no immediate impact on cash flow.

    On December 14, 2007, Bill C-28, which contained legislative provisions
    to implement corporate income tax rate reductions announced in the
    October 30, 2007 fall economic statement, became law. The general
    corporate tax rate will decrease by 1.0% in 2008 from 20.5% to 19.5%.
    There are additional rate reductions scheduled until the target federal
    tax rate of 15.0% is reached as of January 1, 2012. These rate reductions
    will also apply to the SIFT tax on distributions from income trusts. The
    SIFT tax rate will fall by 3.5% from 31.5% to 28.0%. As a result, our
    year to date future income tax provision includes a future income tax
    recovery of $22,640,000 related to this legislation and other tax rate
    changes enacted earlier in the year.

    We are currently evaluating alternatives to determine the optimal
    structure for our unitholders. However, we see value in the remaining
    three- year tax exemption period through 2010 and will look to maintain
    our current structure during this period unless there are compelling
    reasons to change.

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

    ($ thousands)                         Canadian      Foreign   2007 Total
    -------------------------------------------------------------------------
    Excess of net book value of
     property, plant and equipment
     over the underlying tax bases     $   176,962  $   194,393  $   371,355
    Asset retirement obligations           (41,669)           -      (41,669)
    Other                                   (2,825)     (33,409)     (36,234)
    -------------------------------------------------------------------------

    Net future income tax
     liability/(asset)                 $   132,468  $   160,984  $   293,452
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    Current future income tax asset    $   (10,807) $         -  $   (10,807)
    Long-term future income tax
     liability                         $   143,275  $   160,984  $   304,259
    -------------------------------------------------------------------------


    ($ 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)
    Other                                    6,963         (807)       6,156
    -------------------------------------------------------------------------
    Future income taxes                $   149,066  $   182,274  $   331,340
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    Current future income tax asset    $         -  $         -  $         -
    Long-term future income tax
     liability                         $   149,066  $   182,274  $   331,340
    -------------------------------------------------------------------------

    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)                                          2007         2006
    -------------------------------------------------------------------------
    Income before taxes                             $   361,712  $   450,984
    -------------------------------------------------------------------------
    Computed income tax expense at the enacted
     rate of 32.41% (34.88% for 2006)               $   117,231  $   157,303
    Increase (decrease) resulting from:
    Net income attributed to the Fund                  (162,016)    (197,694)
    Non-deductible crown royalties                            -       11,878
    Resource allowance                                        -      (11,998)
    Amended returns and pool balances                     5,150      (21,446)
    Change in tax rate                                  (22,640)     (35,500)
    SIFT Tax                                             78,110            -
    Other                                                 6,186        3,659
    -------------------------------------------------------------------------
                                                    $    22,021  $   (93,798)
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    Future income tax recovery                      $      (990) $  (112,034)
    Current tax                                     $    23,011  $    18,236
    -------------------------------------------------------------------------

    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, 2007
    ($ thousands)                         Canadian      Foreign        Total
    -------------------------------------------------------------------------
    Future income (recovery)/expense   $    (8,183) $     7,193  $      (990)
    Current income tax                           -       23,011       23,011
    -------------------------------------------------------------------------


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

    12. FINANCIAL INSTRUMENTS

    (a) Fair Value of Financial Instruments

    As a result of the adoption of the new financial instrument and hedging
    accounting standards described in Note 2, certain financial instruments
    are now measured and reported on the balance sheet at fair value which
    were previously reported at amortized cost.

    The fair value of a financial instrument is the amount of consideration
    that would be agreed upon in an arm's-length transaction between
    knowledgeable, willing parties who are under no compulsion to act. Fair
    values are determined by reference to quoted bid or ask prices, as
    appropriate, in the most advantageous active market for that instrument
    to which we have immediate access. Where bid and ask prices are
    unavailable, we would use the closing price of the most recent
    transaction for that instrument. In the absence of an active market, we
    determine fair values based on prevailing market rates for instruments
    with similar characteristics. Fair values may also be determined based on
    internal and external valuation models, such as option pricing models and
    discounted cash flow analysis, that use observable market based inputs
    and assumptions.

    The Fund is exposed to the commodity price fluctuations of crude oil and
    natural gas and to fluctuations in the Canada/US dollar exchange rate.
    The Fund manages this risk by entering into various derivative financial
    instruments.

