Enerplus announces 2008 year end results and reserves information



    
    TSX:  ERF.UN
    NYSE:   ERF
    

    CALGARY, Feb. 26 /CNW/ - Enerplus Resources Fund ("Enerplus") is pleased
to announce our financial and operating results for the year ended December
31, 2008. Given the global economic down turn that occurred during the course
of the year, it proved to be a challenging year on many fronts. We were
successful, however, in executing on a number of our key strategic objectives
during 2008. This has resulted in Enerplus being in a relatively strong
financial position in a depressed market, exiting the year with over a billion
dollars of available credit capacity. We believe this affords us a significant
advantage to capitalize on potential acquisition opportunities as we move
forward in 2009.

    As previously announced, we have reduced capital spending plans for 2009
relative to 2008 and have also reduced our distributions to unitholders to
preserve our financial strength. Given the current economic environment, we
expect cost structures to improve and are working aggressively to reduce costs
throughout our organization. We will continue to evaluate our currently
planned projects for 2009 relative to both expected reductions in cost
structures and direction of commodity prices.

    As we move forward in 2009 we will be looking to increase our ownership
in the resource plays we have targeted for greater, more profitable growth for
2009 and beyond. We expect that the successful execution of our strategies
will be demonstrated over time through improved operational metrics including
improved recycle ratios and improved finding and development costs. Ultimately
our key objective is to enhance the total return to our unitholders.

    
    STRATEGIC EXECUTION:

    -   During the first half of 2008, Enerplus successfully completed the
        acquisition and integration of the assets of Focus Energy Trust, the
        single largest transaction in our history valued at $1.7 billion.
    -   We sold our 15% interest in the Joslyn oil sands lease for $502
        million. These proceeds were used to reduce our outstanding bank
        debt.
    -   We continued to advance on our Kirby oil sands project with the
        filing of our regulatory application for Phase I in late September.
        We also increased the contingent resource estimate by 70% to over 400
        million barrels of bitumen.
    -   Crude oil and natural gas prices declined dramatically in the fourth
        quarter of 2008 as the global economic environment deteriorated. In
        response, we have reduced our 2009 capital spending plans and
        distributions to unitholders. We believe these actions will preserve
        our balance sheet strength and position us to take advantage of
        potential acquisition opportunities.

    STRATEGIC POSITIONING FOR THE FUTURE:

    -   We believe that Enerplus currently has one of the strongest balance
        sheets in the oil and gas sector. With over $1 billion of unused
        credit capacity we believe this is a tremendous competitive
        advantage in the current economic environment.
    -   Enerplus has a proven track record of completing strategic
        transactions that improve our business. We are focused on acquiring
        high quality assets in growth areas such as tight gas and tight oil
        through acquisitions in priority investing development capital in
        our existing asset base. We are also directing 25% of our 2009
        capital program toward growth projects in these areas to provide
        even greater value growth opportunities in the future.
    -   We are focused on preserving our financial flexibility.  By reducing
        both our capital spending and distributions relative to our cash
        flows, we are positioning to minimize any increases in our debt
        except as may be necessary in our acquisition strategies.
    -   As we enter 2009, our emphasis is on production optimization and
        cost reductions to improve capital efficiencies and performance. We
        have a meaningful inventory of natural gas and oil projects, but in
        the current commodity price environment, we will look to retain our
        drilling inventory until such time as prices and cost structures
        improve.
    -   We are also undertaking a review of our asset base to identify those
        conventional properties which do not fit into our longer-term
        strategic plan of growing our resource play asset base.  It is part
        of our strategy to rationalize these non-core assets at the
        appropriate time.
    -   We believe that our asset base is well suited to an income-oriented
        business model and believe that there will continue to be a growing
        demand for yield-oriented investments. We continue to evaluate
        alternatives to our income trust structure with the expectation that
        we will most likely convert to a dividend paying corporation. With
        the current forward commodity price and our plans regarding
        production, costs and capital spending, we do not expect a
        significant change to our overall tax costs until 2013 even if we
        were to convert to a corporation during 2010.

    FINANCIAL HIGHLIGHTS:

    -   Cash flow from operating activities totaled $1,263 million in 2008,
        an increase of 45% over 2007 levels.
    -   Cash distributions to unitholders totaled $5.06 per trust unit
        essentially unchanged from the amount paid in 2007, resulting in a
        payout ratio of 62% versus 74% in 2007.
    -   Distributions and development capital spending totaled 109% of cash
        flow, compared to 120% in 2007.
    -   We maintained a strong balance sheet with a net debt to trailing 12
        month cash flow ratio of 0.5x.


    OPERATIONAL HIGHLIGHTS:

    -   Production averaged 95,687 BOE/day in 2008, in-line with our third
        quarter guidance of 96,000 BOE/day.
    -   Average December production volumes were 96,400 BOE/day (98,000
        BOE/day after adjusting for unexpected downtime at two non-operated
        facilities, both of which were resolved by year-end). The adjusted
        exit rate was only slightly behind our exit rate guidance of 98,500
        BOE/day.
    -   Development capital spending was $578 million, 6% higher than our
        guidance of $545 million principally as a result of accelerating
        capital spending on certain projects.
    -   We drilled a record 643 net wells with a 99% success rate.
    -   General and Administrative ("G&A") expenses were $1.88/BOE, 6% lower
        than our guidance of $2.00/BOE and 17% lower than $2.26/BOE in 2007.
    -   Operating costs were $9.50/BOE for 2008, in-line with our guidance
        but representing an increase of 4% year-over-year.
    -   We invested $106 million to pursue our resource-play growth strategy
        including $55 million on exploration drilling, land and seismic, and
        $51 million on oil sands.
    -   We continued to focus on the health and safety of our workers and
        recorded better performance than the Canadian Association of
        Petroleum Producers' industry average.

    RESERVES:

    -   We replaced 78% of 2008 production through reserve additions from
        development capital spending and net acquisitions on a proved plus
        probable basis.
    -   Proved reserves increased 10% to 319 MMBOE, while probable reserves
        decreased 24% to 114 MMBOE primarily due to the sale of the Joslyn
        oil sands interest. Our total proved plus probable reserves decreased
        by 2% to 432.4 MMBOE.
    -   Proved plus probable finding, development and acquisition costs
        ("FD&A") on our conventional oil and gas activities were $29.17/BOE
        for the year including future development capital.
    -   Our conventional recycle ratio for 2008 was 1.4x.
    -   Our Reserve Life Index ("RLI") continues to be one of the longest in
        the sector at 12.1 years on a proved plus probable basis and 9.4
        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",
"Notice to U.S. Readers" and "Forward-Looking Information and Statements" at
the end of this news release for information regarding the presentation of the
financial, reserves, resources and operational information in this news
release and information regarding the inclusion of certain forward-looking
information and statements in this news release. 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.

    
    SELECTED FINANCIAL RESULTS

                                Three months ended       Twelve months ended
                                       December 31,              December 31,
    (in Canadian dollars)        2008         2007         2008         2007
    -------------------------------------------------------------------------
    Financial (000's)
    Cash Flow from
     Operating Activities $   258,536  $   205,084  $ 1,262,782  $   868,548
    Cash Distributions
     to Unitholders(1)        167,017      163,447      786,138      646,835
    Cash Withheld for
     Acquisitions and
     Capital Expenditures      91,519       41,637      476,644      221,713
    Net Income                189,495       98,701      888,892      339,691
    Debt Outstanding
     (net of cash)            657,421      724,975      657,421      724,975
    Development Capital
     Spending                 200,254      106,120      577,739      387,165
    Acquisitions                1,443        5,095    1,772,826      274,244
    Divestments                   162        4,003      504,859        9,572
    Actual Cash
     Distributions
     to Unitholders
     per Trust Unit       $      1.23  $      1.26  $      5.06  $      5.04

      Financial per
       Weighted Average
       Trust Unit(2)
      Cash Flow from
       Operating
       Activities         $      1.56  $      1.58  $      7.86  $      6.80
      Cash Withheld for
       Acquisitions and
       Capital
       Expenditures              0.55         0.32         2.97         1.74
      Net Income                 1.15         0.76         5.54         2.66
      Payout Ratio(3)              65%          80%          62%          74%

      Selected Financial
       Results per BOE(4)
      Oil & Gas Sales(5)  $     46.54  $     52.33  $     65.79  $     50.48
      Royalties                 (8.61)       (9.83)      (12.27)       (9.49)
      Commodity Derivative
       Instruments               3.54        (0.08)       (2.94)        0.45
      Operating Costs           (9.46)       (8.53)       (9.51)       (9.11)
      General and
       Administrative           (1.71)       (1.94)       (1.68)       (1.98)
      Interest and Other
       Income and
       Foreign Exchange         (2.73)       (1.70)       (1.59)       (1.43)
      Taxes                      0.92        (1.70)       (0.65)       (0.77)
      Asset retirement
       obligations settled      (0.53)       (0.75)       (0.52)       (0.54)
    -------------------------------------------------------------------------
      Cash Flow from
       Operating
       Activities before
       changes in
       non-cash working
       capital            $     27.96  $     27.80  $     36.63  $     27.61
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    Weighted Average
     Number of
     Trust Units
      Outstanding
       Including
       Equivalent
      Exchangeable
       Limited
       Partnership
       Units (thousands)      165,373      129,658      160,589      127,691
      Debt/Trailing
       12 Month Cash
       Flow Ratio(6)             0.5x         0.8x         0.5x         0.8x
    -------------------------------------------------------------------------



    SELECTED OPERATING RESULTS

                                Three months ended       Twelve months ended
                                       December 31,              December 31,
                                 2008         2007         2008         2007
    -------------------------------------------------------------------------
    Average Daily
     Production
    Natural gas (Mcf/day)     346,439      257,415      338,869      262,254
    Crude oil (bbls/day)       35,434       34,221       34,581       34,506
    NGLs (bbls/day)             4,529        3,836        4,627        4,104
    Total (BOE/day)            97,702       80,959       95,687       82,319

    % Natural gas                 59%          53%          59%          53%

    Average Selling
     Price(5)
    Natural gas (per Mcf) $      6.92  $      5.91  $      8.17  $      6.45
    Crude oil (per bbl)         55.16        72.21        91.31        65.11
    NGLs (per bbl)              43.55        58.12        68.93        51.35
    CDN$/US$ exchange
     rate                        0.82         1.02         0.94         0.93

    Net Wells drilled             174           76          643          252
    Success Rate(7)                99%         100%          99%          99%
    -------------------------------------------------------------------------
    (1) Calculated based on distributions paid or payable.
    (2) Based on weighted average trust units outstanding for the period,
        including the exchangeable limited partnership units assumed through
        the Focus Energy Trust acquisition during 2008.
    (3) Calculated as Cash Distributions to Unitholders divided by Cash Flow
        from Operating Activities. See "Non-GAAP Measures" in the following
        Management's Discussion and Analysis.
    (4) Non-cash amounts have been excluded.
    (5) Net of oil and gas transportation costs, but before the effects of
        commodity derivative instruments.
    (6) Including the trailing 12 month cash flow of Focus Energy Trust for
        2008.
    (7) Based on wells drilled and cased.


    Trust Unit Trading Summary

    For the twelve months ended                     TSX - ERF.un   NYSE - ERF
     December 31, 2008                                  (CDN$)         (US$)
    -------------------------------------------------------------------------
    High                                               $ 49.85       $ 50.63
    Low                                                $ 21.53       $ 17.07
    Close                                              $ 23.96       $ 19.58


    2008 Cash Distributions
     Per Trust Unit

    Payment Month                                         CDN$           US$
    -------------------------------------------------------------------------

    First Quarter Total                                 $ 1.26        $ 1.23
    Second Quarter Total                                $ 1.26        $ 1.25
    Third Quarter Total                                 $ 1.31        $ 1.26

    October                                             $ 0.47        $ 0.39
    November                                              0.38          0.29
    December                                              0.38          0.31
    Fourth Quarter Total                                $ 1.23        $ 0.99

    Total Year-to-Date                                  $ 5.06        $ 4.73
    


    OPERATIONS

    2008 was a very active year for Enerplus as we closed and integrated the
single largest acquisition in our history and executed our largest capital
development program to date. Our activities essentially delivered our
production targets for annual average volumes, exit rate volumes, operating
costs and G&A costs. However, we were disappointed with our capital
efficiencies and our reserve additions were impacted by negative revisions.

    Production

    Daily production for 2008 averaged 95,687 BOE/day representing a new
record and in-line with our guidance of 96,000 BOE/day. Our average daily
volumes were approximately 16% higher than 2007 as a result of the Focus
Energy Trust ("Focus") acquisition which closed on February 13, 2008 and added
approximately 18,000 BOE/day of annualized production.
    We exited 2008 with production volumes of approximately 96,400 BOE/day,
roughly 2% lower than our guidance of 98,500 BOE/day due to unexpected
downtime at two non-operated facilities. Approximately 1,100 BOE/day was shut
in at our Tommy Lakes property during December due to a labour strike at a
processing facility and we lost approximately 500 BOE/day due to unplanned
downtime at our Bantry facility. Both the strike and the Bantry turnaround
were resolved by year-end. After adjusting for these events, our exit rate was
approximately 98,000 BOE/day.

    Development Activities

    Our capital spending program during 2008 totaled $578 million,
approximately $33 million above our third quarter guidance of $545 million. We
spent an additional $22 million due to accelerated activity associated with
good weather conditions and rig availability at Tommy Lakes, Bantry and
Shackleton as well as an accelerated seismic program at our Kirby oil sands
project. An additional $11 million was incurred due to higher than expected
service and drilling costs and higher maintenance costs on various properties.
This additional spending is not expected to have a material impact on our 2009
guidance.
    Our conventional capital development program in 2008 was equally weighted
to both oil and natural gas projects across our portfolio. In total, we
drilled 643 net wells with a 99% success rate and brought on approximately
19,500 BOE/day of initial production at an average on-stream cost of
$27,000/BOE/day, excluding oil sands spending. Approximately 80% of the
capital was spent in our five core resource plays with a majority of the
drilling activity targeted to shallow gas (520 wells). We increased our
drilling activity in our tight gas resource plays and shifted our U.S. Bakken
activity from drilling wells to completing refracs on existing wells. Overall
our capital efficiencies decreased from 2007 due to lower performance,
continued cost escalation which only began to moderate in the latter half of
the year and a higher percentage of infrastructure spending.
    We continued to invest in growth projects during 2008 as approximately
18% (or $106 million) of our capital program was invested in these activities
including oil sands. This growth spending does not typically add production,
reserves or cash flow in the near term as we are investing in land, seismic
and exploration activities that help capture new opportunities for the future.
We are encouraged by the progress we are making on a number of new growth
plays which are in the early stages. We expect this type of spending to grow
as a percentage of our capital spending plans going forward.
    In 2008 we invested $55 million in exploration drilling and new land and
seismic primarily in the Montney regions of Alberta and British Columbia and
the Bakken region of southeast Saskatchewan. Spending on our oil sands assets
increased from $39 million in 2007 to $51 million in 2008.

    
    2008 Production and Capital

                     Average    Drilling
                       Daily    Activity     Initial     Capital     Capital
                  Production        (Net  Production    Spending  Efficiency
    Play Types      (BOE/day)      Wells)   (BOE/day)       ($MM) ($/BOE/day)
    -------------------------------------------------------------------------
    Shallow Gas
     & Coalbed
     Methane          23,666         520       5,660    $    159    $ 28,100
    Crude Oil
     Waterfloods      16,282          40       3,000          84      28,000
    Tight Gas         15,070          20       5,100          81      15,900
    Bakken/Tight Oil  10,831          11       3,200          99      30,940
    Other
     Conventional
     Oil & Gas        29,838          52       2,500         104      41,600
    -------------------------------------------------------------------------
    Total
     Conventional     95,687         643      19,460    $    527    $ 27,100
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    Oil Sands              0         n/a         n/a          51         n/a
    -------------------------------------------------------------------------
    Total Company     95,687         643      19,460    $    578    $ 29,700
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------


    Resource Plays

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

    Shallow natural gas and coal bed methane ("CBM") represented 25% of our
average daily production volumes in 2008, an increase of 61% over 2007,
reflecting the additional working interests acquired in the Shackleton field
from Focus. Given the inventory of higher quality locations from the Focus
acquisition and strong natural gas prices for most of the year, we invested
$159 million, drilling 520 net shallow gas wells in 2008 with most of our
spending at Shackleton in Saskatchewan and Bantry, Verger and Medicine Hat in
Alberta.
    Our capital efficiency of $28,100/BOE/day was higher than in 2007 due to
the early start of our 2009 program to ensure we have our wells tied in before
break-up and increased infrastructure costs associated with pipeline repairs
and compressor upgrades.
    With softening natural gas prices, our projected spending levels for 2009
have been reduced to approximately $75 million. We plan to drill approximately
226 net wells and will continue to focus on infill drilling at Shackleton,
Bantry and Verger where our most attractive opportunities exist. We anticipate
that over 80% of our total conventional wells in 2009 will be shallow gas
wells targeting the Milk River and Medicine Hat formations.

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

    Crude oil waterfloods represented approximately 17% of our 2008 average
daily production from about 12 major properties located across the Western
Canadian Sedimentary Basin. We operate over 80% of our waterfloods and
invested $84 million in this resource play in 2008. Capital spending was
largely focused at Giltedge, Pembina, Virden and Silver Heights where we
drilled 40 net wells. Capital efficiency in this resource play was impacted by
the ongoing maintenance costs associated with these properties as a percentage
of total capital and a higher percentage of investment in infrastructure
projects to upgrade facilities which will support longer-term development. Our
capital efficiency of $28,000/BOE/day was better than the average efficiency
for this resource play in 2006 and 2007.
    We expect to decrease our 2009 capital spending significantly in our
waterflood assets to approximately $45 million due to the marginal economics
of crude oil projects at current price levels. However we plan to continue
identifying development prospects in our most attractive plays to be well
positioned to restart these programs when oil prices rebound and/or cost
structures improve. The current allocated funds will be used for ongoing
production optimization projects which have the most attractive economics as
well as the completion and tie in of wells that were drilled in the fourth
quarter of 2008. Due to the ongoing maintenance requirements and lower level
of capital investment, capital efficiencies in this area are not expected to
improve in 2009.

    
    Tight Gas
    ---------
    

    Our tight gas resource play is a growing component of our asset base and
almost doubled in size from 2007 mainly due to the acquisition of the Tommy
Lakes property in British Columbia. This play now represents 15% of our total
corporate production. We more than doubled our capital spending in 2008 to $81
million and increased the number of net wells drilled from 6 to 20
year-over-year. Approximately 40% of our capital was spent at Tommy Lakes to
complete and tie-in 17 wells in early 2008. Due to favourable weather
conditions, we were able to accelerate our 2009 capital spending in this area
with approximately $14 million spent in 2008 for our 2008/09 winter program.
The remaining investment in this resource play in 2008 was primarily at our
Ansell and Elmworth properties in Alberta.
    Our 2008 capital efficiency of $15,900/BOE/day benefited from capital
spent by Focus during the 2007/2008 winter drilling program prior to our
acquisition in February. Going forward, advances in our use of horizontal and
completion technologies and/or deflationary pressures may improve our results.
    Our spending levels for 2009 are expected to remain relatively constant
compared to 2008 at $78 million. Our plans include ongoing development at
Tommy Lakes with a 14 well program including a few step-out wells aimed at
expanding the play and the piloting of a horizontal well. We also expect to
continue to add to our tight gas land positions in other areas and begin
delineating the new lands purchased in 2008.

    
    Bakken/Tight Oil
    ----------------
    

    Our Bakken/tight oil resource play represented roughly 11% of our 2008
average daily production, with virtually all of this production coming from
the Sleeping Giant project in Montana. In 2008, we continued to invest in this
project, spending approximately $70 million. We also expanded our Bakken
interests with the purchase of approximately 30,000 acres of undeveloped land
in southeast Saskatchewan. In total we invested $99 million in this resource
play in 2008.
    We continued our third well per section development drilling program at
Sleeping Giant in 2008 and drilled 11 net wells and refrac'd 16 net wells.
Capital efficiencies in the U.S. during 2008 were $21,500/BOE/day. When we
include the purchase of Bakken lands in Canada, our capital efficiency
declined to $30,940/BOE/day. In 2008 we also initiated a full optimization
program and tested a variety of techniques to improve production. These
efforts added approximately $8 million to our operating costs which also
resulted in approximately 600 BOE/day of increased production. We expect to
reduce our optimization activities in 2009 and should see an improvement in
operating costs as the year progresses.
    In 2009, we have allocated $42 million to Bakken/tight oil the majority
of which will be invested at Sleeping Giant. We plan on concentrating our
spending on refracs (24 planned) and modest drilling subject to commodity
price and/or cost improvements. There are approximately 15 third well per
section drilling locations, approximately 40 fourth well per section locations
and 120 refrac wells remaining in our inventory at Sleeping Giant. We are also
participating in a CO2 pilot project on an existing Enerplus producing well
with two other industry partners. Injection commenced in January 2009 and we
expect to be able to provide an update on these activities later in the year.
Outside of Sleeping Giant, we are also pursuing investments in other tight oil
resource plays in both the U.S. and Canada.

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

    Other conventional oil and gas properties comprised approximately 32% of
our average daily production and 18% of capital spending in 2008. This
includes a diversified portfolio of both crude oil and natural gas projects
across western Canada of which we operate approximately 55% of the production
and 70% of the capital spending. Capital investment on these assets was
slightly lower year-over-year at $104 million but was reduced from 33% to 20%
of our conventional spending as we continued to focus on our core resource
plays in 2008.
    Our 2008 capital efficiency was negatively impacted by lower than
expected performance at Colgate, Shorncliff, Sylvan Lake and a number of
non-operated properties as well as higher infrastructure investment. As well,
the timing of capital spending late in 2008 has increased capital efficiencies
as the associated production will not come on stream until 2009. As a result,
capital efficiencies averaged $41,600/BOE/day.
    As we continue to concentrate our capital spending in our core resource
play areas, coupled with the decrease in commodity prices, we expect that in
2009 our investment in this category will decrease significantly to
approximately $35 million, representing a reduction of 66% year-over-year. We
will monitor economic conditions throughout the year and will be prepared to
adjust our allocation of capital among the various play types as required.