    The Fund is exposed to credit risk due to the potential non-performance
    of counterparties to our financial instruments. The Fund mitigates this
    risk by having an established credit policy and controls designed to
    mitigate the risk of default or non-payment.

    The Fund has exposure to movements in interest rates. Changing interest
    rates can affect borrowing costs and the price on yield-based investments
    such as Enerplus trust units. The Fund monitors the interest rate forward
    market and has fixed the interest rate on a portion of our debt through
    our senior unsecured notes and interest rate swaps.

    (b) Carrying Value and Fair Value of Financial Instruments

    i. Cash

    Cash is classified as held-for-trading and is reported at fair value.

    ii. Accounts Receivable

    Accounts receivable are classified as loans and receivables which are
    reported at amortized cost. At December 31, 2007 the carrying value of
    accounts receivable approximated their fair value.

    iii. Marketable Securities

    Marketable securities with a quoted market price in an active market are
    classified as available-for-sale and are reported at fair value, with
    changes in fair value recorded in other comprehensive income. As at
    December 31, 2007 the Fund reported investments in marketable securities
    of publicly traded marketable securities at a fair value of $14,676,000.
    For the year ended December 31, 2007, the change in fair value of these
    investments represented a gain of $950,000 ($629,000 net of tax).

    Marketable securities without a quoted market price in an active market
    are reported at cost. As at December 31, 2007 the Fund reported
    investments in marketable securities of private companies at cost of
    $45,400,000.

    During the first quarter of 2007 the Fund disposed of certain marketable
    securities which resulted in a gain of $14,055,000 ($11,302,000 net of
    tax) being reclassified from accumulated other comprehensive income to
    net income. This gain is included in the other income balance of
    $14,991,000 on the Consolidated Statements of Income.

    As at December 31, 2007 total marketable securities of $60,076,000 are
    included in other assets or other assets on the Consolidated Balance
    Sheet. Realized gains and losses on marketable securities are included in
    other income.

    iv. Accounts Payable & Distributions Payable to Unitholders

    Accounts payable as well as distributions payable to unitholders are
    classified as other liabilities and are reported at amortized cost. At
    December 31, 2007 the carrying value of these accounts approximated their
    fair value.

    v. Long-term debt

    Bank Credit Facilities

    The bank credit facilities are classified as other liabilities and are
    reported at cost. At December 31, 2007 the carrying value of the bank
    credit facilities approximated their fair value.

    US$54 million senior notes

    The US$54,000,000 million senior notes, which are classified as other
    liabilities, are reported at their amortized cost of US$54,000,000 and
    are translated into Canadian dollars at the period end exchange rate. At
    December 31, 2007 the Canadian dollar amortized cost of the senior notes
    was approximately $53,357,000 and the fair value of these notes was
    $56,585,000.

    US$175 million senior notes

    The US$175,000,000 million senior notes, which are classified as other
    liabilities, are reported at amortized cost of US$178,093,000 and are
    translated to Canadian dollars at the period end exchange rate. At
    December 31, 2007 the Canadian dollar amortized cost of the senior notes
    was approximately $175,973,000 and the fair value of these notes was
    $185,591,000.

    vi. Derivative Financial Instruments

    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 June 2011 and January 2012. The interest rate swaps are
    classified as held-for-trading and are reported at fair value. At
    December 31, 2007 the fair value of the interest rate swaps represented a
    liability of $226,000 and the change in fair value of these contracts
    represented an unrealized gain of $447,000.

    Cross Currency Interest Rate Swap (CCIRS)

    Concurrent with the issuance of the notes on June 19, 2002, the Fund
    entered into a CCIRS 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 payments 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 CCIRS is
    classified as held-for- trading and is reported at fair value. At
    December 31, 2007 the fair value of the CCIRS represented a liability of
    $89,439,000 and the change in fair value of the CCIRS represented an
    unrealized loss of $24,437,000.

    Foreign Exchange Swaps

    In September 2007 the Fund entered into foreign exchange swaps on
    US$54,000,000 of notional debt at an average CAD/US foreign exchange rate
    of 1.02. These foreign exchange swaps mature between October 2011 and
    October 2015 in conjunction with the principal repayments on the
    US$54,000,000 senior notes. The foreign exchange swaps are classified as
    held-for-trading and are reported at fair value. At December 31, 2007 the
    fair value of the interest rate swaps represented a liability of $425,000
    and the change in fair value of these contracts represented an unrealized
    loss of $425,000.

    Electricity Instruments

    The Fund has entered into electricity swaps that fix the price of
    electricity. These contracts are classified as held-for-trading and are
    reported at fair value. At December 31, 2007 the fair value of these
    contracts represented an asset of $450,000 and the change in fair value
    of these contracts represented an unrealized loss of $1,044,000.

    Unrealized gains or losses resulting from changes in fair value along
    with realized gains or losses on settlement of the electricity contracts
    are recognized as operating costs.

    The following table summarizes the Fund's electricity management
    positions at February 20, 2008.
                                                                       Price
    Term                                            Volumes MWh     CDN$/MWh
    -------------------------------------------------------------------------
    January 1, 2008 - September 30, 2008                    4.0  $     63.00
    January 1, 2008 - December 31, 2009                     4.0  $     74.50
    -------------------------------------------------------------------------

    The Fund did not enter into any new electricity contracts in the first
    quarter of 2008.

    Crude Oil Instruments

    Enerplus has entered into the following financial option contracts to
    reduce the impact of a downward movement in crude oil prices. These
    contracts are classified as held-for-trading and are reported at fair
    value. At December 31, 2007 the fair value of these contracts represented
    a liability of $52,488,000 and the change in fair value of these
    contracts represented an unrealized loss of $63,410,000.

    The net premium cost of the crude oil instruments entered into as of
    December 31, 2007 is $7,739,000.

    The following table summarizes the Fund's crude oil risk management
    positions at February 20, 2008:

                                           WTI US$/bbl
                              -----------------------------------------------
                        Daily                                          Fixed
                      Volumes                                          Price
                     bbls/day  Sold Call  Purchased Put  Sold Put  and Swaps
    -------------------------------------------------------------------------
    Term
    January 1, 2008
     - June 30, 2008
      Put               1,500          -         $74.00         -          -
      Swap(1)           1,000          -              -         -     $92.61
      Swap(1)             500          -              -         -     $94.30
      Costless
       Collar(1)(3)       400     $79.00         $70.00         -          -
    January 1, 2008 -
     December 31, 2008
      Collar              750     $77.00         $67.00         -          -
      3-Way option      1,000     $84.00         $66.00    $50.00          -
      3-Way option      1,000     $84.00         $66.00    $52.00          -
      3-Way option      1,000     $86.00         $68.00    $52.00          -
      3-Way option      1,000     $87.50         $70.00    $52.00          -
      3-Way option      1,500     $90.00         $70.00    $60.00          -
      Put Spread(1)     1,500          -         $76.50    $58.00          -
      Swap                750          -              -         -     $72.94
      Swap                750          -              -         -     $74.00
      Swap                750          -              -         -     $73.80
      Swap                750          -              -         -     $73.35
      Swap(1)(3)          400          -              -         -     $78.53
    April 1, 2008 -
     December 31, 2008
      Put(2)              700          -         $86.10         -          -
    July 1, 2008 -
     December 31, 2008
      Put Spread(1)     1,500          -         $78.00    $58.00          -
      Swap(1)           1,500          -              -         -     $92.00
      Swap(1)(3)          400          -              -         -     $84.60
    January 1, 2009 -
     December 31, 2009
      Collar(2)           850    $100.00         $85.00         -          -
      3-Way option(1)   1,000     $85.00         $70.00    $57.50          -
      3-Way option(1)   1,000     $95.00         $79.00    $62.00          -
    -------------------------------------------------------------------------
    (1) Financial contracts entered into during the fourth quarter of 2007.
    (2) Financial contracts entered into subsequent to December 31, 2007.
    (3) Acquired through the acquisition of Focus.

    Natural Gas Instruments

    Enerplus has certain financial contracts outstanding as at February 20,
    2008 on its natural gas production that are detailed below.

    These contracts are classified as held-for-trading and are reported at
    fair value. At December 31, 2007 the fair value of these contracts
    represented an asset of $9,707,000 and the change in fair value of these
    contracts represented an unrealized loss of $2,983,000.

    The net premium cost of the financial natural gas instruments entered
    into as of December 31, 2007 is $921,000.