    
    Oil Sands
    ---------
    

    We invested $51 million in our oil sands portfolio in 2008, $41 million
of which was spent on our Kirby SAGD project. Approximately $10 million was
spent on the Joslyn project prior to the sale of this asset in July.

    Kirby

    Kirby is located in the heart of the Athabasca fairway close to other
major SAGD projects currently on production and extends over 43,360 gross
acres (67 sections of land) in a highly prospective area where we see a number
of potential oil sands pay zones. Enerplus holds a 100% working interest in
the property. The current plan would see the property developed in phases,
with Phase 1 having production capacity of 10,000 bbls/day of bitumen and
Phase 2 having an incremental production capacity of 20,000 - 30,000 bbls/day.
    In 2008 we completed our first winter delineation drilling program at the
Kirby project with great success. A total of 58 delineation wells were drilled
including two source water wells and a water disposal well. The results of
this program were significant in that our independent reserves engineers
reported an increase of 170 million barrels to our contingent resource
estimate, an increase of 70% over the 244 million barrels estimated at the
time of purchase. We also confirmed that we have an adequate source of saline
water (non-potable water) for the Kirby Phase 1 project and that we have a
deep reservoir zone capable of handling our disposal water for the life of the
project.
    Set forth below is the "best estimate" of contingent resources
attributable to our Kirby lease as at December 31, 2008 provided by GLJ
Petroleum Consultants Ltd., independent petroleum engineers.

    
    Northern Area Wabiskaw D (Project area)            118 million barrels
    Northern Area McMurray                             191 million barrels
    Central and Southern Areas                         105 million barrels
                                                       -------------------
    Total Kirby Contingent Resource Estimate           414 million barrels
                                                       -------------------
                                                       -------------------
    

    For additional information relating to contingent resource estimates, see
"Information Regarding Disclosure in this News Release and Oil and Gas
Reserves, Resources and Operational Information" at the conclusion of this
news release. As well, for additional information regarding our Kirby Oil
Sands project, see our Annual Information Form for the year ended December 31,
2008, a copy of which will be available on or about March 16th, 2009 on our
SEDAR profile at www.sedar.com and which will also form part of our Form 40-F
for the year ended December 31, 2008 to be filed with the SEC, a copy of which
will be available at www.sec.gov.
    With our experienced team and a successful winter drilling program, we
were able to prepare and submit the development application for Phase 1 to the
regulatory authorities in September.
    Despite the advancements made at Kirby, our 2009 capital program has been
reduced significantly due to the fall in crude oil prices. We will be working
with regulators and our stakeholders in an effort to obtain regulatory
approval by late 2009. Once we have regulatory approval, our Board of
Directors will determine whether to sanction proceeding with the project at
that time. Given the downturn in commodity prices, we have elected to defer
any additional delineation activity this year, but plan to complete a three
dimensional seismic program over 20 sections of our northern lease area. This
will position us for future delineation drilling should we move forward with
Phase 2 of Kirby. We also plan to complete a more detailed geological review
of all potential oil sands zones in our lease which we believe should result
in additional contingent resources being identified.

    2009 PRODUCTION AND CAPITAL SPENDING PLANS

    As previously announced in December 2008, Enerplus is planning a
conservative approach to 2009 with reductions in capital spending and
distributions in light of current commodity prices and capital market
uncertainty. We intend to preserve our financial strength and maintain
flexibility so that we are in a position to take advantage of opportunities to
add quality assets in what we expect will prove to be an attractive
acquisition market.
    As a result of reduced capital spending, we anticipate that our annual
daily production volumes will average 91,000 BOE/day in 2009, a decline of
approximately 5% from 2008. We expect to exit 2009 with production of
approximately 88,000 BOE/day.
    We currently plan to spend $300 million, a decrease of 48% from our 2008
development capital spending levels. Our plans include $240 million of
spending on our Canadian conventional assets, $35 million in the U.S. and $25
million on oil sands. Our program is directed toward high value optimization
and development projects, maintaining the integrity of our existing
infrastructure and investment in new development areas given our desire to add
opportunities in emerging resource plays.
    Approximately 56% of our conventional spending will be directed at
natural gas resource plays with the remainder on oil. Our natural gas program
will be concentrated on shallow gas and tight gas projects which provide an
attractive return with natural gas prices at or better than $5.00/Mcf. Our oil
program is directed primarily at our U.S. Bakken assets and optimization
projects with attractive returns with oil prices at or better than
US$40.00/bbl. Included in our plans is approximately $50 million of spending
on growth-oriented projects in the Montney gas play in northeastern B.C. and
northwestern Alberta, the Bakken oil play in the Williston Basin and a few
other select resource plays. We anticipate drilling several pilot wells to
test reservoir quality and productivity and accumulate additional prospective
lands in key areas. We will also continue to look for acquisition and joint
venture opportunities as a way to advance and accelerate our growth in
resource plays that target tight gas and tight oil.
    This capital spending forecast also includes an estimate of cost savings
that we are expecting as a result of the slowdown in industry activity and
does not reflect any acquisition or divestment activity that may occur as a
normal part of our business. We will review our 2009 capital program and
distributions on an on-going basis throughout the year in the context of
prevailing economic conditions and make adjustments as deemed necessary. In
addition, there is a risk that certain wells could become uneconomic to
produce if current market conditions fail to improve thereby impacting our
production volumes. We expect that up to one third of our capital spending
will occur in the first quarter of 2009 as a result of winter access areas and
the continuation of our ongoing program from 2008.

    
                                  2009               2009               2009
                             Estimated          Estimated          Estimated
                               Average           Drilling            Capital
                      Daily Production           Activity           Spending
    Play Types                (BOE/day)        (Net Wells)             ($MM)
    -------------------------------------------------------------------------
    Shallow Gas & CBM           22,700                226              $  75
    Crude Oil
     Waterfloods                16,200                 12                 45
    Tight Gas                   14,100                 24                 78
    Bakken/Tight Oil             9,900                  4                 42
    Other Conventional
     Oil & Gas                  28,100                  9                 35
    -------------------------------------------------------------------------
    Total Conventional          91,000                275              $ 275
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    Oil Sands                       0                   0                 25
    -------------------------------------------------------------------------
    Total Company              91,000                 275              $ 300
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    


    ACQUISITIONS & DIVESTMENTS

    In 2008 we leveraged our strategic and execution capabilities to execute
two of the most significant transactions in our history. On February 13, 2008
Enerplus acquired Focus Energy Trust for $1.7 billion through an exchange of
trust units and the assumption of debt adding approximately 84 MMBOE of proved
plus probable conventional oil and natural gas reserves and approximately
20,000 BOE/day of production (18,000 BOE/day annualized from the closing date
of February 13, 2008), of which approximately 90% was natural gas. On July 31,
2008, we completed the sale of our 15% working interest in the Joslyn oil
sands lease for net cash proceeds of approximately $502 million. We sold 63.5
million barrels of proved plus probable reserves at a cost of $14.36 per
barrel including future development capital.
    We believe that weak commodity prices and the current downturn in the
economy will create acquisition opportunities. Given our financial strength,
we believe we are in an excellent position to capitalize on these
opportunities to add high quality, growth-oriented assets that will improve
our overall portfolio.

    
    2008 Acquisition & Divestment Summary


                                                         Cost of
                                 Proved                   Proved
                                   plus                     plus    Cost per
                       Cost/   Probable    Estimated    Probable       Daily
    Conventional    Proceeds   Reserves   Production    Reserves      Barrel
     Oil & Gas          ($MM)     (MBOE)    (BOE/day)     ($/BOE) ($/BOE/day)
    -------------------------------------------------------------------------
    Acquisitions,
     net of
     divestments(*) $1,770.0      84,237      20,668    $  21.01    $ 85,640

    -------------------------------------------------------------------------
    Oil Sands
     Divest-
     ments(xx)      $  502.0      63,498           -    $  14.36           -
    -------------------------------------------------------------------------
    (*)  After adjustment for working capital and excluding future
         development capital.
    (xx) Including future development capital
    


    RESERVES

    Enerplus replaced approximately 78% of our produced reserves in 2008,
essentially keeping our total proved plus probable reserves consistent
year-over-year. Through the Focus acquisition and our development activities,
we added over 90 MMBOE of proved plus probable reserves however the sale of
Joslyn and our production more than offset these additions. Our proved
reserves as a percent of total reserves increased by 8% (from 66% at December
31, 2007 to 74% in 2008) given the higher percentage of proved reserves
attributable to the Focus assets whereas the majority of the reserves
associated with the Joslyn lease were in the probable category.
    Overall the results from our development program were disappointing as
fewer reserves were added than expected and we experienced negative revisions
and increased capital costs in some areas. These revisions negatively impacted
our finding and development costs ("F&D") as well as our finding, development
and acquisition costs ("FD&A"). Our conventional FD&A costs per BOE including
future development capital ("FDC") were $29.17 with a recycle ratio of 1.4x
driven primarily by the Focus acquisition (see "Recycle Ratio" below for
additional information on this metric). Our total finding and development
costs on our oil sands assets including FDC were $13.71 per BOE reflecting the
impact of the Joslyn sale and the spending on oil sands which added contingent
resources but do not at this stage of development qualify as reserves.

    
    The following information highlights some of our key reserve findings
    -   We added approximately 20 MMBOE of proved plus probable reserves
        through our conventional development program including:
           -   3.4 MMBOE of proved plus probable reserves added as a result
               of price forecast revisions by our external independent
               reserve evaluators as higher long-term prices extended the
               life and expected reserves in some areas even though the near-
               term price outlook was lower than in 2007.
           -   6 MMBOE of proved plus probable reserves were added on the
               Focus assets, primarily at Shackleton and other minor
               properties.
           -   We added 3 MMBOE of proved plus probable reserves at Sleeping
               Giant. Since acquiring this property in 2005, reserves have
               increased by 48% through the addition of 17.4 MMBOE of proved
               plus probable reserves including the replacement of 13.3 MMBOE
               of produced reserves.
    -   We experienced negative reserve revisions of 13.6 MMBOE;
           -   5.6 MMBOE of which were due to performance issues associated
               with our Verger, Hanna Garden and Medicine Hat South shallow
               gas properties as well as with our Mitsue non-operated oil
               property.
           -   Approximately 5.0 MMBOE of reserves were eliminated from our
               least attractive shallow gas undeveloped locations, the
               majority of which were at our Medicine Hat North and Verger
               shallow gas properties. Lower than expected results combined
               with a reduced capital budget have resulted in a reduction in
               future spending plans on these properties. Given the current
               commodity price environment, we are directing our shallow gas
               spending to other areas that have higher economic returns.
           -   2.5 million BOE of reserves were eliminated at our Mount
               Benjamin property as the operator is not planning on drilling
               in the current commodity price environment.
    -   Approximately $144 million of future development capital was added to
        our reserve report to reflect higher costs. Close to half of this
        amount was associated with increased development costs relating to
        the Shackleton property. We also experienced an increase in
        maintenance capital associated with our Mitsue property.
    -   Given the sale of Joslyn, our Reserve life index and our percentage
        of reserves tied to resource plays fell to 12.1 years and 74%
        respectively. We believe that our RLI remains one of the longest in
        our sector and we expect to continue to increase our percentage of
        resource oriented reserves through our acquisitions and divestments.


                                                                       Proved
                          Proved                                         plus
                Proved Developed  Proved                      Proved Probable
             Developed      Non-  Undeve-                       Plus  Reserve
             Producing Producing   loped   Proved  Probable Probable    Life
              Reserves  Reserves Reserves Reserves Reserves Reserves   Index
    Play Types (MMBOE)   (MMBOE)  (MMBOE)  (MMBOE)  (MMBOE)  (MMBOE)  (years)
    -------------------------------------------------------------------------
    Crude Oil
     Waterfloods  67.1      0.0      6.9     74.0     21.7     95.7     16.2
    Shallow
     Gas & CBM    62.4      0.3     23.7     86.4     35.6    122.0     12.6
    Tight Gas     35.7      2.0      6.7     44.4     17.0     61.4     10.5
    Bakken/
     Tight Oil    27.3      1.4      2.1     30.8      9.8     40.6     11.0
    Other
     Conventional
     Oil & Gas    74.3      0.9      7.7     82.9     29.8    112.7     10.6
    -------------------------------------------------------------------------
    Total
     Company     266.8      4.6     47.1    318.5    113.9    432.4     12.1
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    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. Two external,
independent third party engineering firms were used to evaluate and review our
reserves this year. Sproule Associates Limited, our historical independent
engineering evaluators, evaluated our Canadian conventional reserves.
Netherland, Sewell & Associates, Inc. ("NSA") of Dallas, Texas evaluated the
reserves attributed to our assets in the United States. Sproule evaluated    
93% of the total proved plus probable value (discounted at 10%) of our
Canadian conventional year-end reserves and audited the remaining 7% of the
reserves which were internally evaluated by Enerplus. NSA evaluated 100% of
the reserves in the U.S. and utilized Sproule's forecast price and cost
assumptions as of December 31, 2008 in their evaluations to maintain
consistency among our reserve reporting. In addition to Sproule and NSA, GLJ
Petroleum Consultants Ltd. evaluated the resources on our Kirby oil sands
project as described above.

    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.

    
    2008 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       64,043  26,979        -  91,022   11,416   813,021  237,942
    United
     States      23,159       -        -  23,159       80    33,928   28,894
    -------------------------------------------------------------------------
    Total        87,202  26,979        - 114,181   11,496   846,949  266,836
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    Proved
     developed
     non-producing
    Canada          243       -        -     243      360    15,355    3,162
    United
     States       1,216       -        -   1,216        4     1,532    1,475
    -------------------------------------------------------------------------
    Total         1,459       -        -   1,459      364    16,887    4,637
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    Proved
     undeveloped
    Canada        4,139   6,160        -  10,299    1,163   197,490   44,377
    United
     States       1,753       -        -   1,753       29     5,208    2,650
    -------------------------------------------------------------------------
    Total         5,892   6,160        -  12,052    1,192   202,698   47,027
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    Total
     Proved
    Canada       68,425  33,139        - 101,564   12,939 1,025,866  285,481
    United
     States      26,128       -        -  26,128      113    40,668   33,019
    -------------------------------------------------------------------------
    Total        94,553  33,139        - 127,692   13,052 1,066,534  318,500
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    Probable
    Canada       19,274  12,790        -  32,064    4,714   397,651  103,053
    United
     States       6,867       -        -   6,867       51    23,483   10,832
    -------------------------------------------------------------------------
    Total        26,141  12,790        -  38,931    4,765   421,134  113,885
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    Total
     Proved
     plus
     Probable
    Canada       87,699  45,929        - 133,628   17,653 1,423,517  388,534
    United
     States      32,995       -        -  32,995      164    64,151   43,851
    -------------------------------------------------------------------------
    Total       120,694  45,929        - 166,623   17,817 1,487,668  432,385
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------


    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,
2007 to December 31, 2008.

    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,
     2007        67,386  31,215    8,568 107,169   11,673   829,122  257,029
    -------------------------------------------------------------------------
    Acquisitions  3,585       -        -   3,585    2,714   337,623   62,570
    Divestments       -       -   (8,568) (8,568)       -         -   (8,568)
    Discoveries     114       -        -     114        6       635      226
    Extensions &
     Improved
     Recovery     2,922   1,899        -   4,821      331    24,953    9,311
    Economic
     Factors        604     200        -     804       94     7,961    2,225
    Technical
     Revisions        1   2,879        -   2,880     (186)  (55,062)  (6,484)
    Production   (6,187) (3,054)       -  (9,241)  (1,693) (119,366) (30,828)
    -------------------------------------------------------------------------
    Proved
     Reserves
     at Dec. 31,
     2008        68,425  33,139        - 101,564   12,939 1,025,866  285,481
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------



    -------------------------------------------------------------------------
                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,
     2007        26,637       -        -  26,637      112    36,955   32,908
    -------------------------------------------------------------------------
    Acquisitions      -       -        -       -        -         -        -
    Divestments       -       -        -       -        -         -        -
    Discoveries       -       -        -       -        -         -        -
    Extensions &
     Improved
     Recovery     2,429       -        -   2,429       16     3,940    3,102
    Economic
     Factors          -       -        -       -        -         -        -
    Technical
     Revisions      465       -        -     465       (2)    4,433    1,202
    Production   (3,403)      -        -  (3,403)     (13)   (4,660)  (4,193)
    -------------------------------------------------------------------------
    Proved
     Reserves
     at Dec. 31,
     2008        26,128       -        -  26,128      113    40,668   33,019
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------



    -------------------------------------------------------------------------
                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,
     2007        94,023  31,215    8,568 133,806   11,785   866,077  289,937
    -------------------------------------------------------------------------
    Acquisitions  3,585       -        -   3,585    2,714   337,623   62,570
    Divestments       -       -   (8,568) (8,568)       -         -   (8,568)
    Discoveries     114       -        -     114        6       635      226
    Extensions &
     Improved
     Recovery     5,351   1,899        -   7,250      347    28,893   12,413
    Economic
     Factors        604     200        -     804       94     7,961    2,225
    Technical
     Revisions      466   2,879        -   3,345     (188)  (50,629)  (5,282)
    Production   (9,590) (3,054)       - (12,644)  (1,706) (124,026) (35,021)
    -------------------------------------------------------------------------
    Proved
     Reserves
     at Dec. 31,
     2008        94,553  33,139        - 127,692   13,052 1,066,534  318,500
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------



    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,
     2007        17,837  10,948   54,930  83,715    3,797   308,276  138,891
    -------------------------------------------------------------------------
    Acquisitions    944       -        -     944      831   119,352   21,667
    Divestments       -       -  (54,930)(54,930)       -         -  (54,930)
    Discoveries      37       -        -      37        1       212       73
    Extensions &
     Improved
     Recovery     1,072     486        -   1,558      168     7,976    3,055
    Economic
     Factors        303     171        -     474       32     4,070    1,184
    Technical
     Revisions     (919)  1,185        -     266     (115)  (42,235)  (6,887)
    Production        -       -        -       -        -         -        -
    -------------------------------------------------------------------------
    Probable
     Reserves
     at Dec. 31,
     2008        19,274  12,790        -  32,064    4,714   397,651  103,053
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------



    -------------------------------------------------------------------------
                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,
     2007         6,719       -        -   6,719       30    27,938   11,406
    -------------------------------------------------------------------------
    Acquisitions      -       -        -       -        -         -        -
    Divestments       -       -        -       -        -         -        -
    Discoveries       -       -        -       -        -         -        -
    Extensions &
     Improved
     Recovery       521       -        -     521       11     1,952      857
    Economic
     Factors          -       -        -       -        -         -        -
    Technical
     Revisions     (373)      -        -    (373)      10    (6,407)  (1,431)
    Production        -       -        -       -        -         -        -
    -------------------------------------------------------------------------
    Probable
     Reserves
     at Dec. 31,
     2008         6,867       -        -   6,867       51    23,483   10,832
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------



    -------------------------------------------------------------------------
                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,
     2007        24,556  10,948   54,930  90,434    3,827   336,214  150,297
    -------------------------------------------------------------------------
    Acquisitions    944       -        -     944      831   119,352   21,667
    Divestments       -       -  (54,930)(54,930)       -         -  (54,930)
    Discoveries      37       -        -      37        1       212       73
    Extensions &
     Improved
     Recovery     1,593     486        -   2,079      179     9,928    3,912
    Economic
     Factors        303     171        -     474       32     4,070    1,184
    Technical
     Revisions   (1,292)  1,185        -    (107)    (105)  (48,642)  (8,318)
    Production        -       -        -       -        -         -        -
    -------------------------------------------------------------------------
    Probable
     Reserves
     at Dec. 31,
     2008        26,141  12,790        -  38,931    4,765   421,134  113,885
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------



    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,
     2007        85,223  42,163   63,498 190,884   15,470 1,137,398  395,920
    -------------------------------------------------------------------------
    Acquisitions  4,529       -        -   4,529    3,545   456,975   84,237
    Divestments       -       -  (63,498)(63,498)       -         -  (63,498)
    Discoveries     151       -        -     151        7       847      299
    Extensions &
     Improved
     Recovery     3,994   2,385        -   6,379      499    32,929   12,366
    Economic
     Factors        907     371        -   1,278      126    12,031    3,409
    Technical
     Revisions     (918)  4,064        -   3,146     (301)  (97,297) (13,371)
    Production   (6,187) (3,054)       -  (9,241)  (1,693) (119,366) (30,828)
    -------------------------------------------------------------------------
    Proved Plus
     Probable
     Reserves at
     Dec. 31,
     2008        87,699  45,929        - 133,628   17,653 1,423,517  388,534
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------



    -------------------------------------------------------------------------
                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,
     2007        33,356       -        -  33,356      142    64,893   44,314
    -------------------------------------------------------------------------
    Acquisitions      -       -        -       -        -         -        -
    Divestments       -       -        -       -        -         -        -
    Discoveries       -       -        -       -        -         -        -
    Extensions &
     Improved
     Recovery     2,950       -        -   2,950       27     5,892    3,959
    Economic
     Factors          -       -        -       -        -         -        -
    Technical
     Revisions       92       -        -      92        8    (1,974)    (229)
    Production   (3,403)      -        -  (3,403)     (13)   (4,660)  (4,193)
    -------------------------------------------------------------------------
    Proved Plus
     Probable
     Reserves at
     Dec. 31,
     2008        32,995       -        -  32,995      164    64,151   43,851
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------



    -------------------------------------------------------------------------
                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,
     2007       118,579  42,163   63,498 224,240   15,612 1,202,291  440,234
    -------------------------------------------------------------------------
    Acquisitions  4,529       -        -   4,529    3,545   456,975   84,237
    Divestments       -       -  (63,498)(63,498)       -         -  (63,498)
    Discoveries     151       -        -     151        7       847      299
    Extensions &
     Improved
     Recovery     6,944   2,385        -   9,329      526    38,821   16,325
    Economic
     Factors        907     371        -   1,278      126    12,031    3,409
    Technical
     Revisions     (826)  4,064        -   3,238     (293)  (99,271) (13,600)
    Production   (9,590) (3,054)       - (12,644)  (1,706) (124,026) (35,021)
    -------------------------------------------------------------------------
    Proved Plus
     Probable
     Reserves at
     Dec. 31,
     2008       120,694  45,929        - 166,623   17,817 1,487,668  432,385
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    