    The following table summarizes the Fund's natural gas risk management
    positions at February 20, 2008:



                                               AECO CDN$/Mcf
                              -----------------------------------------------
                        Daily                                          Fixed
                      Volumes                                          Price
                     MMcf/day  Sold Call  Purchased Put  Sold Put  and Swaps
    -------------------------------------------------------------------------
    Term
    January 1, 2008 -
     January 31, 2008
      Call(1)             4.7     $ 9.13              -         -          -
    February 1, 2008 -
     February 29, 2008
      Call(1)             4.7     $ 9.58              -         -          -
    January 1, 2008 -
     March 31, 2008
      Collar              2.4     $ 9.95          $8.00         -          -
      Collar              2.4     $10.15          $8.00         -          -
      Collar(1)(3)       14.2     $ 9.50          $8.70         -          -
      3-Way option        4.7     $10.50          $8.20     $5.70          -
      3-Way option        9.5     $11.61          $8.97     $6.33          -
      3-Way option        4.7     $11.08          $8.55     $6.01          -
      3-Way option        4.7     $ 9.50          $7.49     $5.70          -
      3-Way option        9.5     $ 9.50          $7.39     $5.70          -
      Swap                4.7          -              -         -      $8.70
      Swap                2.4          -              -         -      $9.01
      Swap(3)            14.2          -              -         -      $8.46
      Swap(3)             9.5          -              -         -      $9.07
    April 1, 2008 -
     October 31, 2008
      Collar              6.6     $ 8.44          $7.17         -          -
      Collar(1)           6.6     $ 7.49          $6.44         -          -
      Collar(1)           5.7     $ 7.39          $6.65         -          -
      Collar(2)          11.4     $ 8.65          $7.60         -          -
      Collar(2)           2.8     $ 8.65          $7.49         -          -
      Collar(2)           2.8     $ 8.86          $7.91         -          -
      3-Way option        5.7     $ 9.50          $7.54     $5.28          -
      3-Way option(1)    11.8     $ 7.91          $6.75     $5.49          -
      3-Way option(1)    11.8     $ 7.91          $6.75     $5.38          -
      3-Way option(2)     4.7     $ 8.23          $7.18     $5.28          -
      Swap                4.7          -              -         -      $8.18
      Swap(1)             7.6          -              -         -      $6.79
      Swap(1)(3)         14.2          -              -         -      $6.70
      Swap(2)(3)         14.2          -              -         -      $7.17
      Swap(2)             2.8          -              -         -      $7.91
      Swap(2)             2.8          -              -         -      $7.87
    November 1, 2008 -
     March 31, 2009
      Collar(2)           5.7     $ 9.50          $8.44         -          -
      3-Way option        5.7     $10.71          $7.91     $5.80          -
    2007 - 2010
    Physical (escalated
     pricing)             2.0          -              -         -      $2.59
    -------------------------------------------------------------------------
    (1) Financial contracts entered into during the fourth quarter of 2007.
    (2) Financial contracts entered into subsequent to December 31, 2007.
    (3) Acquired through the acquisition of Focus.

    13. COMMITMENTS AND CONTINGENCIES

    (a) Pipeline Transportation

    Enerplus has contracted to transport 104 MMcf/day of natural gas on the
    Nova system in the province of Alberta as well as 20 MMcf/day of natural
    gas on various pipelines to the US midwest. 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 within western Canada.

    (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, 2007 of $1,571,000.
    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 2011 and 2014. Annual costs of these lease
    commitments include rent and operating fees.

    (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
                                                                   Committed
                            Minimum Annual Commitment Each Year        after
                         -----------------------------------------      2012
    ($ thousands)   Total    2008    2009     2010    2011    2012
    -------------------------------------------------------------------------
    Bank credit
     facility   $ 497,347 $     - $     - $497,347 $     - $     -  $      -
    Senior
     unsecured
     notes      323,408(1)      -       -   53,666  64,682  64,682   140,378
    Pipeline
     commitments   31,063   9,972   5,879    3,960   2,797   2,405     6,050
    Office lease   67,875   6,907   7,559   10,304  10,782  11,082    21,241
    -------------------------------------------------------------------------
    Total
     commit-
     ments      $ 919,693 $16,879 $13,438 $565,277 $78,261 $78,169  $167,669
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    (1) Includes the economic impact of derivative instruments directly
        related to the senior unsecured notes (CCIRS and foreign exchange
        swap - see Note 12).

    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.