    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, 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 estimated net present value of all future net revenues at December
31, 2008 was based upon forecast crude oil and natural gas pricing assumptions
prepared by Sproule as of December 31, 2008. These prices were applied to the
reserves evaluated by Sproule and NSA. The base reference prices and exchange
rates used by Sproule are detailed below:

    
    Sproule December 31, 2008 - Forecast Price Assumptions
    -------------------------------------------------------------------------
                                                         Natural
                                                             Gas
                                                          30 day
                                   Hardisty     Henry       spot
                WTI       Light       Heavy       Hub       @
              crude    crude(1) 12(degrees)     Price       AECO   Exchange
                oil    Edmonton         API      US$/      CDN$/       Rate
            US$/bbl    CDN$/bbl    CDN$/bbl     MMbtu      MMbtu    US$/CDN$
    -------------------------------------------------------------------------
    2009      53.73       65.35       47.05      6.30       6.82        0.80
    2010      63.41       72.78       54.58      7.32       7.56        0.85
    2011      69.53       79.95       59.96      7.56       7.84        0.85
    2012      79.59       86.57       67.53      8.49       8.38        0.90
    2013      92.01       94.97       74.08      9.74       9.20        0.95
    -------------------------------------------------------------------------
    Thereafter  (xx)       (xx)         (xx)      (xx)       (xx)       0.95
    -------------------------------------------------------------------------
    (1)   Edmonton refinery postings for 40 degree API, 0.4% sulphur content
          crude
    (xx)  Escalation varies until 2019 and increases at an annual rate of 2%
          thereafter


    Net Present Value of Future Production Revenue - Forecast Prices and
    Costs (Before Tax) At December 31, 2008

    Conventional Reserves ($ Millions,
     discounted at)                          0%        5%       10%       15%
    -------------------------------------------------------------------------
    Proved developed producing         $10,366    $6,731    $5,044    $4,069
    Proved developed non-producing         173       120        89        70
    Proved undeveloped                   1,177       704       438       272
    -------------------------------------------------------------------------
    Total Proved                       $11,716    $7,555    $5,571    $4,411
    Probable                             5,269     2,362     1,352       890
    -------------------------------------------------------------------------
    Total Proved Plus Probable
     Conventional Reserves             $16,985    $9,917    $6,923    $5,301
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------


    Net Present Value of Future Production Revenue - Forecast Prices and
    Costs (After Tax)
    At December 31, 2008

    Conventional Reserves ($ Millions,
     discounted at)                          0%        5%       10%       15%
    -------------------------------------------------------------------------
    Proved developed producing          $8,573    $5,748    $4,403    $3,610
    Proved developed non-producing         127        90        67        53
    Proved undeveloped                     952       550       332       196
    -------------------------------------------------------------------------
    Total Proved                        $9,652    $6,388    $4,802    $3,859
    Probable                             3,896     1,755     1,008       666
    -------------------------------------------------------------------------
    Total Proved Plus Probable
     Conventional Reserves             $13,548    $8,143    $5,810    $4,525
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    


    NET ASSET VALUE

    Enerplus' estimated net asset value is measured with reference to the
estimated net present value of all future net revenue from our reserves,
before taxes, as estimated by our independent reserve engineers (Sproule 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 23 year history of replacing production
through acquisitions and development.
    In addition, we have included in our net asset value calculation
provisions for our oil sands portfolio. Given the significant decrease in oil
prices and the lack of comparable transactions of oil sands assets, we are
showing our costs (acquisition costs and any capital investments made to date)
in the net asset value table and have not attempted to determine a current
fair market value for our oil sands assets at this time.

    
    Forecast Prices and Costs at December 31, 2008

    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     $16,985    $9,917    $6,923    $5,301
    Undeveloped acreage(1)                  85        85        85        85
    Asset retirement obligations          (343)     (195)      (74)      (43)
    Long-term debt (net of cash)          (657)     (657)     (657)     (657)
    Net Working Capital excluding
     deferred financial asset,
     distributions to unitholders,
     deferred credits, and
     future income tax                    (106)     (106)     (106)     (106)
    -------------------------------------------------------------------------
    Net Asset Value of
     Conventional Assets               $15,964    $9,044    $6,171    $4,580
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    Net Asset Value per Trust Unit
     - Conventional Assets(2)(3)        $96.41    $54.62    $37.27    $27.66
    -------------------------------------------------------------------------

    Oil Sands (at cost)
    Kirby Oil Sands Lease(4)              $246      $246      $246      $246
    Laricina Equity Investment(5)           25        25        25        25
    Undeveloped Oil Sands acreage(6)        11        11        11        11
    -------------------------------------------------------------------------
    Net Asset Value of
     Oil Sands Assets                     $282      $282      $282      $282
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    Net Asset Value per Trust Unit
     - Oil Sands                         $1.70     $1.70     $1.70     $1.70

    Total Net Asset Value
     per Trust Unit(2)                  $98.11    $56.32    $38.97    $29.36
    -------------------------------------------------------------------------
    (1) Conventional undeveloped acreage valued at $100 per acre except
        Alberta which was valued at $50 per acre
    (2) Asset retirement obligations ("ARO") do not equal the amount on the
        balance sheet ($207.4 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
    (3) Based on 165,590,000 trust units outstanding at December 31, 2008
    (4) Kirby valuation represents $203.1 million purchase price plus capital
        spending of $42.9 million since acquisition
    (5) Laricina equity investment represents the carrying value of our 4.3
        million shares
    (6) Undeveloped oil sands acreage valued at cost of land acquisitions and
        development capital spent on those lands
    


    RESERVE LIFE INDEX ("RLI")

    Enerplus continues to maintain one of the longest reserve life indices in
the sector. In 2008 our proved plus probable RLI decreased primarily due to
the sale of the Joslyn oil sands interest and the removal of proved and
probable reserves associated with that lease. At this time, we have only
contingent resources and no reserves associated with the Kirby oil sand
project and therefore our RLI solely represents our conventional oil and gas
assets. Our proved reserve life index declined slightly in 2008 as we did not
replace all of the reserves produced during the year.

    
    Conventional Reserves
    (as at December 31)         2008    2007    2006    2005    2004    2003
    -------------------------------------------------------------------------

    Proved                       9.4    10.0     9.8     9.6    10.1    10.6
    Proved plus Probable        12.1    12.8    12.2    12.0    12.4    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")
    

    F&D and FD&A costs have historically been calculated both including and
excluding future development capital. F&D and FD&A costs 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.
    Our F&D and FD&A results were significantly influenced by our acquisition
and divestment activity during the year as well as a number of other factors
detailed above. When reviewing these numbers in light of these factors, care
must be taken before drawing conclusions as to the effectiveness of current
spending and the full-cycle economics associated with the recent and ongoing
capital investment program.
    Our total spending on our conventional asset base delivered a FD&A cost
of $29.17/BOE on a proved plus probable basis including future development
capital ("FDC"). Our three-year conventional proved plus probable FD&A was
$27.13/BOE including changes in future development capital.
    Through our conventional capital development program, we added 20.0
million BOE of proved plus probable reserves. We also experienced negative
technical revisions of 13.6 million proved plus probable BOE. Therefore on a
net basis, our capital development program added only 6.4 million BOE of
proved plus probable reserves resulting in F&D costs of $82.34/BOE on our
conventional oil and gas assets.
    Our oil sands activity consisted of the disposition of the Joslyn oil
sands mining lease and capital development at our Kirby SAGD lease. We sold
63.5 million barrels of reserves (87% probable) associated with the Joslyn
lease and while the spending on our Kirby oil sands property did not add
production or reserves in 2008, it has advanced the Phase I project. As
development of the Kirby lease moves forward, we would expect to move
contingent resources into the probable reserve category. Key events triggering
this move would be regulatory approval of the Phase I project and affirmative
sanctioning by our Board of Directors. Our proved plus probable FD&A cost on
our oil sands assets was $13.71/BOE including FDC.


    
    F&D and FD&A Costs (Including
     Future Development Capital)
    ($ millions except for
     per BOE amounts)                       2008          2007          2006
    -------------------------------------------------------------------------
    Proved Reserves

    Conventional  Oil & Gas
    -------------------------------------------------------------------------
    Finding & Development Costs
    Capital Expenditures                  $526.5        $348.3        $452.1
    Net change in Future
     Development Capital                  $(27.9)        $39.3         $22.3
    Gross Company Reserve
     additions (MMBOE)                       9.6          17.9          16.1
    F&D costs ($/BOE)                     $51.94        $21.65        $29.47
    Three year average
     F&D cost ($/BOE)(1)                  $31.21        $20.62        $15.54

    Finding, Development
     & Acquisition Costs
    Capital Expenditures
     and net acquisitions               $2,296.5        $409.8        $502.0
    Net change in Future
     Developments Capital                 $252.5         $48.5          $8.0
    Gross Company Reserve
     additions (MMBOE)                      72.2          20.4          18.6
    FD&A costs ($/BOE)                    $35.30        $22.47        $27.42
    Three year average FD&A
     costs ($/BOE)(1)                     $31.63        $22.93        $19.80

    Oil Sands
    -------------------------------------------------------------------------
    Finding & Development Costs
    Capital Expenditures                   $51.2         $38.9         $39.1
    Net change in Future
     Development Capital                      $-         $(1.7)       $(10.8)
    Gross Company Reserve
     additions (MMBOE)                       0.0          (0.2)         (0.1)
    F&D costs ($/BOE)                        n/a      $(186.00)     $(283.00)
    Three year average F&D
     cost ($/BOE)(1)                    $(389.00)       $15.58        $12.17

    Finding, Development &
     Acquisition Costs
    Capital Expenditures
     and net acquisitions                $(450.8)       $242.0         $19.4
    Net change in Future
     Development Capital                  $(29.3)        $(1.7)       $(13.6)
    Gross Company Reserve
     additions (MMBOE)                      (8.6)         (0.2)         (0.7)
    FD&A costs ($/BOE)                    $55.83    $(1,201.50)       $(8.29)
    Three year average FD&A
     costs ($/BOE)(1)                     $24.63        $37.66        $10.44



    Proved Plus Probable Reserves
    ($ millions except for
     per BOE amounts)                       2008          2007          2006

    Conventional Oil & Gas
    -------------------------------------------------------------------------
    Finding & Development Costs
    Capital Expenditures                  $526.5        $348.3        $452.1
    Net change in Future
     Development Capital                    $0.5        $(30.7)        $50.7
    Gross Company Reserve
     additions (MMBOE)                       6.4          15.9          18.3
    F&D costs ($/BOE)                     $82.34        $19.97        $27.48
    Three year average F&D
     cost ($/BOE)(1)                      $33.19        $18.85        $20.22

    Finding, Development &
     Acquisition Costs
    Capital Expenditures
     and net acquisitions               $2,296.5        $409.8        $502.0
    Net change in Future
     Development Capital                  $348.8        $(12.0)        $54.4
    Gross Company Reserve
     additions (MMBOE)                      90.7          20.1          21.9
    FD&A costs ($/BOE)                    $29.17        $19.79        $25.41
    Three year average FD&A
     costs ($/BOE)(1)                     $27.13        $19.57        $18.10

    Oil Sands
    -------------------------------------------------------------------------
    Finding & Development Costs
    Capital Expenditures                   $51.2         $38.9         $39.1
    Net change in Future
     Development Capital                      $-        $105.0         $34.3
    Gross Company Reserve
     additions (MMBOE)                       0.0           6.8           6.9
    F&D costs ($/BOE)                        n/a        $21.16        $10.64
    Three year average F&D
     cost ($/BOE)(1)                      $19.60        $14.86         $6.91

    Finding, Development &
     Acquisition Costs
    Capital Expenditures
     and net acquisitions                $(450.8)       $242.0         $19.4
    Net change in Future
     Development Capital                 $(420.1)       $105.0         $15.6
    Gross Company Reserve
     additions (MMBOE)                     (63.5)          6.8           3.6
    FD&A costs ($/BOE)(1)                 $13.71        $51.03         $9.72
    Three year average FD&A
     costs ($/BOE)(1)                      $9.21        $28.39         $6.63
    -------------------------------------------------------------------------
     (1) Calculated over a three year period.



    F&D and FD&A Costs
     (Excluding Future
     Development Capital)
    ($ millions except for
     per  BOE amounts)                      2008          2007          2006
    -------------------------------------------------------------------------
    Proved Reserves

    Conventional Oil & Gas
    -------------------------------------------------------------------------
    Finding & Development Costs
    Capital Expenditures                  $526.5        $348.3        $452.1
    Gross Company Reserve
     additions (MMBOE)                       9.6          17.9          16.1
    F&D Cost ($/BOE)                      $54.84        $19.46        $28.08
    Three year average F&D
     costs ($/BOE)(1)                     $30.43        $18.09        $13.17

    Finding, Development &
     Acquisition Costs
    Capital Expenditures and
     net acquisitions                   $2,296.5        $409.8        $502.0
    Gross Company Reserve
     additions (MMBOE)                      72.2          20.4          18.6
    FD&A costs ($/BOE)                    $31.81        $20.09        $26.99
    Three year average FD&A
     costs ($/BOE)(1)                     $28.85        $20.33        $17.55

    Oil Sands
    -------------------------------------------------------------------------
    Finding & Development Costs
    Capital Expenditures                   $51.2         $38.9         $39.1
    Gross Company Reserve
     additions (MMBOE)                       0.0          (0.2)         (0.1)
    F&D Cost ($/BOE)                         n/a      $(194.50)     $(391.00)
    Three year average F&D
     costs ($/BOE)(1)                   $(430.67)       $12.09         $8.57

    Finding, Development &
     Acquisition Costs
    Capital Expenditures and
     net acquisitions                    $(450.8)       $242.0         $19.4
    Gross Company Reserve
     additions (MMBOE)                      (8.6)         (0.2)         (0.7)
    FD&A costs ($/BOE)                    $52.42    $(1,210.00)      $(27.71)
    Three year average FD&A
     costs ($/BOE)(1)                     $19.94        $34.26         $6.92


    Proved Plus Probable Reserves
    ($ millions except
     for per BOE amounts)                   2008          2007          2006

    Conventional  Oil & Gas
    -------------------------------------------------------------------------
    Finding & Development Costs
    Capital Expenditures                  $526.5        $348.3        $452.1
    Gross Company Reserve
     additions (MMBOE)                       6.4          15.9          18.3
    F&D Cost ($/BOE)                      $82.27        $21.91        $24.70
    Three year average F&D
     costs ($/BOE)(1)                     $32.68        $17.16        $16.66

    Finding, Development &
     Acquisition Costs
    Capital Expenditures and
     net acquisitions                   $2,296.5        $409.8        $502.0
    Gross Company Reserve
     additions (MMBOE)                      90.7          20.1          21.9
    FD&A costs ($/BOE)                    $25.32        $20.39        $22.92
    Three year average FD&A
     costs ($/BOE)(1)                     $24.18        $17.36        $15.55

    Oil Sands
    -------------------------------------------------------------------------
    Finding & Development Costs
    Capital Expenditures                   $51.2         $38.9         $39.1
    Gross Company Reserve
     additions (MMBOE)                       0.0           6.8           6.9
    F&D Cost ($/BOE)                         n/a         $5.72         $5.67
    Three year average F&D
     costs ($/BOE)(1)                      $9.43         $5.82         $1.34

    Finding, Development &
     Acquisition Costs
    Capital Expenditures and
     net acquisitions                    $(450.8)       $242.0         $19.4
    Gross Company Reserve
     additions (MMBOE)                     (63.5)          6.8           3.6
    FD&A costs ($/BOE)                     $7.10        $35.59         $5.39
    Three year average FD&A
     costs ($/BOE)(1)                      $3.57        $18.65         $1.07
    -------------------------------------------------------------------------
     (1) Calculated over a three year period.
    


    RECYCLE RATIO

    Recycle ratio is calculated as operating income (revenues less royalties
and operating costs) 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
currently has no operating income or proved plus probable reserves.

    
    Proved Plus Probable Reserves                 2008       2007       2006
    -------------------------------------------------------------------------
    Conventional Recycle Ratio                    1.4x       1.6x       1.2x
    Conventional 3-Year Average                   1.4x       1.5x       1.4x
    -------------------------------------------------------------------------
    Based on 2008 netback of $41.07
    


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

    The following discussion and analysis of financial results is dated
February 25, 2009 and is to be read in conjunction with the audited
consolidated financial statements as at and for the years ended December 31,
2008 and 2007. 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.

    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 are measures prescribed by
GAAP 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.

    2008 OVERVIEW

    We began 2008 with the largest acquisition in our 23 year history. Focus
Energy Trust ("Focus") was acquired on February 13, 2008 for approximately
$1.7 billion and added approximately 18,000 BOE/day of average daily
production to our 2008 operating results. Commodity prices started the year
off strong and continued to rise throughout the first half of the year,
ultimately peaking in July. Higher commodity prices combined with additional
production volumes from Focus resulted in our cash flow from operating
activities totaling $1,262.8 million, representing a 45% increase from 2007.
    On July 31, 2008, as commodity prices began to decline, we reduced our
exposure to oil sands and successfully disposed of our interest in the Joslyn
oil sands lease ("Joslyn") for net proceeds of $502.0 million. The proceeds
were used to pay down debt and, as a result, we believe that we have one of
the strongest balance sheets in the sector with a trailing twelve month
debt-to-cash flow ratio of 0.5x at December 31, 2008. We believe we are in a
strong position given the current market conditions and expect to enhance our
asset base with opportunistic acquisitions.
    In addition to our successful acquisition and disposition activities, we
completed the largest development capital spending program in our history with
total spending of approximately $577.7 million, resulting in the drilling of
643 net wells with a 99% success rate.
    The sharp decline in commodity prices in the fourth quarter of 2008 has
focused our priorities on preserving our balance sheet strength and, as a
result, we have decreased our 2009 development capital program along with our
monthly distributions. We intend to manage our capital spending and
distributions to unitholders at a level which will minimize increases in our
debt levels outside of any acquisition activity. We have decided to limit
spending on our current properties as we expect the acquisition market will
provide the best opportunity to add quality reserves at a reasonable cost in
today's credit constrained environment. As a result of our reduced development
capital spending, we expect annual production to average 91,000 BOE/day with
an exit production rate of 88,000 BOE/day in 2009.

    
    RESULTS OF OPERATIONS

    Production
    

    Production during 2008 averaged 95,687 BOE/day, essentially in line with
our guidance of 96,000 BOE/day and 16% higher than 82,319 BOE/day in 2007. The
increase compared to 2007 was primarily due to the additional production
volumes from the Focus assets which were purchased on February 13, 2008.
Although our annual average production approximated our guidance we did
encounter challenges with production throughout the year. We experienced
unplanned downtime at several non-operated facilities along with setbacks
executing our capital program due to weather and tie in delays while we
assessed alternative well completion techniques.
    Average production during the year was weighted 59% to natural gas and
41% to liquids on a BOE basis. Average production volumes for the years ended
December 31, 2008 and 2007 are outlined below:

    
    Daily Production Volumes                      2008      2007    % Change
    -------------------------------------------------------------------------
    Natural gas (Mcf/day)                      338,869   262,254          29%
    Crude oil (bbls/day)                        34,581    34,506           -%
    Natural gas liquids (bbls/day)               4,627     4,104          13%
    Total daily sales (BOE/day)                 95,687    82,319          16%
    -------------------------------------------------------------------------
    

    During the month of December we experienced production interruptions of
approximately 1,600 BOE/day on two of our properties. We experienced an
interruption of 1,100 BOE/day related to a labour strike at a non-operated
facility which processes our Tommy Lakes production and another interruption
of 500 BOE/day related to unscheduled downtime at Bantry. As a result, our
December average daily production was approximately 96,400 BOE/day. Both of
these issues were resolved and production was restored resulting in an
adjusted exit rate of approximately 98,000 BOE/day which was 500 BOE/day less
than our guidance of 98,500 BOE/day.
    Considering our reduced development capital program in 2009, we expect
2009 annual production volumes to average 91,000 BOE/day, weighted 58% to
natural gas and 42% to liquids. We expect to exit 2009 with production of
approximately 88,000 BOE/day. This guidance does not contemplate any potential
acquisitions or dispositions.

    Pricing

    The prices received for our natural gas and crude oil production directly
impact our earnings, cash flow and financial condition. The following table
compares our average selling prices for 2008 with those of 2007. It also
compares the benchmark price indices for the same periods.

    
    Average Selling Price(1)                      2008       2007   % Change
    -------------------------------------------------------------------------
    Natural gas (per Mcf)                     $   8.17   $   6.45        27%
    Crude oil (per bbl)                       $  91.31   $  65.11        40%
    Natural gas liquids (per bbl)             $  68.93   $  51.35        34%
    Per BOE                                   $  65.79   $  50.48        30%
    -------------------------------------------------------------------------
    (1) Net of oil and gas transportation costs, but before the effects of
        commodity derivative instruments


    Average Benchmark Pricing                     2008       2007   % Change
    -------------------------------------------------------------------------
    AECO natural gas - monthly index
     (CDN$/Mcf)                               $   8.13   $   6.61        23%
    AECO natural gas - daily index (CDN$/Mcf) $   8.14   $   6.45        26%
    NYMEX natural gas - monthly NX3 index
     (US$/Mcf)                                $   8.93   $   6.92        29%
    NYMEX natural gas - monthly NX3 index:
     CDN$ equivalent (CDN$/Mcf)               $   9.50   $   7.44        28%
    WTI crude oil (US$/bbl)                   $  99.65   $  72.34        38%
    WTI crude oil: CDN$ equivalent (CDN$/bbl) $ 106.01   $  77.78        36%
    CDN$/US$ exchange rate                        0.94       0.93         1%
    -------------------------------------------------------------------------
    

    Natural Gas

    Natural gas prices in Alberta were strong through the first half of 2008,
opening at $6.97/Mcf at AECO and rising steadily to a high of $11.82/Mcf by
the end of June. The strength in natural gas prices was partly fueled by the
crude oil market which hit record levels by mid-year. Also, the key consuming
regions of the U.S. experienced cold weather from late January to March 2008
which decreased inventories to the lowest levels since 2004. Early forecasts
for an active hurricane season and the expectation for supply disruptions led
to further price strength at the start of summer combined with demand in Asia
and Europe for liquefied natural gas ("LNG") which diverted the majority of
LNG supply away from North America, ultimately helped keep prices high.
    By mid-year the market started to adjust to the impact of the increased
U.S. shale gas production that had been brought on-stream throughout the year
and gas inventories started to rise despite a warmer than average summer. The
impact of the global economic crisis began to take its toll on demand as
supply additions continued to overwhelm the shrinking demand for gas. Prices
declined to a low of $5.79/Mcf at AECO at the end of September and closed the
year at $6.34/Mcf.
    During 2008 we sold approximately 84% of our natural gas on the AECO
index split evenly between the daily and monthly indices and the remaining 16%
against the monthly NYMEX index. During 2008 we sold our natural gas for an
average price of $8.17/Mcf (net of transportation costs), an increase of 27%
from $6.45/Mcf realized in 2007. This increase is comparable to the price
increases realized in the AECO daily and monthly indices and the NYMEX monthly
index.

    Crude Oil

    Crude prices were strong through the first two quarters of 2008 reaching
a peak of US$147.27/bbl during July. Prices then dropped significantly,
approximately 77% through the second half of the year. The global economic
crisis and reduced access to credit began to weaken gasoline and distillate
demand. Inventories began to grow and the general bearish mood in the market,
which was supported by continued weak economic data, pushed prices down
reaching a low for the year in mid-December at US$33.87/bbl.
    Our crude oil production in 2008 was weighted 76% light/medium and 24%
heavy. The average price received for our crude oil (net of transportation
costs) was $91.31/bbl during 2008, a 40% increase over 2007. The West Texas
Intermediate ("WTI") crude oil benchmark price, after adjusting for the change
in the U.S. dollar exchange rate, increased 36% year-over-year. With gasoline
demand falling and heavy oil refining capacity increasing, the demand for
heavy oil increased. This fundamental change created a narrowing of the heavy
differentials which benefited our heavy crude pricing in comparison to the
benchmark.

    Foreign Exchange

    During the first half of the year the Canadian dollar fluctuated around
par relative to the U.S. dollar, but by the third quarter it started to weaken
along with crude oil prices and by the fourth quarter it dropped dramatically
reaching a low CDN$/US$ exchange rate of 0.77. As most of our crude oil and a
portion of our natural gas sales are priced in reference to U.S. dollar
denominated benchmarks, this movement in the exchange rate during the latter
part of the year increased the Canadian dollar prices we realized.

    Price Risk Management

    We continue to adjust our price risk management program with
consideration given to our overall financial position together with the
economics of our development capital program and potential acquisitions.
Consideration is also given to the upfront and potential costs of our risk
management program as we seek to limit our exposure to price downturns. Hedge
positions for any given term are transacted across a range of prices and time.
    Our existing commodity contracts are designed to protect a portion of our
natural gas sales through October 2010 and a portion of our crude oil sales
through December 2009. We have also hedged a portion of our electricity
consumption through December 2010 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.
    The following is a summary of the financial contracts in place at
February 18, 2009 expressed as a percentage of our forecasted net production
volumes:

    
                                      Natural Gas                  Crude Oil
                                      (CDN$/Mcf)                   (US$/bbl)
                      -------------------------------------------- ----------
                       January 1,   April 1, November 1,  April 1, January 1,
                          2009 -     2009 -      2009 -    2010 -     2009 -
                           March    October       March   October   December
                        31, 2009   31, 2009    31, 2010  31, 2010   31, 2009
    -------------------------------------------------------------------------
    Purchased Puts
     (floor prices)       $ 9.20     $ 8.30      $ 8.99    $    -     $98.08
    %                        21%        18%          8%         -        24%

    Sold Puts (limiting
     downside protection) $ 6.93     $ 7.85      $    -    $    -     $66.17
    %                        14%         4%           -         -        10%

    Swaps (fixed price)   $ 9.35     $ 7.41      $ 7.33    $ 7.33    $100.05
    %                         3%        11%          9%        9%         2%

    Sold Calls (capped
     price)               $11.60     $    -      $12.13    $    -     $92.98
    %                        10%          -          2%         -        11%
    ------------------------------------------------------------------------
    Based on weighted average price (before premiums), estimated average
    annual production of 91,000 BOE/day, net of royalties and assuming a 18%
    royalty rate.
    

    Accounting for Price Risk Management

    For the first three quarters of 2008 commodity prices were generally
above our swap and sold call positions, resulting in cash losses of $135.0
million on our natural gas and crude oil contracts for the period ending
September 30, 2008. In the fourth quarter of 2008 commodity prices declined
significantly to levels below our swap and purchased put positions resulting
in cash gains of $31.8 million on our natural gas and crude oil contracts. In
aggregate we recorded net cash losses of $20.1 million on our natural gas
contracts and $83.1 million on our crude oil contracts in 2008. In comparison,
during 2007 our commodity price risk management program resulted in cash gains
of $23.6 million on our natural gas contracts and cash losses of $10.0 million
on our crude oil contracts.
    At December 31, 2008 the fair value of our natural gas and crude oil
derivative instruments, net of premiums, represented a gain of $24.3 million
and $96.6 million respectively. These gains are recorded as current deferred
financial assets on our balance sheet. In comparison, at December 31, 2007 the
fair value of our natural gas derivative instruments, net of premiums,
represented a gain of $9.7 million which was recorded on our balance sheet as
a deferred financial asset and the fair value of our crude oil derivative
instruments, net of premiums, represented a loss of $52.5 million which was
recorded on our balance sheet as a deferred financial credit. The change in
the fair value of our financial contracts during the year, after adjusting for
the Focus derivative instruments, resulted in unrealized gains of $16.2
million for natural gas and $153.4 million for crude oil. As the forward
markets for natural gas and crude oil fluctuate, new contracts are executed
and existing contracts are realized, the changes in fair value will be
reflected as a non-cash charge or non-cash gain in earnings. See Note 12 for
details.

    The following table summarizes the effects of our financial contracts on
income for the years ended December 31, 2008 and 2007.

    
    Risk Management Costs
    ($ millions, except per
     unit amounts)                     2008                    2007
    -------------------------------------------------------------------------
    Cash (losses)/gains:
      Natural gas             $   (20.1) $(0.16)/Mcf  $    23.6  $  0.25/Mcf
      Crude oil                   (83.1) $(6.57)/bbl      (10.0) $(0.79)/bbl
                              ----------              ----------
    Total cash (losses)/gains $  (103.2) $(2.94)/BOE  $    13.6  $  0.45/BOE

    Non-cash gains/(losses)
     on financial contracts:
      Change in fair value
       - natural gas          $    16.2  $  0.13/Mcf  $    (3.0) $(0.03)/Mcf
      Change in fair value
       - crude oil                153.4  $ 12.12/bbl      (63.4) $(5.03)/bbl
                              ----------              ----------
    Total non-cash
     gains/(losses)           $   169.6  $  4.84/BOE  $   (66.4) $(2.21)/BOE

                              ----------              ----------
    Total gains/(losses)      $    66.4  $  1.90/BOE  $   (52.8) $(1.76)/BOE
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    Cash Flow Sensitivity

    The sensitivities below reflect all commodity contracts as listed in Note
12 and are based on forward markets as at February 18, 2009. 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.

                                                               Effect on 2009
                                                                Cash Flow per
    Sensitivity Table                                           Trust Unit(1)
    -------------------------------------------------------------------------
    Change of $0.50 per Mcf in the price of AECO natural gas           $0.20
    Change of US$5.00 per barrel in the price of WTI crude oil         $0.32
    Change of 1,000 BOE/day in production                              $0.06
    Change of $0.01 in the US$/CDN$ exchange rate                      $0.08
    Change of 1% in interest rate                                      $0.04
    -------------------------------------------------------------------------
    (1) Assumes constant working capital and 165,590,000 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 in 2008 were $2,304.2 million
($2,331.9 million, net of $27.7 million of transportation costs), an increase
of 52% or $787.1 million compared to $1,517.1 million ($1,539.2 million, net
of $22.1 million of transportation costs) during 2007. Higher commodity prices
and production resulting primarily from our Focus acquisition helped to
increase revenues significantly over 2007 levels.

    
    Analysis of Sales                                    Natural
     Revenue(1) ($ millions)   Crude oil        NGLs         Gas       Total
    -------------------------------------------------------------------------
    2007 Sales Revenue         $   820.1   $    76.9   $   620.1   $ 1,517.1
    Price variance(1)              331.6        29.7       221.2       582.5
    Volume variance                  4.0        10.1       190.5       204.6
    -------------------------------------------------------------------------
    2008 Sales Revenue         $ 1,155.7   $   116.7   $ 1,031.8   $ 2,304.2
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    (1) Net of oil and gas transportation costs, but before the effects of
        commodity derivative instruments.
    

    Other Income

    Other income during 2008 was $8.5 million compared to $15.0 million in
2007. During 2008 we realized a gain of $8.3 million on the sale of marketable
securities and business interruption insurance proceeds of $8.9 million
related to the Giltedge fire. In addition we recorded a write down of $10.0
million related to one of our equity investments in a private company. In 2007
we had a gain of $14.1 million on the sale of marketable securities.

    Royalties

    Royalties are paid to various government entities and other land and
mineral rights owners. Total royalties paid during 2008 increased to $429.9
million compared to $285.1 million in 2007 due to increased commodity prices
and production volumes. As a percentage of oil and gas sales, net of
transportation costs, royalties remained at approximately 19%.
    On January 1, 2009 a new royalty regime came into effect in the province
of Alberta where approximately 60% of our production is located. This new
regime has provisions for escalating royalty rates depending on production and
product price levels. The fundamental design of this 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. The Alberta government further modified the new regime
with programs to encourage the drilling of medium and deeper wells but with
our reduced development capital spending plans we expect no material impact in
2009 from these modifications. Assuming current forward commodity prices and
our production profile, we expect our average royalty rate to decrease
slightly in 2009. The following is a summary of our estimated corporate
average royalty rates under various commodity price scenarios.

    
    2009 Royalty Rate

    Light Crude Oil
     (Cdn $/bbl)(1) $40.00  $50.00  $60.00  $70.00  $80.00  $100.00  $120.00
    -------------------------------------------------------------------------
    AECO Natural
     Gas ($/Mcf)    $ 4.00  $ 5.00  $ 6.00  $ 7.00  $ 8.00  $ 10.00  $ 12.00
    -------------------------------------------------------------------------
    Corporate
     royalty rate    15.6%   17.2%   18.7%   20.2%   21.5%    24.0%    25.9%
    Incremental
     Annual
     Royalties(2)
     ($ Millions)   $(28.6) $(18.0) $(0.1) +$25.0  +$53.3  +$ 123.8 +$ 203.1
    -------------------------------------------------------------------------
    (1) Canadian dollar denominated prices before quality differentials and
        transportation
    (2) Compared to 2008 corporate average rate of 19%
    

    Operating Expenses

    Operating expenses during 2008 were $9.50/BOE or $332.6 million which was
in-line with our guidance and 4% higher than 2007 operating costs of $9.12/BOE
or $274.2 million. Although we expected the acquisition of Focus to decrease
operating costs on a BOE basis, rising costs due to high industry activity for
most of 2008 resulted in higher than expected charges for repairs and
maintenance, chemicals, labour and supplies. In addition we increased our
service rig activity related to our U.S. optimization program.
    For 2009 we expect operating costs to average $10.65/BOE, representing an
increase of 12% per BOE compared to 2008. Approximately half of this increase
is due to lower production while the remainder is due to increased power and
regulatory costs as well as optimization efforts on our Canadian properties.

    General and Administrative Expenses ("G&A")

    G&A expenses were $1.88/BOE or $65.7 million during 2008, approximately
6% lower than our guidance of $2.00/BOE and 17% lower than $2.26/BOE in 2007.
G&A expenses were lower than our guidance primarily due to lower than
anticipated compensation charges. All our compensation plans impact cash G&A
with the exception of our trust unit rights incentive plan which is non-cash.
    Our 2008 G&A expenses included non-cash charges for our trust unit rights
incentive plan of $7.0 million or $0.20/BOE compared to $8.4 million or
$0.28/BOE for 2007. These amounts relate solely to our trust unit rights
incentive plan and are based on the fair value which is determined on the
grant date using a binomial lattice option-pricing model. These values may not
represent the amount realized by employees. 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)           2008       2007
    -------------------------------------------------------------------------
    Cash                                                    $58.7      $59.5
    Trust unit rights incentive plan (non-cash)               7.0        8.4
    -------------------------------------------------------------------------
    Total G&A                                               $65.7      $67.9
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------


    (Per BOE)                                                2008       2007
    -------------------------------------------------------------------------
    Cash                                                    $1.68      $1.98
    Trust unit rights incentive plan (non-cash)              0.20       0.28
    -------------------------------------------------------------------------
    Total G&A                                               $1.88      $2.26
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    

    Our 2008 cash G&A costs were significantly impacted by the drop in our
trust unit price during the year.  Our compensation plans are directly tied to
the movement in our trust unit price.  During 2008 our trust unit price
decreased 40% from $39.87 to $23.96 which significantly reduced the projected
payouts on our plans and our 2008 G&A per BOE measure.  In 2009 we expect cash
G&A costs to be $2.25/BOE which is more consistent with 2007 levels adjusted
for increased technical staff added and additional office space acquired
during 2008.  We expect total G&A costs in 2009 to be $2.45/BOE including
non-cash G&A costs of approximately $0.20/BOE.

    Interest Expense

    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
("CCIRS"). See Note 8 for further details.
    Interest on long-term debt during 2008 totaled $42.6 million, a $0.7
million increase from $41.9 million in 2007. This increase is due to higher
average indebtedness offset by lower interest rates year-over-year. As a
result of the Focus acquisition in February 2008, $330.9 million of additional
debt was assumed when average interest rate was approximately 4.5%. In July
2008 we used the proceeds of $502.0 million from the disposition of Joslyn to
reduce debt outstanding. The Bank of Canada interest rates declined through
2008 from 4.25% to 1.50% at the end of the year. During 2008 our weighted
average interest rate was 3.8% compared to 4.8% in 2007.
    For the year ended December 31, 2008 we recorded unrealized gains of
$18.4 million compared to $8.3 million in 2007. The changes in the fair value
of our interest rate swaps and CCIRS that result from movements in forward
market interest rates cause non-cash interest to fluctuate between periods.

    The following table summarizes the cash and non-cash interest expense:

    
    Interest Expense ($ millions)                            2008       2007
    -------------------------------------------------------------------------
    Interest on long-term debt                              $42.6      $41.9
    Unrealized gain                                         (18.4)      (8.3)
    -------------------------------------------------------------------------
    Total Interest Expense                                  $24.2      $33.6
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    

    At December 31, 2008 approximately 28% of our debt was based on fixed
interest rates while 72% had floating interest rates. In comparison, at
December 31, 2007 approximately 18% of our debt was based on fixed interest
rates and 82% was floating.

    Capital Expenditures

    During 2008 we spent $577.7 million on development capital, which was
$190.5 million or 49% greater than 2007. The increased capital spending in
2008 was due to our expanded asset base resulting from the Focus acquisition
as well as increased spending on shallow gas, deep gas and Bakken oil projects
given higher commodity prices for the majority of the year. Included in our
development capital spending was $54.8 million of exploratory drilling seismic
and undeveloped land acquisitions mainly within the Montney and Bakken plays
which we expect to provide future development opportunities. We achieved a 99%
success rate drilling 643 net wells during 2008.
    Our 2008 development capital was approximately $33.0 million above our
guidance of $545.0 million, mainly due to $22.0 million of accelerated
activity in the Tommy Lakes, Bantry and Shackleton areas. The remaining $11.0
million related to cost overages on various properties including pipeline
maintenance at Golden and drilling costs at Pembina and Virden. We expect the
impact on production and overall capital spending for 2009 to be minimal.
    Corporate acquisitions for 2008 totaled approximately $1.7 billion and
relate to the Focus acquisition which closed February 13, 2008 (refer to Note
5 for further details). Property dispositions were $504.8 million during 2008
compared to $9.6 million in 2007. Our 2008 divestments relate mainly to the
Joslyn disposition which closed in July 2008 for net proceeds of $502.0
million. Our 2007 divestments included $5.6 million of property interests in
the Thorhild area and the sale of undeveloped land in North Dakota for
approximately $3.6 million.
    Property acquisitions were $15.3 million during 2008 compared to $274.2
million in 2007. The majority of our 2007 acquisitions related to the purchase
of our Kirby Oil Sands Project ("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.

    
    Capital Expenditures ($ millions)                        2008       2007
    -------------------------------------------------------------------------
    Development expenditures                            $   442.4  $   321.3
    Plant and facilities                                    135.3       65.9
    -------------------------------------------------------------------------
    Development Capital                                     577.7      387.2
    Office                                                   10.6        6.5
    -------------------------------------------------------------------------
    Sub-total                                               588.3      393.7
    Property acquisitions(1)                                 15.3      274.2
    Corporate acquisitions                                1,757.5          -
    -------------------------------------------------------------------------
      Capital Expenditures                                2,361.1      667.9
    -------------------------------------------------------------------------
    Property dispositions(1)                               (504.8)      (9.6)
    -------------------------------------------------------------------------
    Total Net Capital Expenditures                      $ 1,856.3  $   658.3
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    Total Capital Expenditures financed with cash
     flow                                               $   476.7  $   221.7
    Total Capital Expenditures financed with debt
     and equity                                           1,379.6      443.2
    Total non-cash consideration for property
     dispositions                                               -       (6.6)
    -------------------------------------------------------------------------
    Total Net Capital Expenditures                      $ 1,856.3  $   658.3
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    (1) Net of post-closing adjustments.

    The following is a summary by play type of our development capital
expenditures during 2008 and 2007, as well as our current expectations for
2009.

    Play type ($ millions)               2009 Estimate       2008       2007
    -------------------------------------------------------------------------
    Shallow Gas and CBM                         $ 74.3     $159.1     $ 39.3
    Crude Oil Waterfloods                         45.4       84.0       54.2
    Tight Gas                                     78.4       81.0       34.7
    Bakken/Tight Oil                              41.8       99.0      106.2
    Other Conventional Oil and Gas                35.1      103.4      113.9
    Oil Sands                                     25.0       51.2       38.9
    -------------------------------------------------------------------------
    Total                                       $300.0     $577.7     $387.2
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    

    We expect development capital expenditures in 2009 to be approximately
$300 million including oil sands development capital of approximately $25
million and $50 million on initial resource investments (land and seismic)
neither of which are expected to impact 2009 production.

    Oil Sands

    Our current oil sands portfolio includes the 100% owned and operated
Kirby steam assisted gravity drainage ("SAGD") project and a 12% minority
equity ownership interest in Laricina Energy Ltd., a private oil sands company
focused on SAGD development in the Athabasca oil sands.
    Our Kirby project has not commenced commercial production. As a result,
all associated costs inclusive of acquisition expenditures are capitalized and
excluded from our depletion calculation. During 2008 we capitalized costs of
$40.6 million associated with the Kirby project including costs of our
regulatory application, which we filed on September 26, 2008. At December 31,
2008 capitalized costs life-to-date for our oil sands development were $257.6
million compared to $321.8 million at December 31, 2007. Included in the 2007
amount was our Joslyn interest which we sold on July 31, 2008.
    As a result of current low crude oil prices we have reduced our 2009
capital spending on the Kirby project to $25.0 million consisting primarily of
engineering and regulatory costs associated with advancing Phase I and seismic
costs aimed at expanding the overall resource base associated with this lease.
Kirby has a reserve life of over 25 years and we believe over the longer term
oil prices will recover to justify proceeding with development. Our regulatory
application is currently under review and we expect to receive regulatory
approval by the end of 2009. Our board of directors will re-evaluate whether
to continue to proceed with or delay the Kirby project at that time.

    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 2008 DDA&A was $640.4
million or $18.29/BOE compared to $463.7 million or $15.43/BOE in 2007. The
increase is a result of higher PP&E and production from the Focus acquisition.
    No impairment of the Fund's PP&E values existed at December 31, 2008
using year-end reserves and management's estimates of future prices. Our
future price estimates are more fully discussed in Note 3.

    Goodwill

    The goodwill balance of $634.0 million arose as a result of previous
corporate acquisitions and represents the excess of the total purchase price
over the fair value of the net identifiable assets and liabilities acquired.
    Accounting standards require the goodwill balance be assessed for
impairment at least annually or more frequently if events or changes in
circumstances indicate the balance might be impaired. If such impairment
exists, it would be charged to income in the period in which the impairment
occurs. No goodwill impairment exists as of December 31, 2008.

    Asset Retirement Obligations

    We have estimated our 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 the future. Our
asset retirement obligation was $207.4 million at December 31, 2008 compared
to $165.7 million at December 31, 2007. The majority of the $41.7 million
increase was due to the addition of abandonment obligations associated with
the Focus acquisition. The remainder of the increase was due to additional
costs from development capital activity and accretion expense offset by
retirement costs incurred. See Note 4 for further details.
    The following chart shows the amortization of the asset retirement cost
and accretion of the asset retirement obligation compared to asset retirement
obligations settled.

    
    ($ millions)                                             2008       2007
    -------------------------------------------------------------------------
    Amortization of the asset retirement cost               $20.0      $11.4
    Accretion of the asset retirement obligation             11.9        6.7
    -------------------------------------------------------------------------
    Total Amortization and Accretion                        $31.9      $18.1
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    Asset Retirement Obligations Settled                    $18.3      $16.3
    -------------------------------------------------------------------------
    

    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 2039
and 2048. 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

    In 2008, the Canadian Federal government introduced draft tax legislation
that allowed for the conversion of a specified investment flow-through
("SIFT") entity into corporate form on a tax deferred basis, defined the
provincial tax component of the SIFT tax, and accelerated the recognition of
the "Safe Harbour" limit. None of the above were enacted prior to the
prorogation of Parliament in December 2008. Therefore, all bills containing
the draft legislation have lapsed.
    Subsequent to the year end, the Federal government has introduced draft
tax legislation which includes the above mentioned measures as part of
Canada's Economic Action Plan. When or if this draft tax legislation becomes
substantially enacted, Enerplus will be able to recognize the tax benefit
associated with the lower provincial tax component of the SIFT tax.