    Not reflected in the above schedule are those term contracts for
    transportation and the office lease that Enerplus assumed upon the
    completion of the Focus acquisition. The Focus term transportation
    contracts consist of 45 MMcf/day of natural gas in British Columbia, and
    60 MMcf/day of natural gas in Saskatchewan.

    14. GEOGRAPHICAL INFORMATION

    As at December 31, 2007
    ($ thousands)                           Canada          U.S.       Total
    -------------------------------------------------------------------------
    Oil and gas revenue                $ 1,252,413  $   286,740  $ 1,539,153
    Capital assets                       3,293,413      579,405    3,872,818
    Goodwill                                47,532      147,580      195,112
    -------------------------------------------------------------------------

    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
    -------------------------------------------------------------------------

    15. EVENTS SUBSEQUENT TO DECEMBER 31, 2007

    On February 13, 2008, Enerplus closed the acquisition of Focus. Under the
    plan of arrangement, Focus unitholders received 0.425 of an Enerplus
    trust unit for each Focus trust unit. This transaction is being accounted
    for as a business combination and the purchase price equation has not yet
    been determined. Total estimated consideration, including deal costs and
    assumed debt, is $1.7 billion, consisting of trust units issued and trust
    units issuable in respect of convertible limited partnership units.

    Enerplus issued a total of 30,150,000 trust units and assumed 9,087,000
    Class B units of Focus Limited Partnership, each exchangeable at the
    option of the holder for no additional consideration, into 0.425 of an
    Enerplus trust unit.

    5 YEAR DETAILED STATISTICAL REVIEW

    ($ thousands,
    except per
    unit amounts)   2007         2006         2005         2004         2003
    -------------------------------------------------------------------------
    Financial
    Oil and
     gas
     sales(1)$ 1,464,214  $ 1,569,487  $ 1,413,734  $   989,266  $   890,011
    Cash flow
     from
     operating
     activities  868,548      863,696      774,633      555,060      427,434
    Cash distri-
     butions to
     unitholders 646,835      614,340      498,205      423,311      372,576
      Per unit      5.04         5.04         4.47         4.20         4.29
    Cash withheld
     for acquis-
     itions and
     capital
     expendi-
     tures       221,713      249,356      276,428      113,248       34,145
    Development
     capital
     spending    387,165      491,226      368,689      206,874      157,706
    Acquisitions 274,244       51,313      704,028      636,326      225,293
    Divestments    9,572       21,127       66,511       31,742       73,214
    Total net
     capital
     expendi-
     tures       658,327      526,387    1,010,549      813,636      312,073
    Total
     assets    4,303,130    4,203,804    4,130,623    3,180,748    2,661,765
    Long-term
     debt, net
     of cash     724,975      679,650      649,825      584,991      257,701
    Payout
     ratio(2)        74%          71%          64%          76%          87%
    -------------------------------------------------------------------------
    Net debt/
     cash flow
     ratio          0.8x         0.8x         0.8x          1.1x        0.6x
    -------------------------------------------------------------------------

    Trust Unit
     Trading
     Information
    Toronto
     Stock
     Exchange
     trading
     summary
      Close     $  39.87     $  50.68     $  55.86      $  43.60    $  39.35
      Volume      96,898       82,120       62,278        52,821      51,800
    New York
     Stock
     Exchange
     trading
     summary
      Close     $  40.05     $  43.61     $  47.98      $  36.31    $  30.44
      Volume      54,192       81,677       70,454        67,570      60,624
    Weighted
     average
     number of
     units out-
     standing
     (basic)     127,691      121,588      109,083        99,273      86,202
    Number of
     units out-
     standing at
     December 31 129,813      123,151      117,539       104,124      94,349
    -------------------------------------------------------------------------