    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
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.
    The future income tax recovery for 2008 was $51.2 million compared to
$1.0 million in 2007. The change was due to the following:
    
    -   The enactment of the SIFT tax which resulted in a future income tax
        expense of $78.1 million in 2007;
    -   The enactment of corporate income tax rate reductions which resulted
        in a future income tax recovery of $22.6 million in 2007 as compared
        to $2.7 million in 2008;
    -   The sale of Joslyn in 2008 resulted in a future income tax recovery
        of $58.9 million relating to the non-taxable portion of the realized
        gain, along with the recognition of tax losses previously
        unrecognized; and
    -   The incremental future tax expense of $51.8 million in 2008 related
        to the increase in the net income attributed to the fund.
    

    After consideration of the above items the future tax provisions were
comparable between 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 minimal cash income taxes are
generally paid by our Canadian operating entities. However, effective January
1, 2011 we will be subject to the SIFT tax should we remain a trust.
    A Canadian income tax liability of $24.3 million was triggered on the
acquisition of Focus in 2008. This liability was included in Focus' assumed
working capital at the time of acquisition. We have accrued for the recovery
of these taxes in 2008 which constitutes the majority of the Canadian income
tax recovery.
    During 2008 our U.S. operations incurred current taxes in the amount of
$47.8 million compared to $23.0 million in 2007. The increase is due to higher
net income combined with a modest decrease in drilling and completion
expenditures for the year.
    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 funds to Canada. Our U.S. taxes as a percentage of cash flow,
assuming constant working capital, were 18% in 2008 compared to our guidance
of 20% as a result of lower commodity prices in the fourth quarter. We expect
current income and withholding taxes to average approximately 15% of cash flow
from U.S. operations in 2009 based on our current development capital program
and assuming all funds are repatriated to Canada.

    Tax Pools

    We estimate our tax pools at December 31, 2008 to be as follows:

    
                                                        Operating
    Pool Type ($ millions)                       Trust   entities      Total
    -------------------------------------------------------------------------
    COGPE                                       $  470     $  165     $  635
    CDE                                              -        670        670
    UCC                                              -        680        680
    CEE                                              -        125        125
    Tax losses and other                            15        380        395
    Foreign tax pools                                -        210        210
    -------------------------------------------------------------------------
    Total                                       $  485     $2,230     $2,715
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    

    Net Income

    Net income in 2008 was $888.9 million or $5.54 per trust unit compared to
$339.7 million or $2.66 per trust unit in 2007. The $549.2 million increase in
net income was primarily due to a $787.0 million increase in oil and gas sales
(net of transportation costs), $119.3 million increase in commodity derivative
instrument gains and a $48.3 million increase in future tax recovery,
partially offset by increased DDA&A charges of $176.7 million, increased
royalty expense of $144.8 million and increased operating costs of $58.4
million.

    Cash Flow from Operating Activities

    Cash flow from operating activities in 2008 was $1,262.8 million or $7.86
per trust unit compared to $868.5 million or $6.80 per trust unit in 2007. The
increase is primarily due to increased commodity prices in the first three
quarters of 2008 and higher production volumes.

    Selected Financial Results

    
                    Year ended December 31,       Year ended December 31,
                             2008                          2007
    Per BOE of   Operating  Non-Cash           Operating  Non-Cash
     production       Cash   & Other                Cash   & Other
     (6:1)          Flow(1)    Items     Total    Flow(1)    Items     Total
    -------------------------------------------------------------------------
    Production per
     day                                95,687                        82,319
    -------------------------------------------------------------------------
    Weighted
     average sales
     price (2)     $ 65.79   $     -   $ 65.79   $ 50.48   $     -   $ 50.48
    Royalties       (12.27)        -    (12.27)    (9.49)        -     (9.49)
    Commodity
     derivative
     instruments     (2.94)     4.84      1.90      0.45     (2.21)    (1.76)
    Operating costs  (9.51)     0.01     (9.50)    (9.11)    (0.01)    (9.12)
    General and
     administrative  (1.68)    (0.20)    (1.88)    (1.98)    (0.28)    (2.26)
    Interest
     expense, net
     of interest
     income          (0.91)     0.51     (0.40)    (1.37)     0.28     (1.09)
    Foreign exchange
     gain / (loss)   (0.68)    (0.05)    (0.73)    (0.06)     0.30      0.24
    Current income
     tax             (0.65)        -     (0.65)    (0.77)        -     (0.77)
    Restoration and
     abandonment
     cash costs      (0.52)     0.52         -     (0.54)     0.54         -
    Depletion,
     depreciation,
     amortization
     and accretion       -    (18.29)   (18.29)        -    (15.43)   (15.43)
    Future income
     tax (expense)
     / recovery          -      1.46      1.46         -      0.04      0.04
    Other Income         -     (0.05)    (0.05)        -      0.47      0.47
    -------------------------------------------------------------------------
    Total per BOE   $36.63   $(11.25)  $ 25.38   $ 27.61   $(16.30)  $ 11.31
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    (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.

    Selected Annual Canadian and U.S. Financial Results

    The following table provides a geographical analysis of key operating and
financial results for 2008 and 2007.

                  Year ended December 31, 2008  Year ended December 31, 2007
    (CDN$
     millions,
     except per
     unit amounts)  Canada       U.S.    Total    Canada       U.S.    Total
    -------------------------------------------------------------------------
    Average Daily
     Production
     Volumes
      Natural gas
       (Mcf/day)   326,138    12,731   338,869   251,561    10,693   262,254
      Crude oil
       (bbls/day)   25,248     9,333    34,581    24,590     9,916    34,506
      Natural gas
       liquids
       (bbls/day)    4,627         -     4,627     4,104         -     4,104
      Total daily
       sales
       (BOE/day)    84,232    11,455    95,687    70,621    11,698    82,319

    Pricing (1)
      Natural gas
       (per Mcf)  $   8.14  $   8.93  $   8.17  $   6.45  $   6.55  $   6.45
      Crude oil
       (per bbl)  $  90.28  $  94.09  $  91.31  $  62.27  $  72.17  $  65.11
      Natural gas
       liquids
       (per bbl)  $  68.93  $      -  $  68.93  $  51.35  $      -  $  51.35

    Capital
     Expenditures
      Development
       capital and
       office     $  518.2  $   70.1  $  588.3  $  287.3  $  106.4  $  393.7
      Acquisitions
       of oil and
       gas
       properties $   15.2  $    0.1  $   15.3  $  213.3  $   60.9  $  274.2
      Corporate
       Acquisi-
       tions      $1,757.5  $      -  $1,757.5
      Dispositions
       of oil and
       gas
       properties $ (504.9) $    0.1  $ (504.8) $   (6.0) $   (3.6) $   (9.6)

    Revenues
      Oil and gas
       sales (1)  $1,941.2  $  363.0  $2,304.2  $1,230.4  $  286.7  $1,517.1
      Royalties   $ (351.9) $(78.0)(2) $(429.9) $ (226.4) $(58.7)(2) $(285.1)
      Commodity
       derivative
       instru-
       ments gain/
       (loss)     $   66.4  $      -  $   66.4  $  (52.8) $      -  $ (52.8)

    Expenses
      Operating   $  314.5  $   18.1  $  332.6  $  264.4  $    9.8  $  274.2
      General and
       adminis-
       trative    $   58.6  $    7.1  $   65.7  $   62.6  $    5.3  $   67.9
    Depletion,
     depreciation,
     amortization
     and
     accretion    $  550.0  $   90.4  $  640.4  $  359.8  $  103.9  $  463.7
    Current
     income taxes
     (recovery)/
     expense      $  (25.1) $   47.8  $   22.7  $      -  $   23.0  $   23.0
    -------------------------------------------------------------------------
    (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, increased production volumes from our Focus acquisition and
increased commodity prices have resulted in higher oil and gas sales, net
income and cash flow from operating activities during 2008 compared to 2007.
The rise in crude oil prices during 2006, 2007 and the first three quarters of
2008 contributed to higher overall sales, however gas sales moderated in 2007
as a result of lower natural gas prices. The following table provides a
summary of net income, cash flow and other key measures.

    
    ($ millions, except per unit amounts)         2008       2007       2006
    -------------------------------------------------------------------------
    Oil and gas sales(1)                      $2,304.2   $1,517.1   $1,572.7

    Net income                                   888.9      339.7      544.8
    Per unit (Basic)(2)                           5.54       2.66       4.48
    Per unit (Diluted)                            5.53       2.66       4.47

    Cash flow from operating activities        1,262.8      868.5      863.7
    Per unit (Basic) (2)                          7.86       6.80       7.10

    Cash distributions                           786.1      646.8      614.3
    Per unit (Basic) (2)                          4.90       5.07       5.05
    Payout ratio                                   62%        74%        71%

    Total assets                               6,230.1    4,303.1    4,203.8

    Long-term debt, net of cash                  657.4      725.0      679.7
    -------------------------------------------------------------------------
    (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

    Capital Markets and Enerplus' Credit Exposure

    The recent turmoil in the financial markets has impacted the availability
of credit and equity in the marketplace. The current market conditions
indicate that it may be difficult to issue additional equity or increase
credit capacity without significant costs at this time. In addition, there has
been a dramatic reduction in crude oil and natural gas prices since the summer
of 2008. As a result there has been a greater emphasis on evaluating credit
capacity, credit counterparties and liquidity. We have discussed these risks
as they relate to our credit facility, oil and gas sales counterparties,
financial derivative counterparties and joint venture partners below.

    
    Credit Facility
    ---------------
    

    Enerplus' bank credit facility is an unsecured, covenant-based credit
agreement with a syndicate of thirteen financial institutions, a summary of
which was filed on March 18, 2008 as a "Material document" on the Fund's SEDAR
profile at www.sedar.com. Of the thirteen syndicate members in Enerplus'
facility, seven are major Canadian banks which represent approximately $1.025
billion or 73% of the commitments under the $1.4 billion facility. The
facility is extendable each year and is currently set to expire in November
2010. Rates under the facility range between 55.0 and 110.0 basis points over
bankers' acceptance rates and are significantly lower than rates currently
being negotiated in the marketplace. At December 31, 2008 we have drawn $380.9
million or approximately 27% of our $1.4 billion facility and have a trailing
debt-to-cash flow ratio of 0.5x. Our borrowing cost is currently 55.0 basis
points over bankers' acceptance rates.
    At December 31, 2008 Enerplus was in compliance with all covenants under
the credit facility. Our exposure to our lenders relates to their potential
inability to fund. Should a lender be unable or choose not to fund, other
lenders have the right, but not the obligation, to increase their commitment
levels to cover the shortfall. Failure to fund would be considered a breach of
contract and could result in potential damages in favour of Enerplus, however
the likelihood of substantiating and receiving damages is unknown. We have not
experienced any funding issues under the facility to date.

    
    Oil and Gas Sales Counterparties
    --------------------------------
    

    The Fund's oil and gas receivables are with customers in the petroleum
and natural gas business and are subject to normal credit risks. Concentration
of credit risk is mitigated by marketing production to numerous purchasers
under normal industry sale and payment terms. A credit review process is in
place to assess and monitor our counterparties' credit worthiness on a regular
basis. This process involves reviewing and ratifying our corporate credit
guidelines, assessing the credit ratings of our counterparties and setting
exposure limits. When warranted we obtain financial assurances such as letters
of credit, parental guarantees, or third party insurance to mitigate our
credit risk. This process is completed for both our oil and gas sales
counterparties as well as our financial derivative counterparties. For the
year ended December 31, 2008 we have made a $1.5 million bad debt provision,
the majority of which relates to our exposure to a Canadian subsidiary of
SemGroup L.P., which is currently subject to insolvency proceedings in the
U.S.

    
    Financial Derivative Counterparties
    -----------------------------------
    

    The Fund is exposed to credit risk in the event of non-performance by our
financial counterparties regarding our derivative contracts. The Fund
mitigates this risk by entering into transactions with major financial
institutions, the majority of which are members of our bank syndicate. We have
no exposure to Lehman Brothers, which is currently in insolvency proceedings.
We have International Swaps and Derivatives Association ("ISDA") agreements in
place with the majority of our financial counterparties. These agreements
provide some credit protection in that they generally allow parties to
aggregate amounts owing to each other under all outstanding transactions and
settle with a single net amount in the case of a credit event. Absent an ISDA
we rely on long form confirmations which provide Enerplus with similar credit
protection in terms of aggregating transactions and netting for settlement in
the case of a credit event. At December 31, 2008 we had $128.1 million in
mark-to-market assets offset by $26.4 million of mark-to-market liabilities
consisting of net asset positions of $77.2 million with major Canadian
institutions and $24.5 million with U.S. institutions.
    We will continue to monitor developments in the financial markets that
could impact the credit worthiness of our financial counterparties, however it
has recently been very difficult to foresee counterparty solvency issues. To
date we have not experienced any losses due to non-performance by our
derivative counterparties.

    
    Joint Venture Partners
    ----------------------
    

    We attempt to mitigate the credit risk associated with our joint interest
receivables by reviewing and actively following up on older accounts. In
addition, we are specifically monitoring our receivables against a watch list
of publicly traded companies that have high debt-to-cash flow ratios or fully
drawn bank facilities. We do not anticipate any significant issues in the
collection of our joint interest receivables at this time. However, if the
current low commodity prices and tight capital markets prevail, there is a
risk of increased bad debts related to our industry partners, and as a result
we have increased our bad debt provision by $1.0 million.

    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 anticipated cash flows, debt levels, capital spending plans and
capital market conditions. The level of cash withheld has historically varied
between approximately 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, funding requirements for our development capital
program and our access to equity markets.
    The sharp decrease in crude oil and natural gas prices has resulted in a
decrease in our overall cash flows. This commodity price downturn, combined
with the ongoing uncertainty and reduced access to the debt and equity
markets, has reinforced our belief in the importance of maintaining strong
financial flexibility. To that end, we have reduced our monthly cash
distributions three times during the last five months to the current level of
$0.18 per unit effective February 20, 2009. We intend to manage our
distribution levels and capital spending in order to minimize increases in our
debt levels and preserve our balance sheet strength for future acquisitions.
    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.

    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.
    Our 2009 development capital spending is expected to be $300 million
which represents a 48% decrease from 2008 spending of $577.7 million. In 2009
we expect to spend $50 million on initial resource investments such as land
acquisitions and seismic to position us for development opportunities in the
future, which is not expected to add production in 2009. As a result we expect
our production to decrease to an annual average of 91,000 BOE/day and an exit
rate of 88,000 BOE/day in 2009. At this level of capital spending it will be
difficult to replace our production without reliance on acquisitions to
supplement our reserves.
    Enerplus currently has approximately $9.5 billion of safe harbour growth
capacity within the context of the Canadian Government's "normal growth"
guidelines for SIFT's. 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.

    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 2008 cash distributions
of $786.1 million were funded entirely through cash flow of $1,262.8 million.
Our payout ratio, which is calculated as cash distributions divided by cash
flow, was 62% for 2008 compared to 74% in 2007. See "Non-GAAP Measures" in
this MD&A.
    In aggregate, our 2008 cash distributions of $786.1 million and our
development capital and office expenditures of $588.3 million totaled $1,374.4
million, or approximately 109% of our cash flow of $1,262.8 million. We expect
to support our distributions and capital expenditures with our cash flow,
however we will continue to fund acquisitions and growth through additional
debt and equity when required. We anticipate that our reduced capital spending
plans for 2009 along with our reductions in monthly cash distributions will
help minimize any increases in debt levels and preserve our balance sheet.
There will be years when we are investing capital in opportunities that do not
immediately generate cash flow (such as our Kirby oil sands project) where we
may also use debt and equity to support the investment. Despite our 2008 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 0.5x at December 31, 2008 and an annualized
fourth quarter 2008 debt-to-cash flow ratio of 0.7x.
    For the year ended December 31, 2008 our net income exceeded our cash
distributions by $102.8 million whereas in 2007 our cash distributions
exceeded our net income by $307.1 million. Non-cash items, such as changes in
the fair value of our derivative instruments and future income taxes, cause
net income to fluctuate between periods but do not impact cash flow from
operations. 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.
    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. As a result we do not
distinguish maintenance capital separately from development capital spending.
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)         2008       2007       2006
    -------------------------------------------------------------------------
    Cash flow from operating activities       $1,262.8   $  868.5   $  863.7
    Cash Distributions                           786.1      646.8      614.3
    -------------------------------------------------------------------------
    Excess of cash flow over cash
     distributions                            $  476.7   $  221.7   $  249.4

    Net income                                $  888.9   $  339.7   $  544.8
    Excess/(shortfall) of net income over
     cash distributions                       $  102.8   $ (307.1)  $  (69.5)

    Cash distributions per weighted average
     trust unit                               $   4.90   $   5.07   $   5.05
    Payout ratio (1)                               62%        74%        71%
    -------------------------------------------------------------------------
    (1) Based on cash distributions divided by cash flow from operating
        activities.
    

    Asset Retirement Costs

    Actual asset retirement costs incurred in the period are deducted for the
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 this
MD&A and Note 4.

    Long-Term Debt

    Long-term debt at December 31, 2008 was $664.3 million, a decrease of
$62.4 million from $726.7 million at December 31, 2007. Long-term debt at
December 31, 2008 was comprised of $380.9 million of bank indebtedness and
$283.4 million of senior unsecured notes. Our bank indebtedness decreased by
$116.5 million year-over-year mainly due to proceeds received from the Joslyn
disposition of $502.0 million which was partially offset by additional debt of
$330.9 million acquired in the Focus acquisition. Our senior unsecured notes
are comprised of our US$175 million senior notes and our US$54 million senior
notes. The change in period end foreign exchange rate resulted in an increase
in the carrying value of our senior notes to $283.4 million compared to $229.3
million at December 31, 2007.
    Our working capital, excluding cash, at December 31, 2008 increased
$147.2 million compared to December 31, 2007 primarily due to an increase in
our deferred financial assets relating to our financial derivative contracts.
Excluding deferred financial assets and credits, our working capital decreased
by $16.4 million compared to the prior year. This is primarily due to an
increase in future income taxes payable offset slightly by a decrease in
distributions payable and an increase in accounts receivable.
    We continue to maintain a conservative balance sheet as demonstrated
below with over $1.0 billion in unused credit capacity under our current
facility:

    
                                                             Year       Year
                                                            ended      ended
                                                          Dec. 31,   Dec. 31,
    Financial Leverage and Coverage                          2008       2007
    -------------------------------------------------------------------------
    Long-term debt to trailing 12 month cash flow           0.5 x      0.8 x
    Long-term debt to annualized fourth quarter cash flow   0.7 x      0.9 x
    Cash flow to interest expense (12 month trailing)      46.5 x     25.8 x
    Long-term debt to long-term debt plus equity              13%        22%
    -------------------------------------------------------------------------
    Long-term debt is measured net of cash.
    

    At December 31, 2008 Enerplus had a $1.4 billion unsecured covenant based
term bank facility maturing 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 term. Due to the volatility in the credit
markets we chose not to extend the term of the credit facility this year. The
facility 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,
2008 we were in compliance with our debt covenants, the most restrictive of
which limits our long-term debt to three times trailing cash flow including
acquisition cash flows. Refer to "Debt of Enerplus" in our Annual Information
Form for the year ended December 31, 2008 for a detailed description of these
covenants.
    Principal payments on Enerplus' senior unsecured notes are required
commencing in 2010 and are more fully discussed below under "Commitments" and
Note 13.
    We continue to have adequate liquidity to fund planned development
capital spending for 2009 through a combination of cash flow retained by the
business and debt, if needed.

    Commitments

    We have contracted to transport 143 MMcf/day of natural gas on the
TransCanada system in Alberta, 70 MMcf/day on TransGas in Saskatchewan, 48
MMcf/day in B.C.via Spectra, as well as 9 MMcf/day on the Alliance pipeline to
the U.S. Midwest.
    Our gas supply dedicated to aggregator sales contracts will decline in
2009 to approximately 6% of gas production (22.0 MMcf/day), down from more
than 20% in 2008. The early truncation of the ProGas and Cargill aggregator
pools leaves Pan-Alberta as the only remaining aggregator. 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 addition, we also have 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.
    Our Canadian and U.S. office leases 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, 2008 Enerplus has the following minimum annual
commitments including long-term debt:

    
                                                                       Total
                                                                     Committ-
                            Minimum Annual Commitment Each Year           ed
                      ----------------------------------------------   after
    ($ millions)       Total    2009    2010    2011    2012    2013    2013
    -------------------------------------------------------------------------
    Bank credit
     facility(1)      $380.9  $    -  $380.9  $    -  $    -  $    -  $    -
    Senior unsecured
     notes(1)(2)       323.2       -    53.7    64.6    64.6    64.6    75.7
    Pipeline
     commitments        62.7    18.8    11.8     9.1     6.7     5.4    10.9
    Processing
     commitments        25.6     7.6     7.7     7.3     3.0       -       -
    Office leases       69.6     8.7    11.7    12.5    12.6    12.6    11.5
    -------------------------------------------------------------------------
    Total
     commitments(3)   $862.0  $ 35.1  $465.8  $ 93.5  $ 86.9  $ 82.6  $ 98.1
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    (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.
    

    Accumulated Deficit

    We have historically paid cash distributions in excess of accumulated
earnings as cash distributions are based on the actual 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 and future
income tax provisions.

    Trust Unit Information

    We had 165,590,000 trust units outstanding at December 31, 2008 compared
to 129,813,000 trust units outstanding at December 31, 2007.
    Included in the December 31, 2008 outstanding units were 30,150,000 units
issued on February 13, 2008 to acquire Focus.  In addition 9,087,000
exchangeable partnership units were assumed on the Focus acquisition which
became exchangeable into Enerplus trust units at the ratio of 0.425 of a trust
unit for each partnership unit.  During 2008 1,849,000 partnership units were
converted into 786,000 trust units, leaving 7,238,000 partnership units
outstanding at December 31, 2008 representing the equivalent of 3,076,000
trust units.
    In addition 1,881,000 trust units (2007 - 1,307,000) 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 $70.5 million (2007 - $56.8 million) of additional equity to the
Fund. For further details see Note 10.
    The weighted average basic number of trust units outstanding during 2008
was 160,589,000 compared to 127,691,000 trust units during 2007. At February
20, 2009 we had 165,707,000 trust units outstanding including the equivalent
limited partnership units.

    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.

    Canadian Unitholders

    We qualify as a mutual fund trust under the Income Tax Act (Canada) and
accordingly, trust units of Enerplus are qualified investments for RRSPs,
RRIFs, RESPs, DPSPs and TFSAs. Each year we have historically transferred all
of our 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 $4.89 per trust unit in cash distributions to unitholders on
record during 2008. For Canadian tax purposes, approximately 2% of these
distributions, or $0.08 per trust unit was a tax deferred return of capital,
approximately 98% or $4.81 per trust unit was taxable to unitholders as other
income, and there was no eligible dividend income.
    For 2009, 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. The
15% preferred rate of tax on "Qualified Dividends" is currently scheduled to
expire in 2010. We are unable to determine whether or to what extent the
preferred rate of tax on "Qualified Dividends" may be extended.
    We paid US$4.77 per trust unit to U.S. residents during the 2008 calendar
year of which 8% or US$0.38 per trust unit was a tax deferred return of
capital and 92% or US$4.39 per unit was a taxable qualified dividend.
    For 2009, 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, crude oil and natural gas sales increased from 2007 to mid
2008 due to increased production and increased commodity prices. Oil and gas
sales decreased during the second half of 2008 as a result of the sharp
decline in commodity prices.
    Net income has been affected by fluctuating commodity prices and risk
management costs, the fluctuating Canadian dollar, higher operating costs and
changes in future tax provisions due to the SIFT tax and corporate rate
reductions. Furthermore, changes in the fair value of our commodity derivative
instruments and other financial instruments cause net income to continually
fluctuate between quarters.

    
    Quarterly Financial
    Information                  Oil and                      Net Income
    (CDN$ millions, except           Gas        Net         Per Trust Unit
     per trust unit amounts)     Sales(1)     Income       Basic     Diluted
    -------------------------------------------------------------------------
    2008
    Fourth Quarter             $   418.3   $   189.5   $    1.15   $    1.15
    Third Quarter                  647.8       465.8        2.82        2.82
    Second Quarter                 734.4       112.2        0.68        0.68
    First Quarter                  503.7       121.4        0.82        0.82
    -------------------------------------------------
    Total                      $ 2,304.2   $   888.9   $    5.54   $    5.53
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    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
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    (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 2008 with the same period in 2007:
    -   Average daily production increased 21% to 97,702 BOE/day primarily
        due to the acquisition of Focus.
    -   The average selling price per BOE decreased 11% to $46.54 due to a
        significant drop in crude oil prices in the fourth quarter of 2008.
    -   Cash flow increased to $258.5 million in 2008 compared to
        $205.1 million in 2007 due to increased production offset by lower
        crude oil prices.
    -   Net income increased 92% from the fourth quarter of 2007 to
        $189.5 million due to increased commodity derivative instrument
        gains and increased production.
    -   The payout ratio decreased 19% compared to the fourth quarter of
        2007 as a result of higher cash flow during the fourth quarter of
        2008.
    -   Cash distributions per unit were reduced during the fourth quarter
        of 2008 which resulted in a 20% decrease from the fourth quarter of
        2007.
    -   Operating expenses, including non-cash amounts, increased by 10% to
        $9.44/BOE from $8.57/BOE during the fourth quarter of 2007 due to
        increased service rig activity and repairs and maintenance.
    -   G&A expenses, including non-cash amounts, decreased 14% on a BOE
        basis to $1.89/BOE from $2.21/BOE in the fourth quarter of 2007 due
        to lower compensation costs.
    -   Development capital spending increased 89% compared to the fourth
        quarter of 2007 due to a larger capital development program that
        included the Focus properties, along with accelerated capital
        spending at several locations.

    The following tables provide an analysis of key financial and operating
results for the three months ended December 31, 2008 and 2007.

                                                  Three Months  Three Months
                                                         Ended         Ended
                                                   December 31,  December 31,
    (CDN$ millions, except per unit amounts)              2008          2007
    -------------------------------------------------------------------------
    Financial (000's)
    Net Income                                     $     189.5    $     98.7
    Cash Flow from Operating Activities            $     258.5    $    205.1
    Cash Distributions to Unitholders(1)           $     167.0    $    163.4

    Financial per Unit(2)
    Net Income                                     $      1.15    $     0.76
    Cash Flow from Operating Activities            $      1.56    $     1.58
    Cash Distributions to Unitholders(1)           $      1.01    $     1.26

    Payout Ratio(3)                                        65%           80%

    Average Daily Production                            97,702        80,959

    Selected Financial Results per BOE(4)
    Oil and Gas Sales(5)                           $     46.54    $    52.33
    Royalties                                            (8.61)        (9.83)
    Commodity Derivative Instruments                      3.54         (0.08)
    Operating Costs                                      (9.46)        (8.53)
    General and Administrative                           (1.71)        (1.94)
    Interest and Foreign Exchange                        (2.73)        (1.70)
    Taxes                                                 0.92         (1.70)
    Restoration and Abandonment                          (0.53)        (0.75)
    -------------------------------------------------------------------------
    Cash Flow from Operating Activities
     before changes in non-cash working capital    $     27.96    $    27.80
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    Weighted Average Number of Units
     Outstanding (thousands)                           165,373       129,658

    Development Capital                                  200.3         106.1
    Net Wells Drilled                                      174            76
    Success Rate                                           99%          100%

    Average Benchmark Pricing
    AECO natural gas - monthly index (CDN$/Mcf)    $      6.79   $      6.00
    AECO natural gas - daily index (CDN$/Mcf)      $      6.68   $      6.14
    NYMEX natural gas - monthly NX3 index
     (US$/Mcf)                                     $      6.77   $      7.03
    NYMEX natural gas - monthly NX3 index: CDN$
     equivalent (CDN$/Mcf)                         $      8.26   $      6.89
    WTI crude oil (US$/bbl)                        $     58.73   $     90.68
    WTI crude oil: CDN$ equivalent (CDN$/bbl)      $     71.62   $     88.90
    CDN$/US$ exchange rate                                0.82          1.02
    -------------------------------------------------------------------------
    (1) Calculated based on distributions paid or payable. Cash distributions
        to unitholders per unit may not correspond to actual distributions of
        $1.01 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$              Three months ended            Three months ended
     millions,          December 31, 2008             December 31, 2007
     except per
     unit amounts)  Canada       U.S.    Total    Canada       U.S.    Total
    -------------------------------------------------------------------------
    Average Daily
     Production Volumes
      Natural gas
       (Mcf/day)   333,046    13,393   346,439   245,219    12,196   257,415
      Crude oil
       (bbls/day)   26,122     9,312    35,434    24,248     9,973    34,221
      Natural gas
       liquids
       (bbls/day)    4,529         -     4,529     3,836         -     3,836
      Total daily
       sales
       (BOE/day)    86,158    11,544    97,702    68,953    12,006    80,959

    Pricing(1)
      Natural gas
       (per Mcf)  $   7.01  $   4.81  $   6.92  $   5.91  $   5.98  $   5.91
      Crude oil
       (per bbl)  $  54.85  $  56.02  $  55.16  $  68.94  $  80.16  $  72.21
      Natural gas
       liquids
       (per bbl)  $  43.55  $      -  $  43.55  $  58.12  $      -  $  58.12

    Capital
     Expenditures
      Development
       capital and
       office     $  186.7  $   18.1  $  204.8  $   94.3  $   13.7  $  108.0
      Acquisitions
       of oil
       and gas
       properties $    1.3  $    0.1  $   1.4   $    5.0  $    0.1  $    5.1
      Dispositions
       of oil
       and gas
       properties $   (0.2) $     -   $  (0.2)  $   (0.4) $   (3.6) $   (4.0)

    Revenues
      Oil and gas
       sales(1)   $  364.4  $   53.9  $  418.3  $  309.5  $   80.3  $  389.8
      Royalties   $  (65.8) $(11.6)(2) $ (77.4) $  (56.1) $(17.1)(2) $ (73.2)
      Commodity
       derivative
       instru-
       ments gain/
       (loss)     $  161.2  $     -   $  161.2  $  (48.8) $      -  $  (48.8)

    Expenses
      Operating   $   80.0  $   4.8   $   84.8  $   61.0  $    2.8  $   63.8
      General and
       adminis-
       trative    $   13.9  $   3.1   $   17.0  $   16.5  $   (0.1) $   16.4
    Depletion,
     depreciation,
     amortization
     and
     accretion    $  142.9  $   24.1  $  167.0  $   89.9  $   21.8  $  111.7
       Current
        income
        taxes     $   (8.2) $   (0.1) $   (8.3) $      -  $   12.6  $   12.6
    -------------------------------------------------------------------------
    (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 15. Most accounting policies are mandated under GAAP
however, in accounting for oil and gas activities, we have a choice between
the full cost and the successful efforts methods of accounting.
    We apply the full cost method of accounting for oil and natural gas
activities. Under 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 exploratory 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
of accounting 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 under full
cost accounting.

    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 estimate (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,
assess impairment in our cost centers, and determine the change in fair value
of financial contracts. Management's estimates of prices are based on the
price forecast from our reserve engineers and the current forward market.

    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, especially in
times of decreasing commodity prices and trust unit values.

    Derivative Financial Instruments

    We utilize derivative financial instruments to manage our exposure to
market risks relating to commodity prices, foreign currency exchange rates and
interest rates. Fair values of derivative contracts fluctuate depending on the
underlying estimate of future commodity prices, foreign currency exchange
rates, interest rates and counterparty credit risk.

    RECENT CANADIAN ACCOUNTING AND RELATED PRONOUNCEMENTS

    Current Year Accounting Changes

    Effective January 1, 2008, the Fund adopted three new accounting
standards that were issued by the Canadian Institute of Chartered Accountants
("CICA"): Handbook Section 1535, Capital Disclosures, Section 3862, Financial
Instruments - Disclosures and Section 3863, Financial Instruments -
Presentation.

    Capital Disclosures

    Section 1535 establishes standards for disclosing information regarding
an entity's capital and how it is managed.

    Financial Instruments - Disclosures, Financial Instruments - Presentation

    Sections 3862 and 3863 establish standards for enhancing financial
statements users' understanding of the significance of financial instruments
to an entity's financial position, performance and cash flows. They require
that entities provide disclosures regarding the nature and extent of risks
arising from financial instruments to which they are exposed both during the
reporting period and at the balance sheet date, as well as how the entities
manage those risks.

    These standards were adopted prospectively.

    Future Accounting Changes

    Goodwill and Intangible Assets

    In February 2008, the CICA issued Section 3064, Goodwill and Intangible
Assets, replacing Section 3062, Goodwill and Other Intangible Assets and
Section 3450, Research and Development Costs. The new Section will be
effective on January 1, 2009. Section 3064 establishes standards for the
recognition, measurement, presentation and disclosure of goodwill and
intangible assets subsequent to its initial recognition. Standards concerning
goodwill are unchanged from the standards included in the previous Section
3062. The Trust is currently evaluating the impact of the adoption of this new
Section, however does not expect a material impact on its Consolidated
Financial Statements.

    
    Convergence of Canadian GAAP with International Financial Reporting
    Standards ("IFRS")
    

    In 2006, Canada's Accounting Standards Board (AcSB) ratified a strategic
plan that will result in Canadian GAAP being converged with IFRS by 2011 for
public reporting entities. On February 13, 2008 the AcSB confirmed that IFRS
will be required for public companies beginning January 1, 2011.
    In order to meet our reporting requirements and transition to IFRS we
have established a project team comprised of individuals from Finance,
Information Systems and Business Solutions, Tax, Investor Relations and
Management. Our transition plan consists of four main phases:
    
    -   An IFRS diagnostic phase which involves an assessment of the
        differences between Canadian GAAP and IFRS,
    -   An assessment and selection phase whereby we will determine
        accounting policies for transition and our continuing IFRS accounting
        policies,
    -   An evaluation of our information systems, business processes,
        procedures and controls to support the new reporting standards, and
    -   Training and development.
    

    To date we have completed our IFRS diagnostic assessment and have started
to analyze and identify accounting policy choices, which include assessing the
impact on information systems and business processes. We have also provided
training to certain business groups which are impacted. We intend to generate
financial information in accordance with IFRS during 2010 to provide
comparative information for the 2011 financial statements.
    The transition from current Canadian GAAP to IFRS is a significant
undertaking that may materially affect our reported financial position and
results of operations. As we have not yet determined our accounting policies,
we are unable to quantify the impact of adopting IFRS on our financial
statements. In addition, due to anticipated changes to IFRS and International
Accounting Standards prior to our adoption of IFRS, our plan is subject to
change based on new facts and circumstances that arise after the date of this
MD&A.

    RISK FACTORS AND RISK MANAGEMENT

    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
have fluctuated widely in response to a variety of factors including global
and domestic demand, 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 crude oil price
    volatility. However, we do not hedge all of our production and expect
    there will always be a portion that remains un-hedged. Furthermore, we
    may use financial derivative 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.
    

    Credit Facility Risk and Credit Exposure

    Recent economic conditions have negatively affected the availability of
credit and increased the risk that certain counterparties for our oil and gas
sales, financial derivatives, and our operating partners may fail to pay.

    
    Enerplus has drawn only approximately 27% of its $1.4 billion bank credit
    facility at December 31, 2008. Also approximately 70% of the commitments
    under this facility are represented by major Canadian banks which are
    considered to be among the most sound credit providers. When the time
    comes to renew our banking facility we expect to pay higher rates and
    there is no guarantee that all our banks will renew at their current
    commitment levels.

    There are normal credit risks with receivables associated with our
    product sales, derivative contracts, insurers and joint venture partners.
    We mitigate these risks through diversification and review processes that
    assess and monitor our counterparties' credit worthiness on a regular
    basis. If the current low commodity prices and uncertain credit markets
    prevail there is a risk of increasing bad debts.

    See the "Liquidity and Capital Resources" section for further information
    related to our credit facility and credit exposure.
    

    Access to Capital Markets

    Historically 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. Recently,
with global capital markets in turmoil and the sharp decline in commodity
prices, we have chosen to reduce our reliance on the capital markets by
balancing the level of capital spending and distributions more closely to our
cash flow. Nonetheless, it will be difficult to pursue material acquisitions
and value creation opportunities without accessing the capital markets in the
future. We expect the debt markets will recover but the cost of debt financing
will increase and credit capacity may be tight for the next few years. The
equity capital markets are showing some signs of recovery however, equity
issues are generally at higher discounts and smaller sizes than previously
experienced. Equity market receptivity depends in large part upon the market's
expectation for oil and natural gas prices. Continued access to capital is
also 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.

    
    We are listed on the Toronto and New York stock exchanges and maintain 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.
    

    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 along with product price forecasts can affect the quantity
and quality of reserves and resources and the cost of ultimately recovering
those reserves and resources. Lower crude oil and natural gas prices may
increase the risk of write-downs for 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, 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. If we do engage in exploration it is usually
    in areas where there is potential for larger scale resource development
    if successful.

    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 93% 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 which Enerplus evaluated internally.
    Netherland, Sewell & Associates Inc. ("NSA") of Dallas, Texas, evaluated
    100% of the reserves attributed to our assets in the United States and
    utilized Sproule's forecast and constant price and cost assumptions as of
    December 31, 2008 to maintain consistency. GLJ Petroleum Consultants Ltd.
    ("GLJ") evaluated the resources attributable to all our oil sands areas.
    The Reserves Committee of the Board of Directors has reviewed and
    approved the reserve and resource reports of the independent evaluators.
    

    Strategy Post 2010

    We continue to evaluate alternatives to our income trust structure beyond
2010 in response to the Canadian Federal Government's plan to tax income
trusts effective January 1, 2011.
    We are currently hesitant to make structural changes for the next two
years unless opportunities arise, as we believe this exemption period has
value for our unitholders. Unless circumstances change within the current
capital markets or the regulatory, tax or political environment, we will most
likely convert into a dividend paying corporation however, we are keeping our
options open at this time.
    We do not expect the conversion to a corporation to have a major impact
on our underlying operating strategy or business affairs. We expect such a
conversion can be achieved without creating a taxable event for most
unitholders. However, going forward, the tax treatment of our distributions or
dividends may be different for our unitholders/shareholders depending on their
jurisdiction and whether they are holding their investment in a taxable
account or tax-deferred account.
    After 2010, the applicable Canadian income tax rate at the entity level
will be similar whether we remain a trust or convert to a corporation. The
most important variables that will determine the level of cash taxes incurred
in a given year will be the price of crude oil and natural gas, capital
spending and the amount of tax pools at the time of conversion.
    With the current forward market for commodity prices and our current
plans with respect to production, costs and capital spending, we would not
expect a significant change to our overall tax costs until 2013 even if we
were to convert to a corporation during 2010. Even after 2013 we expect our
capital spending will help shelter taxes and would expect cash taxes to
average around 15% of cash flow, which is not dissimilar to other oil and gas
production companies.
    If crude oil and natural gas prices were to strengthen beyond the levels
anticipated by the current forward market, our tax pools would be utilized
more quickly and we may experience higher than expected cash taxes.
    We must emphasize it is difficult to give guidance on future taxability
as we operate within an industry that constantly changes given acquisitions,
divestments, capital spending, distributions and overall commodity prices.

    Regulatory Risk

    Government royalties, income tax laws, environmental laws and regulatory
requirements can have a significant financial and operational impact on us. In
the province of Alberta a new royalty regime came into effect on January 1,
2009. The Canadian Federal Government enacted a new tax on publicly traded
income trusts and limited partnerships, the SIFT tax, effective January 1,
2011. In early 2008 the Canadian government presented a long term plan to
reduce greenhouse gas emissions, with the intent of issuing draft regulations
in the fall of 2008. The draft regulations have been delayed as the federal
government considers aligning its approach in this area with that of the new
administration in the U.S. Accordingly the cost impact to our business remains
uncertain.
    Our operations expose us to possible regulatory changes and greater
emphasis on regulatory requirements by both the 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 by participating in industry
    organizations, conferences, exchanging information with third party
    experts and employing qualified individuals to assess the impact of such
    changes on our financial and operating results. In 2008 we also initiated
    an extensive review of the regulatory compliance obligations across our
    full business in all jurisdictions. We intend to complete this review in
    2009.
    

    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. We
have reduced our capital spending plans dramatically for 2009 and this will
make it difficult to replace our production without relying on acquisitions.
Acquisitions of oil and gas assets depend on our assessment of value at the
time of acquisition. Incorrect assessments of value may 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.
    

    Access to Transportation Capacity

    Market access for crude oil and natural gas production in Canada and the
United States is dependent on our ability 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 transportation capacity is insufficient to accommodate all of the
production from a given region, causing added expense and/or volume
curtailments for all shippers.

    
    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 using other means
    of transportation.
    

    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.
    

    Foreign Currency Exposure

    We have exposure to fluctuations in foreign currency as our senior
unsecured notes are 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 positively impacted as the
Canadian dollar weakens relative to the U.S. dollar.

    
    We have hedged our foreign currency exposure on both our US$175 million
    and US$54 million 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.
    

    Interest Rate Exposure

    We have exposure to movements in interest rates and credit markets as
changing interest rates affect our borrowing costs and the trust unit price of
yield-based investments such as our trust units.

    
    We monitor the interest rate forward market and have fixed the interest
    rate on approximately 28% of our debt through our senior unsecured notes
    and interest rate swaps.
    

    Non-Resident Ownership and Mutual Fund Trust Status

    Based on information received from our transfer agent and financial
intermediaries in February 2009, an estimated 65% of our outstanding trust
units were held by non-residents. 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.

    
    We currently meet 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, we do not anticipate any legislative changes
    that would affect our status as a mutual fund trust.
    

    SUMMARY 2009 OUTLOOK

    Enerplus offers investors the benefits of owning a large, diversified
portfolio of producing crude 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 2009 outlook should be taken within the context of the
current commodity price environment.
    The following summarizes our 2009 guidance as provided throughout this
MD&A. We do not attempt to forecast commodity prices and, as a result, we do
not forecast future cash flow or cash distributions. Readers are encouraged to
apply their own price expectations to the following factors to arrive at an
expected cash distribution.

    
    Summary of 2009
    Expectations                Target            Comments
    -------------------------------------------------------------------------
    Average annual production   91,000 BOE/day    Does not include any
                                                  further potential
                                                  acquisitions/divestments

    Exit rate 2009 production   88,000 BOE/day    Assumes $300 million
                                                  development capital
                                                  spending

    2009 production mix         58% gas, 42%
                                liquids

    Average royalty rate        18%               Percentage of gross sales

    Operating costs             $10.65/BOE

    G&A costs                   $2.45/BOE         Includes non-cash charges
                                                  of $0.20/BOE (unit rights
                                                  incentive plan)

    U.S. income and             15%               Applied to net cash flow
     withholding tax - cash                       generated by U.S.
     costs                                        operations and assumes
                                                  repatriation of the funds
                                                  to Canada after U.S.
                                                  development capital
                                                  spending
    Average interest cost       3%                Based on current fixed rate
                                                  contracts and forward
                                                  market

    Payout ratio                50% - 75%         We intend to manage our
                                                  distributions and capital
                                                  spending in order to
                                                  minimize increases in debt
                                                  outside of acquisitions

    Development capital         $300 million      We intend to monitor
     spending                                     commodity prices and cost
                                                  structures and will adjust
                                                  capital spending in order
                                                  to minimize increases in
                                                  debt outside of
                                                  acquisitions
    -------------------------------------------------------------------------
    

    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. As a result, we have reduced our 2009 development
capital spending to $300 million, which is 48% lower than our 2008 spending.
We have also reduced our monthly distributions to unitholders to $0.18 per
trust unit and based on current commodity prices we do not expect to
materially increase our debt levels in 2009 outside of acquisition activities.
    We will continue to focus on low-risk development opportunities and
review our risk management strategies in response to changing prices, the
current economic environment and the economics of our acquisition and
development projects.
    For 2009, 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.