    -------------------------------------------------------------------------
    Average
     Benchmark
     Pricing
    AECO natural
     gas (per
     Mcf)          $6.61        $6.99        $8.48         $6.79       $6.70
    NYMEX natural
     gas (US$ per
     Mcf)           6.92         7.26         8.55          6.09        5.54
    WTI crude oil
     (US$ per bbl) 72.34        66.22        56.56         41.40       31.04
    CDN$/US$
     exchange
     rate           0.93         0.88         0.83          0.77        0.72
    -------------------------------------------------------------------------
    ($ per BOE
     except
     percentage
     data)
    -------------------------------------------------------------------------
    Oil and Gas
     Economics
    Net royalty
     rate            19%          19%          19%           21%         20%
    Weighted
     average
     price(3)     $50.48       $50.23       $52.36        $40.90      $36.94
    Hedging(4)      0.45        (1.10)       (4.90)        (3.50)      (1.81)
    -------------------------------------------------------------------------
    Weighted
     average
     price(1)      50.93        49.13        47.46         37.40       35.13
    Net royalty
     expense        9.49         9.36        10.21          8.40        7.51
    Operating
     expense(4)     9.11         8.02         7.45          7.14        6.73
    -------------------------------------------------------------------------
    Operating
     netback       32.33        31.75        29.80         21.86       20.89
    General and
     admini-
     strative
     expense(4)     1.98         1.71         1.28          1.06        0.95
    Management
     fee               -            -            -             -        2.29
    Interest
     expense,
     net of
     interest
     and other
     income(4)      1.37         0.95         0.51          0.68        0.74
    Foreign
     exchange(4)    0.06        (0.02)        0.13         (0.01)       0.08
    Taxes           0.77         0.70         0.31          0.24        0.26
    Restoration
     and abandon-
     ment cash
     costs          0.54         0.37         0.27          0.25        0.26
    -------------------------------------------------------------------------
    Cash flow
     before
     changes in
     non-cash
     working
     capital      $27.61       $28.04       $27.30        $19.64      $16.31
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    (1) Net of commodity derivative instruments and transportation
    (2) Calculated as cash distributions to unitholders divided by cash flow
        from operating activities
    (3) Net of transportation and before the effects of commodity derivative
        instruments
    (4) 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.

                  2007(1)      2006(1)      2005(1)      2004(1)      2003(1)
    -------------------------------------------------------------------------
    Daily
     Production
    Oil Sands
     (bbls/day)      n/a          n/a          n/a           n/a         n/a
    Crude Oil
     (bbls/day)   34,506       36,134        29,315       25,550      24,597
    NGLs
     (bbls/day)    4,104        4,483         4,689        4,398       4,666
    Natural Gas
     (Mcf/day)   262,254      270,972       274,336      271,091     240,907
    -------------------------------------------------------------------------
    BOE per day   82,319       85,779        79,727       75,130      69,414

    Drilling
     Activity
     (net wells)     252          361           393          367         294
    Success Rate     99%          99%           99%          99%         99%

    Production
     Replacement     90%          82%          247%         384%         91%

    Proved
     Reserves(2)
    Oil Sands
     (Mbbls)       8,568        8,730         9,453          n/a         n/a
    Crude Oil
     (Mbbls)     125,238      125,048       129,745      104,408      91,063
    NGLs (Mbbls)  11,785       12,690        13,084       12,776      13,571
    Natural Gas
     (MMcf)      866,077      920,061       965,776      971,598     867,204
    -------------------------------------------------------------------------
    MBOE         289,937      299,812       313,245      279,117     249,168
    -------------------------------------------------------------------------
    Probable
     Reserves(2)
    Oil Sands
     (Mbbls)      54,930       47,998        43,700       47,747         n/a
    Crude Oil
     (Mbbls)      35,504       34,421        31,567       26,783      27,807
    NGLs (Mbbls)   3,827        3,777         3,539        3,292       3,742
    Natural Gas
     (MMcf)      336,214      344,025       342,518      295,698     284,096
    -------------------------------------------------------------------------
    MBOE         150,297      143,533       135,892      127,105      78,898
    -------------------------------------------------------------------------
    Proved Plus
     Probable
     Reserves(2)
    Oil Sands
     (Mbbls)      63,498       56,728        53,153       47,747         n/a
    Crude Oil
     (Mbbls)     160,742      159,469       161,312      131,191     118,870
    NGLs
     (Mbbls)      15,612       16,467        16,623       16,068      17,313
    Natural Gas
     (MMcf)    1,202,291    1,264,086     1,308,294    1,267,296   1,151,300
    -------------------------------------------------------------------------
    MBOE         440,234      443,345       449,137      406,222     328,066
    -------------------------------------------------------------------------
    Reserve
     Life
     Index(3)
    Without
     Oil Sands:
    Proved
     (years)       10.0           9.8           9.6         10.1       10.6
    Proved Plus
     Probable
     (years)       12.8          12.2          12.0         12.4       13.3
    -------------------------------------------------------------------------
    With Oil
     Sands:
    Proved
     (years)       10.3          10.1           9.9         10.1       10.6
    Proved Plus
     Probable
     (years)       14.8          14.0          13.5         14.0       13.3
    -------------------------------------------------------------------------

    (1) 2003 - 2007 reserve information reflects NI 51-101 reporting
        methodology.
    (2) Company interest reserves consist of gross reserves (as defined in
        National Instrument 51-101) plus Enerplus' royalty interests. Company
        interest reserves are not a term defined in National instrument
        51-101 and may not be comparable to reserves disclosed by other
        issuers.
    (3) The Reserve Life Indices (RLI) are based upon year-end proved plus
        probable reserves divided by the following year's proved and proved
        plus probable production volumes as determined in the independent
        reserve engineering reports.

    INFORMATION REGARDING DISCLOSURE IN THIS NEWS RELEASE AND OIL AND GAS
    RESERVES, RESOURCES AND OPERATIONAL INFORMATION

    All amounts in this news release are stated in Canadian dollars unless
    otherwise specified.

    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. In accordance with Canadian practice,
    production volumes and revenues are reported on a gross basis, before
    deduction of Crown and other royalties, unless otherwise stated. Unless
    otherwise specified, all reserves volumes in this news release (and all
    information derived therefrom) are based on "company interest reserves"
    using forecast prices and costs. "Company interest reserves" consist of
    "gross reserves" (as defined in National Instrument 51-101 adopted by the
    Canadian securities regulators ("NI 51-101") plus Enerplus' royalty
    interests in reserves. "Company interest reserves" are not a measure
    defined in NI 51-101 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 oil
    and gas reserves statement for the year ended December 31, 2007, which
    will include complete disclosure of our oil and gas reserves and other
    oil and gas information in accordance with NI 51-101, will be 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 will form part of our Form 40-F
    that will be filed with the SEC and available on www.sec.gov. Readers are
    also urged to review the Management's Discussion & Analysis and financial
    statements included in this news release for more complete disclosure on
    our operations.

    This news release contains estimates of "contingent resources".
    "Contingent resources" are not, and should not be confused with, oil and
    gas reserves. "Contingent resources" are defined in the Canadian Oil and
    Gas Evaluation Handbook (the "COGE Handbook") as "those quantities of
    petroleum estimated, as of given date, to be potentially recoverable from
    known accumulations using established technology or technology under
    development, but which are not currently considered to be commercially
    recoverable due to one or more contingencies. Contingencies may include
    factors such as economic, legal, environmental, political and regulatory
    matters or a lack of markets. It is also appropriate to classify as
    contingent resources the estimated discovered recoverable quantities
    associated with a project in the early evaluation stage."

    There is no certainty that Enerplus will produce any portion of the
    volumes currently classified as "contingent resources". The primary
    contingencies which currently prevent the classification of Enerplus'
    disclosed contingent resources associated with the Kirby oil sands
    project as reserves consist of current uncertainties around the specific
    scope and timing of the project development, proposed reliance on
    technologies that have not yet been demonstrated to be commercially
    applicable in oil sands applications, the uncertainty regarding marketing
    plans for production from the subject areas and improved estimation of
    project costs. The primary contingencies which currently prevent the
    classification of Enerplus' disclosed contingent resources associated
    with the Joslyn Project as "reserves" consist of current uncertainties
    around the specific scope of the Joslyn Project (and in particular the
    finalization of an overall lease development plan), timing of the
    proposed development as it relates to proposed changes in the lease
    development plan, proposed reliance on technologies that have not yet
    been demonstrated to be commercially applicable in oil sands
    applications, the uncertainty regarding marketing plans for production
    from the subject areas and improved estimation of project costs. Based on
    current information and market conditions, Enerplus believes that
    development of the Kirby and Joslyn projects will proceed as described in
    this news release, although readers should consider the described
    uncertainties regarding SAGD expansion and the development of the mining
    portion of the Joslyn Project, as described herein. However, there
    are a number of inherent risks and contingencies associated with the
    development of the Kirby and Joslyn projects, including commodity price
    fluctuations, project costs, receipt of regulatory approvals and those
    other risks and contingencies described above and under "Risk Factors and
    Risk Management" in the Management's Discussion an Analysis section of
    this news release and under "Risk Factors" in the Fund's Annual
    Information Form (and corresponding Form 40-F) dated March 12, 2007, as
    well as the risk factors to be contained in the Fund's Annual Information
    Form (and corresponding Form 40-F) to be filed in mid-March 2008.