    
    CONSOLIDATED BALANCE SHEETS

    As at December 31 (CDN$ thousands)                     2008         2007
    -------------------------------------------------------------------------
    Assets
    Current assets
    Cash                                            $     6,922  $     1,702
    Accounts receivable                                 163,152      145,602
    Deferred financial assets (Note 12)                 121,281       10,157
    Future income taxes (Note 11)                             -       10,807
    Other current                                         3,783        6,373
    -------------------------------------------------------------------------
                                                        295,138      174,641
    Property, plant and equipment (Note 3)            5,246,998    3,872,818
    Goodwill (Note 1(f))                                634,023      195,112
    Deferred financial assets (Note 12)                   6,857            -
    Other assets                                         47,116       60,559
    -------------------------------------------------------------------------
                                                    $ 6,230,132  $ 4,303,130
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    Liabilities
    Current liabilities
    Accounts payable                                $   272,818  $   269,375
    Distributions payable to unitholders                 41,397       54,522
    Future income taxes (Note 11)                        30,198            -
    Deferred financial credits (Note 12)                      -       52,488
    -------------------------------------------------------------------------
                                                        344,413      376,385
    -------------------------------------------------------------------------
    Long-term debt (Note 7)                             664,343      726,677
    Deferred financial credits (Note 12)                 26,392       90,090
    Future income taxes (Note 11)                       648,821      304,259
    Asset retirement obligations (Note 4)               207,420      165,719
    -------------------------------------------------------------------------
                                                      1,546,976    1,286,745
    -------------------------------------------------------------------------
    Equity
    Unitholders' capital (Note 10)
    Trust Units and Trust Units Equivalent
    Authorized:             Unlimited
    Issued and Outstanding: 2008 - 165,590,240
                            2007 - 129,813,445        5,471,336    4,032,680

    Accumulated deficit                              (1,181,199)  (1,283,953)
    Accumulated other comprehensive income
     (Notes 1(i) and (j))                                48,606     (108,727)
    -------------------------------------------------------------------------
                                                     (1,132,593)  (1,392,680)
                                                      4,338,743    2,640,000
    -------------------------------------------------------------------------

                                                    $ 6,230,132  $ 4,303,130
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------



    CONSOLIDATED STATEMENTS OF ACCUMULATED DEFICIT

    For the year ended December 31 (CDN$ thousands)        2008         2007
    -------------------------------------------------------------------------

    Accumulated income, beginning of year           $ 2,286,927  $ 1,952,960
    Adjustment for adoption of financial
     instruments standards                                    -       (5,724)
    -------------------------------------------------------------------------
    Revised Accumulated income, beginning of year     2,286,927    1,947,236
    Net income                                          888,892      339,691
    -------------------------------------------------------------------------
    Accumulated income, end of year                   3,175,819    2,286,927
    Accumulated cash distributions, beginning of
     year                                            (3,570,880)  (2,924,045)
    Cash distributions                                 (786,138)    (646,835)
    -------------------------------------------------------------------------
    Accumulated cash distributions, end of year      (4,357,018)  (3,570,880)

    -------------------------------------------------------------------------
    Accumulated deficit, end of year                $(1,181,199) $(1,283,953)
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------



    CONSOLIDATED STATEMENTS OF ACCUMULATED OTHER COMPREHENSIVE INCOME

    For the year ended December 31 (CDN$ thousands)        2008         2007
    -------------------------------------------------------------------------

    Balance, beginning of year                      $  (108,727) $    (8,979)
      Transition adjustments:
        Cash flow hedges                                      -          660
        Available for sale marketable securities              -       14,252
      Other comprehensive (loss)/income                 157,333     (114,660)
    -------------------------------------------------------------------------
    Balance, end of year                            $    48,606  $  (108,727)
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------



    CONSOLIDATED STATEMENTS OF INCOME

    For the year ended December 31
     (CDN$ thousands except per trust
     unit amounts)                                         2008         2007
    -------------------------------------------------------------------------
    Revenues
    Oil and gas sales                               $ 2,331,884  $ 1,539,153
    Royalties                                          (429,943)    (285,148)
    Commodity derivative instruments (Note 12)           66,434      (52,841)
    Other income (Note 12)                                8,464       14,991
    -------------------------------------------------------------------------
                                                      1,976,839    1,216,155
    -------------------------------------------------------------------------
    Expenses
    Operating                                           332,622      274,150
    General and administrative                           65,667       67,921
    Transportation                                       27,650       22,098
    Interest (Note 8)                                    24,224       33,627
    Foreign exchange (Note 9)                            25,852       (7,071)
    Depletion, depreciation, amortization and
     accretion                                          640,440      463,718
    -------------------------------------------------------------------------
                                                      1,116,455      854,443
    -------------------------------------------------------------------------
    Income before taxes                                 860,384      361,712
    Current taxes                                        22,722       23,011
    Future income tax recovery (Note 11)                (51,230)        (990)
    -------------------------------------------------------------------------
    Net Income                                      $   888,892  $   339,691
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    Net income per trust unit
    Basic                                           $      5.54  $      2.66
    Diluted                                         $      5.53  $      2.66
    -------------------------------------------------------------------------
    Weighted average number of trust units
     outstanding (thousands)
    Basic                                               160,589      127,691
    Diluted                                             160,640      127,752
    -------------------------------------------------------------------------



    CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

    For the year ended December 31
     (CDN$ thousands)                                      2008         2007
    -------------------------------------------------------------------------
    Net income                                      $   888,892  $   339,691
    -------------------------------------------------------------------------
    Other comprehensive (loss)/income, net of tax:
      Unrealized gain on marketable securities            2,578          629
      Realized gains on marketable securities
       included in net income (Note 12 (b))              (6,158)     (11,302)
      Gains and losses on derivatives designated
       as hedges in prior periods included in net
       income                                                74         (733)
      Change in cumulative translation adjustment       160,839     (103,254)
    -------------------------------------------------------------------------
    Other comprehensive (loss)/income                   157,333     (114,660)

    -------------------------------------------------------------------------
    Comprehensive income                            $ 1,046,225  $   225,031
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------



    CONSOLIDATED STATEMENTS OF CASH FLOWS

    For the year ended December 31
     (CDN$ thousands)                                      2008         2007
    -------------------------------------------------------------------------
    Operating Activities
    Net income                                      $   888,892  $   339,691
    Non-cash items add/(deduct):
    Depletion, depreciation, amortization and
     accretion                                          640,440      463,718
    Change in fair value of derivative instruments
     (Note 12)                                         (240,085)      91,852
    Unit based compensation (Note 10 (d))                 6,996        8,435
    Foreign exchange on translation of senior
     notes (Note 9)                                      54,792      (41,182)
    Future income tax (Note 11)                         (51,230)        (990)
    Impairment of marketable securities                  10,000            -
    Amortization of senior notes premium                   (668)        (631)
    Reclassification adjustments from AOCI to net
     income and other                                        92         (865)
    Gain on sale of marketable securities (Note 12)      (8,263)     (14,055)
    Asset retirement obligations settled (Note 4)       (18,308)     (16,280)
    -------------------------------------------------------------------------
                                                      1,282,658      829,693
    Decrease/(Increase) in non-cash operating
     working capital                                    (19,876)      38,855
    -------------------------------------------------------------------------
    Cash flow from operating activities               1,262,782      868,548
    -------------------------------------------------------------------------

    Financing Activities
    Issue of trust units, net of issue costs
     (Note 10)                                           70,516      256,369
    Cash distributions to unitholders                  (786,138)    (646,835)
    (Decrease)/Increase in bank credit facilities
     (Note 7)                                          (447,371)     148,827
    Decrease in non-cash financing working capital      (13,125)       2,799
    -------------------------------------------------------------------------
    Cash flow from financing activities              (1,176,118)    (238,840)
    -------------------------------------------------------------------------
    Investing Activities
    Capital expenditures                               (588,337)    (393,655)
    Property acquisitions (Note 6)                      (15,306)    (226,480)
    Property dispositions (Note 6)                      504,859        2,947
    Proceeds on sale of marketable securities            18,320       16,467
    Purchase of investments                              (7,150)      (2,927)
    Increase in non-cash investing working capital       (1,618)     (21,046)
    -------------------------------------------------------------------------
    Cash flow from investing activities                 (89,232)    (624,694)
    -------------------------------------------------------------------------

    Effect of exchange rate changes on cash               7,788       (3,436)
    -------------------------------------------------------------------------
    Change in cash                                        5,220        1,578
    Cash, beginning of year                               1,702          124
    -------------------------------------------------------------------------
    Cash, end of year                               $     6,922  $     1,702
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    Supplementary Cash Flow Information
    Cash income taxes paid                          $    73,914  $    17,431
    Cash interest paid                              $    42,695  $    42,861



    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 ("Canadian GAAP"). A
    reconciliation between Canadian GAAP and United States of America GAAP
    ("U.S. GAAP") is disclosed in Note 15. 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 Computershare Trust Company of
    Canada. 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 price, volumes delivered and contractual delivery
    points. 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 is recognized in the period in
    which it occurs. Goodwill is stated at cost less impairment and is not
    amortized. Goodwill is not deductible for income tax purposes.

    (g) Asset Retirement Obligations

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

    (h) Income Taxes

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

    Effective January 1, 2011, the Fund will be subject to a 29.5% SIFT
    (specified investment flow-through) 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.

    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

    The Fund is exposed to market risks resulting from fluctuations in
    commodity prices, foreign exchange rates and interest rates in the normal
    course of operations. A variety of derivative instruments are used by the
    Fund to reduce its exposure to these risks. The Fund records its
    derivative instruments on the Consolidated Balance Sheet at fair value
    and recognizes any change in fair value through net income during the
    period. The fair values of these derivative instruments are generally
    based on an estimate of the amounts that would be received or paid to
    settle these instruments at the balance sheet date.

    The Fund has certain minor equity investments in entities involved in the
    oil and gas industry. Investments that have a quoted price in an active
    market are measured at fair value with changes in fair value recognized
    in other comprehensive income. When the investment is ultimately sold any
    gains or losses are recognized in net income and any unrealized gains or
    losses previously recognized in other comprehensive income are reversed.
    Investments that do not have a quoted price in an active market are
    measured at cost unless there has been an other than temporary
    impairment, in which case a charge is recognized in net income to record
    the loss in value.

    (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

    Current Year Accounting Changes

    Effective January 1, 2008, the Fund adopted three new accounting
    standards that were issued by the Canadian Institute of Chartered
    Accountants ("CICA"): Handbook Section 1535, Capital Disclosures, Section
    3862, Financial Instruments - Disclosures and Section 3863, Financial
    Instruments - Presentation.

    (a) Capital Disclosures

    Section 1535 establishes standards for disclosing information regarding
    an entity's capital and how it is managed.

    (b) Financial Instruments - Disclosures, Financial Instruments -
        Presentation

    Sections 3862 and 3863 establish standards for enhancing financial
    statements users' understanding of the significance of financial
    instruments to an entity's financial position, performance and cash
    flows. They require that entities provide disclosures regarding the
    nature and extent of risks arising from financial instruments to which
    they are exposed both during the reporting period and at the balance
    sheet date, as well as how the entities manage those risks.

    These standards were adopted prospectively.

    Future Accounting Changes

    (a) Goodwill and Intangible Assets

    In February 2008, the CICA issued Section 3064, Goodwill and Intangible
    Assets, replacing Section 3062, Goodwill and Other Intangible Assets and
    Section 3450, Research and Development Costs. The new Section will be
    effective on January 1, 2009. Section 3064 establishes standards for the
    recognition, measurement, presentation and disclosure of goodwill and
    intangible assets subsequent to its initial recognition. Standards
    concerning goodwill are unchanged from the standards included in the
    previous Section 3062. The Fund is currently evaluating the impact of the
    adoption of this new Section, however does not expect a material impact
    on its Consolidated Financial Statements.

    (b) Convergence of Canadian GAAP with International Financial Reporting
        Standards ("IFRS")

    In 2006, Canada's Accounting Standards Board (AcSB) ratified a strategic
    plan that will result in Canadian GAAP being converged with International
    Financial Reporting Standards (IFRS) by 2011 for public reporting
    entities. On February 13, 2008 the AcSB confirmed that IFRS will be
    required for public companies beginning January 1, 2011.

    3.  PROPERTY, PLANT AND EQUIPMENT

    ($ thousands)                                           2008        2007
    -------------------------------------------------------------------------
    Property, plant and equipment                     $8,497,206  $6,429,241
    Accumulated depletion, depreciation and accretion (3,250,208) (2,556,423)
    -------------------------------------------------------------------------
    Net property, plant and equipment                 $5,246,998  $3,872,818
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    Capitalized general and administrative ("G&A") expenses for 2008 of
    $21,766,000 (2007 - $17,185,000) are included in PP&E. The depletion and
    depreciation calculation includes future capital costs of $773,371,000
    (2007 - $521,650,000) as indicated in our reserve reports. Excluded from
    PP&E for the depletion and depreciation calculation is $257,608,000 (2007
    - $321,801,000) related to the Kirby oil sands project ("Kirby") which
    has not yet commenced commercial production. The 2007 amount included
    costs related to the Joslyn oil sands project which was sold in July,
    2008.

    An impairment test calculation was performed on a country by country
    basis on the PP&E values at December 31, 2008 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 estimated benchmark prices and the exchange
    rate used in the impairment tests for both Canadian and U.S. cost centers
    at December 31, 2008:


                                                                 Natural Gas
                                                       Edm Light 30 day spot
                         WTI Crude Oil(1) Exchange Rate Crude(1) @ AECO(1)
    Year                         US$/bbl    CDN$/US$    CDN$/bbl    CDN$/Mcf
    -------------------------------------------------------------------------
    2009                          $53.73       $0.80      $65.35       $6.82
    2010                           63.41        0.85       72.78        7.56
    2011                           69.53        0.85       79.95        7.84
    2012                           79.59        0.90       86.57        8.38
    2013                           92.01        0.95       94.97        9.20
    Thereafter(*)                 +2% yr        0.95      +2% yr      +2% yr
    -------------------------------------------------------------------------
    (1) Prices used in the impairment test were adjusted for commodity price
        differentials specific to the Fund
    (*) Escalation varies after 2013.

    4.  ASSET RETIREMENT OBLIGATIONS

    Total future asset retirement obligations were estimated by management
    based on the Fund's net ownership interest in wells and facilities,
    estimated costs to abandon and reclaim the wells and facilities, and the
    estimated timing of the costs to be incurred in future periods. The Fund
    has estimated the net present value of its total asset retirement
    obligations to be $207,420,000 at December 31, 2008 compared to
    $165,719,000 at December 31, 2007 based on a total undiscounted liability
    of $644,423,000 and $542,781,000 respectively. These payments are
    expected to be made over the next 66 years with the majority of costs
    incurred between 2039 and 2048. To calculate the present value of the
    asset retirement obligations for 2008 the Fund used a weighted credit-
    adjusted rate of approximately 6.1% and an inflation rate of 2.0%, (2007
    - 6.1% and 2.0%). Settlements during 2008 and 2007 approximated our
    estimates and as a result no gains or losses were recognized.

    Following is a reconciliation of the asset retirement obligations:

    ($ thousands)                                           2008        2007
    -------------------------------------------------------------------------
    Asset retirement obligations, beginning of year     $165,719    $123,619
    Corporate acquisition                                 36,784           -
    Changes in estimates                                   4,087      46,000
    Acquisition and development activity                   7,394       6,441
    Dispositions                                            (110)       (756)
    Asset retirement obligations settled                 (18,308)    (16,280)
    Accretion expense                                     11,854       6,695
    -------------------------------------------------------------------------
    Asset retirement obligations, end of year           $207,420    $165,719
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    5.  CORPORATE ACQUISITIONS

    Focus Energy Trust

    On February 13, 2008 Enerplus closed the acquisition of Focus Energy
    Trust ("Focus"). Under the plan of arrangement, Focus unitholders
    received 0.425 of an Enerplus trust unit for each Focus trust unit and
    Focus Exchangeable Limited Partnership Units became exchangeable into
    Enerplus trust units at the option of the holder on the basis of 0.425 of
    an Enerplus trust unit for each Focus Exchangeable Limited Partnership
    Unit. Total consideration was $1,366,494,000 consisting of 30,150,000
    trust units issued, 9,087,000 exchangeable limited partnership units
    assumed (convertible into 3,861,833 trust units) and transaction costs of
    $5,350,000. The Fund also assumed bank debt plus an estimated working
    capital deficit including certain transaction costs paid by Focus of
    $357,305,000.

    The acquisition has been accounted for using the purchase method of
    accounting and results from the operations of Focus from February 13,
    2008 onward have been included in the Fund's consolidated financial
    statements. The allocation of the consideration paid to the fair value of
    the assets acquired and liabilities assumed plus future income tax cost
    is summarized below:

    Net Assets Acquired ($ thousands)
    -------------------------------------------------------------------------
    Property, plant and equipment                                 $1,757,520
    Other assets                                                       4,566
    Goodwill                                                         403,588
    Working capital deficit                                          (26,393)
    Deferred financial credits                                        (5,919)
    Long-term debt                                                  (330,912)
    Asset retirement obligations                                     (36,784)
    Future income taxes                                             (399,172)
    -------------------------------------------------------------------------
    Total net assets acquired                                     $1,366,494
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    Consideration paid ($ thousands)
    -------------------------------------------------------------------------
    Trust units issued(1)                                         $1,206,593
    Exchangeable limited partnership units assumed(1)                154,551
    Transaction costs                                                  5,350
    -------------------------------------------------------------------------
    Total consideration paid                                      $1,366,494
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    (1) Recorded based on a fair value of $40.02 per trust unit

    6.  PROPERTY ACQUISITIONS AND DISPOSITIONS

    Joslyn Oil Sands Interest

    On July 31, 2008 the Fund disposed of its interest in the Joslyn oil
    sands project for net cash proceeds of $502,000,000.

    Kirby Oil Sands Project

    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)                                           2008        2007
    -------------------------------------------------------------------------
    Bank credit facilities (a)                          $380,888    $497,347
    Senior notes (b)
    US$175 million (issued June 19, 2002)                217,327     175,973
    US$54 million (issued October 1, 2003)                66,128      53,357
    -------------------------------------------------------------------------
    Total long-term debt                                $664,343    $726,677
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    (a) Unsecured Bank Credit Facility

    Enerplus has a $1.4 billion unsecured covenant based facility ($1.0
    billion at December 31, 2007) that matures November 18, 2010. The
    facility is extendible each year with a bullet payment required at
    maturity. At December 31, 2008 Enerplus had available credit of
    $1,019,112,000. Various borrowing options are available under the
    facility including prime based advances and bankers' acceptances. This
    facility carries floating interest rates that are expected to range
    between 55 and 110 basis points over bankers' acceptance rates, depending
    on Enerplus' ratio of senior debt to earnings before interest, taxes and
    non-cash items. The weighted average effective interest rate on the
    facility for the year ended December 31, 2008 was 3.8% (2007 - 5.1%).

    (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 cross
    currency interest rate swap ("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 dollar exchange rate was 0.74,
    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. In 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 CDN/US exchange rate of 0.98 or CDN$55,080,000.

    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. 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, 2008 the amortized cost of the
    US$175,000,000 senior notes was US$177,467,000.

    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)                                           2008        2007
    -------------------------------------------------------------------------
    Realized
      Interest on long-term debt                         $42,626     $41,934
    Unrealized
      Gain on cross currency interest rate swap          (27,559)     (7,340)
      Loss/(gain) on interest rate swaps                   9,825        (447)
      Amortization of the premium on senior unsecured
       notes                                                (668)       (631)
      Other                                                    -         111
    -------------------------------------------------------------------------
    Interest Expense                                    $ 24,224    $ 33,627
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    9.  FOREIGN EXCHANGE

    ($ thousands)                                           2008        2007
    -------------------------------------------------------------------------
    Realized
      Foreign exchange loss                             $ 23,881    $  1,909
    Unrealized
      Foreign exchange loss/(gain) on
       translation of U.S. dollar denominated
       senior notes                                       54,792     (41,182)
      Foreign exchange (gain)/loss on cross currency
       interest rate swap                                (45,539)     31,777
      Foreign exchange (gain)/loss on foreign exchange
       swaps                                              (7,282)        425
    -------------------------------------------------------------------------
    Foreign exchange loss/(gain)                        $ 25,852    $ (7,071)
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    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. UNITHOLDERS' CAPITAL

    Unitholders' capital as presented on the Consolidated Balance Sheets
    consists of trust unit capital, exchangeable partnership unit capital and
    contributed surplus.

    Unitholders' capital ($ thousands)                      2008        2007
    -------------------------------------------------------------------------
    Trust units                                      $ 5,328,629 $ 4,020,228
    Exchangeable limited partnership units               123,107           -
    Contributed surplus                                   19,600      12,452
    -------------------------------------------------------------------------
    Balance, end of year                             $ 5,471,336 $ 4,032,680
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    (a) Trust Units

    Authorized: Unlimited number of trust units

    (thousands)                          2008                    2007
    -------------------------------------------------------------------------
    Issued:                        Units      Amount       Units      Amount
    -------------------------------------------------------------------------
    Balance before Contributed
     Surplus, beginning of year  129,813  $4,020,228     123,151  $3,706,821
    Issued for cash:
    Pursuant to public offerings       -           -       4,250     199,558
    Pursuant to rights
     incentive plan                  210       6,755         205       6,758
    Cancelled trust units           (116)     (3,794)          -           -
    Exchangeable limited
     partnership units exchanged     786      31,444           -           -
    Trust unit rights incentive
     plan (non-cash) - exercised       -       3,642           -       2,288
    DRIP(*), net of redemptions    1,671      63,761       1,102      50,053
    Issued for acquisition of
     corporate and property
     interests (non-cash)         30,150   1,206,593       1,105      54,750
    -------------------------------------------------------------------------
                                 162,514   5,328,629     129,813   4,020,228
    Equivalent exchangeable
     partnership units             3,076     123,107           -           -
    -------------------------------------------------------------------------
    Balance, end of year         165,590  $5,451,736     129,813  $4,020,228
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    (*) Distribution Reinvestment and Unit Purchase Plan

    On February 13, 2008 the Fund issued 30,150,000 trust units pursuant to
    the Focus acquisition valued at $40.02 per trust unit, being the weighted
    average trading price of the Fund's units on the Toronto Stock Exchange
    during the five day trading period surrounding the announcement date of
    December 3, 2007, for a recorded value of $1,206,593,000.