    NOTICE TO U.S. READERS

    The oil and natural gas reserves contained in this Annual Information
    Form has generally been prepared in accordance with Canadian disclosure
    standards, which are not comparable in all respects of United States or
    other foreign disclosure standards. For example, the United States
    Securities and Exchange Commission (the "SEC") generally permits oil and
    gas issuers, in their filings with the SEC, to disclose only proved
    reserves (as defined in SEC rules). Canadian securities laws require oil
    and gas issuers, in their filings with Canadian securities regulators, to
    disclose not only proved reserves (which are defined differently from the
    SEC rules) but also probable reserves, each as defined in NI 51-101.
    Accordingly, proved reserves disclosed in this news release may not be
    comparable to U.S. standards, and in this news release, Enerplus has
    disclosed reserves designated as "probable reserves" and "proved plus
    probable reserves". Probable reserves are higher risk and are generally
    believed to be less likely to be accurately estimated or recovered than
    proved reserves. The SEC's guidelines strictly prohibit reserves in these
    categories from being included in filings with the SEC that are required
    to be prepared in accordance with U.S. disclosure requirements. In
    addition, under Canadian disclosure requirements and industry practice,
    reserves and production are reported using gross (or, as noted above,
    "company interest") volumes, which are volumes prior to deduction of
    royalty and similar payments. The practice in the United States is to
    report reserves and production using net volumes, after deduction of
    applicable royalties and similar payments. Moreover, Enerplus has
    determined and disclosed estimated future net revenue from its and Focus'
    reserves using forecast prices and costs, whereas the SEC generally
    requires that prices and costs be held constant at levels in effect at
    the date of the reserve report. As a consequence of the foregoing,
    Enerplus' and Focus' reserve estimates and production volumes in this
    news release may not be comparable to those made by companies utilizing
    United States reporting and disclosure standards. Additionally, the SEC
    prohibits disclosure of oil and gas resources, whereas Canadian issuers
    may disclose resource volumes. Resources are different than, and should
    not construed as, reserves. For a description of the definition of, and
    the risks and uncertainties surrounding the disclosure of, contingent
    resources, see above.

    FORWARD-LOOKING INFORMATION AND STATEMENTS

    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", "strategy" 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
    volumes and estimated value of the Fund's oil and gas reserves; the life
    of the Fund's 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 and operating metrics; future costs, expenses and royalty
    rates; future interest costs; future development, exploration,
    acquisition and development activities (including drilling plans) and
    related capital expenditures, including with respect to both our
    conventional and oil sands activities and in particular the development
    of the Kirby and Joslyn leases; future acquisitions and dispositions; the
    reinstatement of production from the Giltedge property and the
    availability of business interruption insurance to mitigate the costs of
    the Giltedge fire; the making and timing of future regulatory filings and
    applications; the value of the Fund's equity investments; future tax
    treatment of income trusts and future taxes payable by the Fund; the
    Fund's tax pools; the impact of the Focus acquisition on the Fund; the
    amount, timing and tax treatment of cash distributions to unitholders;
    and future payout ratios.

    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, the implementation of proposed)
    tax, royalty and regulatory regimes; the accuracy of the estimates of the
    Fund's reserve and resource volumes; certain commodity price and other
    cost assumptions; the continued availability of adequate debt and equity
    financing and cash flow to fund its plans expenditures; and accurate
    assessment of the value of Focus' assets and the extent of its
    liabilities 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; changes in the demand for or supply of the Fund's
    products; unanticipated operating results or production declines; changes
    in tax or environmental laws, royalty rates or other regulatory matters;
    changes in development plans the Fund or by third party operators of the
    Fund's properties, including the operator of the Joslyn oil sands
    project; increased debt levels or debt service requirements; inaccurate
    estimation of the Fund's and Focus' oil and gas reserve and resource
    volumes; limited, unfavourable or a lack of access to capital markets;
    increased costs; a lack of adequate insurance coverage; declines in the
    value of the Fund's equity investments; 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

    %CIK: 0001126874

Emergency Number 1-877-576-5636
Last Updated: February 25, 2014
© Copyright 2011 Enerplus Corp.