    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).

    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.

    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) Exchangeable Limited Partnership Units

    In conjunction with the Focus acquisition 9,087,000 Exchangeable Limited
    Partnership Units issued by Focus Limited Partnership (since renamed
    Enerplus Exchangeable Limited Partnership) became exchangeable into
    Enerplus trust units at a ratio of 0.425 of an Enerplus trust unit for
    each limited partnership unit (3,862,000 trust units). The exchangeable
    limited partnership units are convertible at any time into trust units at
    the option of the holder and receive cash distributions and have voting
    rights in accordance with the 0.425 exchange ratio. The Board of
    Directors may redeem the exchangeable limited partnership units after
    January 8, 2017, unless certain conditions are met to permit an earlier
    redemption date. The exchangeable limited partnership units are not
    listed on any stock exchange and are not transferable. The exchangeable
    limited partnership units were recorded at fair value, based on
    Enerplus' five day weighted average trust unit trading price surrounding
    the December 3, 2007 announcement date of $40.02 multiplied by the 0.425
    exchange ratio.

    During the period February 13, 2008 to December 31, 2008, 1,849,000
    exchangeable limited partnership units were converted into 786,000 trust
    units. As at December 31, 2008, the 7,238,000 outstanding exchangeable
    limited partnership units represent the equivalent of 3,076,000 trust
    units.

    (thousands)                          2008                    2007
    Issued:                        Units      Amount       Units      Amount
    -------------------------------------------------------------------------
    Assumed on February 13, 2008   9,087    $154,551           -     $     -
    Exchanged for trust units     (1,849)    (31,444)          -           -
    -------------------------------------------------------------------------
    Balance, end of period         7,238    $123,107           -     $     -
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    (c) Contributed Surplus

    Contributed surplus ($ thousands)                       2008        2007
    -------------------------------------------------------------------------
    Balance, beginning of year                          $ 12,452    $  6,305
    Trust unit rights incentive plan (non-cash) -
     exercised                                            (3,642)     (2,288)
    Trust unit rights incentive plan (non-cash) -
     expensed                                              6,996       8,435
    Cancelled trust units                                  3,794           -
    -------------------------------------------------------------------------
    Balance, end of year                                $ 19,600    $ 12,452
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    (d) Trust Unit Rights Incentive Plan

    As at December 31, 2008 a total of 4,001,000 rights issued pursuant to
    the Trust Unit Rights Incentive Plan ("Rights Incentive Plan") were
    outstanding at an average exercise price of $45.05. This represents 2.4%
    of the total trust units outstanding, of which 2,024,000 rights, with an
    average exercise price of $46.44, 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, 2008 reduced the exercise price of the outstanding rights by
    $1.65 per trust unit of which a $0.59 reduction is effective January 2009
    and a $0.22 reduction is effective April 2009. 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 result in higher
    after tax proceeds for the plan member.

    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:

                                                            2008        2007
    -------------------------------------------------------------------------
    Dividend yield                                        12.09%      10.37%
    Volatility                                            27.12%      26.35%
    Risk-free interest rate                                2.90%       4.41%
    Forfeiture rate                                        7.30%       6.20%
    Right's exercise price reduction                      $1.91       $1.75
    -------------------------------------------------------------------------

    The fair value of the rights granted under the plan during 2008 and 2007
    ranged between 9% and 12% of the underlying market price of a trust unit
    on the grant date.

    During the year the Fund expensed $6,996,000 or $0.04 per unit (2007 -
    $8,435,000 or $0.07 per unit) of unit based compensation expense using
    the fair value method. The remaining future fair value of the rights of
    $4,678,000 at December 31, 2008 (2007 - $6,195,000) 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:

                                        2008                    2007
    -------------------------------------------------------------------------
                                            Weighted                Weighted
                                             Average                 Average
                               Number of    Exercise     Number of  Exercise
                           Rights (000's)   Price(1) Rights (000's)  Price(1)
    -------------------------------------------------------------------------
    Trust unit rights
     outstanding
    Beginning of year              3,404      $47.59       3,079      $48.53
      Granted                      1,403       42.00         816       48.71
      Exercised                     (210)      32.22        (205)      32.90
      Forfeited and expired         (596)      44.94        (286)      50.74
    -------------------------------------------------------------------------
    End of year                    4,001      $45.05       3,404      $47.59
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    Rights exercisable at
     the end of the year           2,024      $46.44       1,635      $44.84
    -------------------------------------------------------------------------
    (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, 2008. Rights vest between one and three years
    and expire between four and six years.

                                                                      Rights
                                         Exercise                Exercisable
    Rights Outstanding at   Original  Price after                at December
        December 31, 2008   Exercise        Price    Expiry Date    31, 2008
                  (000's)      Price   Reductions    December 31      (000's)
    -------------------------------------------------------------------------
                       4       33.00        23.85           2009           4
                       2       36.00        27.23           2009           2
                      57       37.62        29.24           2009          57
                       3       40.70        32.71    2009 - 2010           3
                      17       37.25        29.63    2009 - 2010          17
                      21       38.83        31.61    2009 - 2010          21
                     231       40.80        33.93    2009 - 2010         231
                      37       45.55        39.00    2009 - 2011          37
                      62       44.86        38.66    2009 - 2011          62
                      74       49.75        43.95    2009 - 2011          74
                     499       56.93        51.54    2009 - 2011         499
                      98       56.55        51.64    2010 - 2012          74
                     352       54.21        49.80    2010 - 2012         254
                     211       56.00        52.10    2010 - 2012         166
                     400       52.90        49.51    2010 - 2012         283
                     133       48.86        45.97    2011 - 2013          55
                     394       50.25        47.87    2011 - 2013         138
                     124       45.14        43.27    2011 - 2013          43
                      13       38.70        37.35    2011 - 2013           4
                   1,142       42.05        41.21    2012 - 2014           -
                      73       47.19        46.78    2012 - 2014           -
                      35       38.76        38.76    2012 - 2014           -
                      19       23.58        23.58    2012 - 2014           -
    -------------------------------------------------------------------------
                   4,001     $ 48.28      $ 45.05                      2,024
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    (e) Basic and Diluted per Trust Unit Calculations

    Basic per-unit calculations are calculated using the weighted average
    number of trust units and exchangeable limited partnership units
    (converted at the 0.425 exchange ratio) outstanding during the period.
    Diluted per-unit calculations include additional trust units for the
    dilutive impact of rights outstanding pursuant to the Rights Incentive
    Plan.

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

    (thousands)                                             2008        2007
    -------------------------------------------------------------------------
    Weighted average units                               160,589     127,691
    Dilutive impact of rights                                 51          61
    -------------------------------------------------------------------------
    Diluted trust units                                  160,640     127,752
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    In 2008 we excluded 837,961 rights because their exercise price was
    greater than the annual average unit market price of $38.49. In 2007 we
    excluded 222,347 rights because their exercise price was greater than the
    annual average unit market price of $47.11.

    (f) 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.

    For the year ended December 31, 2008 the Fund recorded compensation costs
    of $8,448,000 (2007 - $1,934,000) under the plan which are included in
    general and administrative expenses.

    During 2008 282,000 PTU's were granted and at December 31, 2008 there
    were 410,000 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 2008, the Fund had taxable income of $763,000,000 (2007 -
    $632,000,000) or $4.81 per trust unit (2007 - $4.92 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 2008. The amounts
    of COGPE and issue costs in the fund remaining as at December 31, 2008
    are $466,700,000 and $17,185,000 respectively.

    Canadian Government's tax on income trusts

    In 2007, the Canadian Federal government enacted tax legislation which
    imposed a tax at a rate equivalent to the corporate tax rate on publicly
    traded trusts in Canada effective January 1, 2011.

    In 2008, the Canadian Federal government introduced draft tax legislation
    that would have allowed for the conversion of a SIFT into a corporation
    on a Canadian tax deferred basis; defined the provincial tax component of
    the SIFT tax; and accelerated the recognition of the "Safe Harbour"
    limit. None of the above draft legislations were enacted prior to the
    prorogation of Parliament in December 2008. Therefore, all bills
    containing the draft legislation lapsed in 2008.

    Subsequent to the year end, the Canadian Federal government has
    introduced draft tax legislation which includes the above mentioned
    measures as part of Canada's Economic Action Plan.

    We continue to evaluate alternatives to our income trust structure beyond
    2010. We are currently hesitant to make structural changes as we believe
    that the exemption period until 2011 has value for our unitholders. While
    we are keeping our options open, we will most likely convert into a
    dividend paying corporation prior to the end of 2010.

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

                                                                        2008
    ($ thousands)                           Canadian     Foreign       Total
    -------------------------------------------------------------------------
    Excess of net book value of property,
     plant and equipment over the
     underlying tax bases                  $ 479,753   $ 200,837   $ 680,590
    Asset retirement obligations             (53,057)          -     (53,057)
    Deferred financial assets and other       51,218         268      51,486
    -------------------------------------------------------------------------
    Future income taxes                    $ 477,914   $ 201,105   $ 679,019
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    Current future income tax liability    $  30,198   $       -   $  30,198
    Long-term future income tax liability  $ 447,716   $ 201,105   $ 648,821
    -------------------------------------------------------------------------

                                                                        2007
    ($ thousands)                           Canadian     Foreign       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)
    -------------------------------------------------------------------------
    Future income taxes                    $ 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
    -------------------------------------------------------------------------

    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)                                           2008        2007
    -------------------------------------------------------------------------
    Income before taxes                                $ 860,384   $ 361,712
    -------------------------------------------------------------------------
    Computed income tax expense at the enacted rate
     of 29.94% (32.41% for 2007)                       $ 257,599   $ 117,231
    Increase/(decrease) resulting from:
    Net income attributed to the Fund                   (213,871)   (162,016)
    Recognition of previously unrecognized pools         (13,405)          -
    Non-taxable portion of (gains)/losses                (45,495)          -
    Amended returns and pool balances                     (7,464)      5,150
    Change in tax rate                                    (2,700)    (22,640)
    SIFT Tax                                                   -      78,110
    Other                                                 (3,172)      6,186
    -------------------------------------------------------------------------
                                                       $ (28,508)  $  22,021
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    Future income tax recovery                         $ (51,230)  $    (990)
    Current tax                                        $  22,722   $  23,011
    -------------------------------------------------------------------------

    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, 2008 ($ thousands)         Canadian     Foreign       Total
    -------------------------------------------------------------------------
    Future income tax (recovery)/expense   $ (52,706)   $  1,476   $ (51,230)
    Current income tax (recovery)/expense    (25,069)     47,791      22,722
    -------------------------------------------------------------------------

    For the year ended
    December 31, 2007 ($ thousands)         Canadian     Foreign       Total
    -------------------------------------------------------------------------
    Future income tax (recovery)/expense   $  (8,183)   $  7,193   $    (990)
    Current income tax                             -      23,011      23,011
    -------------------------------------------------------------------------

    12. FINANCIAL INSTRUMENTS AND RISK MANAGEMENT

    (a) Fair Value of Financial Instruments

    As a result of the adoption of the new financial instrument and hedging
    accounting standards on January 1, 2007, 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, considering credit risk. 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.

    (b) Carrying Value and Fair Value of Non-Derivative 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, 2008 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. During the
    first quarter of 2008 the Fund recorded an unrealized gain on certain
    publicly traded marketable securities of $3,645,000 ($2,578,000 net of
    tax) which was recorded in accumulated other comprehensive income. These
    marketable securities were then sold, which resulted in a gain of
    $8,263,000 ($6,158,000 net of tax) being reclassified from accumulated
    other comprehensive income to other income on the Consolidated Statement
    of Income. 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) which was also reclassified from accumulated
    other comprehensive income to other income on the Consolidated Statement
    of Income.

    As at December 31, 2008 the Fund did not hold any investments in publicly
    traded marketable securities. As at December 31, 2007 the Fund reported
    investments in publicly traded marketable securities at a fair value of
    $14,676,000.

    Marketable securities without a quoted market price in an active market
    are reported at cost unless an other than temporary impairment exists. In
    the fourth quarter of 2008 the Fund reduced the carrying value of an
    investment in a private company to nil resulting in a charge of
    $10,000,000 to the income statement. As at December 31, 2008 the Fund
    reported investments in marketable securities of private companies at a
    cost of $47,116,000 (December 31, 2007 - $45,400,000) in 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, 2008 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, 2008 the carrying value of the bank
    credit facility approximated its fair value.

    US$175 million senior notes

    The US$175,000,000 senior notes, which are classified as other
    liabilities, are reported at amortized cost of US$177,467,000 and are
    translated to Canadian dollars at the period end exchange rate. At
    December 31, 2008 the Canadian dollar amortized cost of the senior notes
    was approximately $217,327,000 and the fair value of these notes was
    $205,942,000.

    US$54 million senior notes

    The US$54,000,000 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, 2008 the Canadian dollar amortized cost of the senior notes
    was approximately $66,128,000 and the fair value of these notes was
    $60,485,000.

    c)  Fair Value of Derivative Financial Instruments

    The Fund's derivative financial instruments are classified as held for
    trading and are reported at fair value with changes in fair value
    recorded through earnings. The deferred financial assets and credits on
    the Consolidated Balance Sheets result from recording derivative
    financial instruments at fair value. At December 31, 2008 a current
    deferred financial asset of $121,281,000, a non-current deferred
    financial asset of $6,857,000 and a non-current deferred financial credit
    of $26,392,000 are recorded on the consolidated balance sheet.

    The deferred financial asset relating to crude oil instruments of
    $96,641,000 at December 31, 2008 represents a gain position of
    $117,428,000 less the related deferred premiums of $20,787,000. The
    deferred financial asset relating to natural gas instruments of
    $24,292,000 at December 31, 2008 represents a gain position of
    $41,953,000 less the related deferred premiums of $17,661,000.

    The following table summarizes the fair value as at December 31, 2008 and
    change in fair value for the period ended December 31, 2008. The fair
    values indicated below are determined using observable market data
    including price quotations in active markets.


                                             Cross
                                          Currency      Foreign
                             Interest     Interest     Exchange  Electricity
    ($ thousands)          Rate Swaps   Rate Swaps        Swaps        Swaps
    -------------------------------------------------------------------------
    Deferred financial
     (credits)/assets,
     at the beginning of
     period               $      (226) $   (89,439) $      (425) $       451

    Change in fair value
     (credits)/asset        (9,825)(3)    73,098(4)     7,282(5)     (103)(6)
    -------------------------------------------------------------------------

    Deferred financial
     (credits)/assets,
     end of period        $   (10,051) $   (16,341) $     6,857  $       348
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    Balance sheet
     classification:

    Current
     (liability)/asset    $         -  $         -  $         -  $       348
    Non-current
     (liability)/asset    $   (10,051) $   (16,341) $     6,857  $         -
    -------------------------------------------------------------------------


                                     Commodity
                                     Derivative
                                    Instruments
                                --------------------
    ($ thousands)                 Oil          Gas        Total
    -------------------------------------------------------------
    Deferred financial
     (credits)/assets,
     at the beginning of
     period               $(56,783)(1) $   8,083(2) $  (138,339)

    Change in fair value
     (credits)/asset        153,424(7)    16,209(7)     240,085
    -------------------------------------------------------------

    Deferred financial
     (credits)/assets,
     end of period        $    96,641  $    24,292  $   101,746
    -------------------------------------------------------------
    -------------------------------------------------------------

    Balance sheet
     classification:

    Current
     (liability)/asset    $    96,641  $    24,292  $   121,281
    Non-current
     (liability)/asset    $         -  $         -  $   (19,535)
    -------------------------------------------------------------

    (1) Includes the Focus opening credit balance at February 13, 2008 of
        $4,295.
    (2) Includes the Focus opening credit balance at February 13, 2008 of
        $1,624.
    (3) Recorded in interest expense.
    (4) Recorded in foreign exchange expense (gain of $45,539) and interest
        expense (gain of $27,559).
    (5) Recorded in foreign exchange expense.
    (6) Recorded in operating expense.
    (7) Recorded in commodity derivative instruments (see below).

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

    ($ thousands)                                           2008        2007
    -------------------------------------------------------------------------
    Gain/(loss) due to change in fair value            $ 169,631   $ (66,393)
    Net realized cash (losses)/gain                     (103,197)     13,552
    -------------------------------------------------------------------------
    Commodity derivative instruments gain/(loss)       $  66,434   $ (52,841)
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    (d) Risk Management

    The Fund is exposed to a number of financial risks including market,
    counterparty credit and liquidity risk. Risk management policies have
    been established by the Fund's Board of Directors to assist in managing a
    portion of these risks, with the goal of protecting earnings, cash flow
    and unitholder value.

    i.  Market Risk

    Market risk is comprised of commodity price risk, currency risk and
    interest rate risk.

    Commodity Price Risk
    --------------------

    The Fund is exposed to commodity price fluctuations as part of its normal
    business operations, particularly in relation to its crude oil and
    natural gas sales. The Fund manages a portion of these risks through a
    combination of financial derivative and physical delivery sales
    contracts. The Fund's policy is to enter into commodity contracts
    considered appropriate to a maximum of 80% of forecasted production
    volumes net of royalties. The Fund's outstanding commodity derivative
    contracts as at February 18, 2009 are summarized below:

    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, 2008 the fair value of these contracts represented
    an asset of $96,641,000 and the change in fair value of these contracts
    during 2008 represented an unrealized gain of $153,424,000.

    The following table summarizes the Fund's crude oil risk management
    positions at February 18, 2009:

                                                 WTI US$/bbl
                              -----------------------------------------------
                Daily Volumes                                    Fixed Price
                     bbls/day  Sold Call  Purchased Put  Sold Put  and Swaps
    -------------------------------------------------------------------------
    Term
    January
     1, 2009 -
     December
     31, 2009
      Put               1,400          -        $122.00         -          -
      Put               1,000          -        $120.00         -          -
      Put                 500          -        $116.00         -          -
      Collar              850    $100.00        $ 85.00         -          -
      Collar            1,000          -        $ 92.00   $ 79.00          -
      3-Way option      1,000    $ 85.00        $ 70.00   $ 57.50          -
      3-Way option      1,000    $ 95.00        $ 79.00   $ 62.00          -
      Swap                500          -              -         -    $100.05
    -------------------------------------------------------------------------

    Natural Gas Instruments:

    Enerplus has certain financial contracts outstanding as at February 18,
    2009 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, 2008 the fair value of these contracts
    represented an asset of $24,292,000 and the change in fair value of these
    contracts during 2008 represented an unrealized gain of $16,209,000.

    The following table summarizes the Fund's natural gas risk management
    positions at February 18, 2009:

                                         AECO CDN$/Mcf
                Daily
              Volumes  Purchased            Purchased            Fixed Price
             MMcf/day       Call  Sold Call       Put   Sold Put   and Swaps
    -------------------------------------------------------------------------
    Term
    January
     1, 2009 -
     March 31,
     2009
      Put          4.7         -         -      $11.34         -         -
      Put          4.7         -         -      $11.61         -         -
      Put          4.7         -         -      $ 9.50         -         -
      Call         5.7    $ 9.50         -           -         -         -
      Collar       3.8         -    $ 9.50      $ 8.44         -         -
      Collar       1.9         -    $ 9.50      $ 8.44         -         -
      Collar       4.7         -         -      $ 8.97    $ 7.39         -
      Collar       4.7         -         -      $ 8.97    $ 7.39         -
      3-Way
       option      5.7         -    $10.71      $ 7.91    $ 5.80         -
      3-Way
       option      1.9         -    $10.55      $ 8.44    $ 6.33         -
      3-Way
       option      5.7         -    $10.71      $ 8.44    $ 6.33         -
      3-Way
       option     14.2         -    $12.45      $ 8.97    $ 7.39         -
      Swap         2.8         -         -           -         -    $ 9.42
      Swap         2.8         -         -           -         -    $ 9.28
      Swap         2.8         -         -           -         -    $ 9.34
    April 1,
     2009 -
     October
     31, 2009
      Put          9.5         -         -      $ 8.44         -         -
      Put(1)      14.2         -         -      $ 7.70         -         -
      Put(1)       2.8         -         -      $ 7.78         -         -
      Put(1)       4.7         -         -      $ 7.87         -         -
      Put(1)       4.7         -         -      $ 7.72         -         -
      Collar       2.8         -         -      $ 9.23    $ 7.65         -
      Collar       2.8         -         -      $ 9.50    $ 7.91         -
      Collar       5.7         -         -      $ 9.60    $ 7.91         -
      Swap         3.8         -         -           -         -    $ 7.86
    April 1,
     2009 -
     October
     31, 2010
      Swap(1)     23.7         -         -           -         -    $ 7.33
    November 1,
     2009 -
     March 31,
     2010
      Put(1)       9.5         -         -      $ 8.97         -         -
      Put(1)       2.8         -         -      $ 9.07         -         -
      Put(1)       9.5         -         -      $ 9.06         -         -
      Call(1)      4.7         -   $ 12.13           -         -         -
    2009 - 2010
      Physical     2.0         -         -           -          -   $ 2.67
    -------------------------------------------------------------------------
    (1) Financial contracts entered into during the fourth quarter of 2008.

    The following sensitivities show the impact to after-tax net income of
    the respective changes in forward crude oil and natural gas prices as at
    December 31, 2008 on the Fund's outstanding commodity derivative
    contracts at that time with all other variables held constant:

                               Increase / (decrease) to after-tax net income
                               ----------------------------------------------
                                           25% decrease in   25% increase in
    ($ thousands)                           forward prices    forward prices
    -------------------------------------------------------------------------
    Crude oil derivative contracts                $ 19,157         $ (19,839)
    Natural gas derivative contracts              $ 29,565         $ (27,481)

    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, 2008 the fair value of these
    contracts represented an asset of $348,000 and the change in fair value
    of these contracts during 2008 represented an unrealized loss of
    $103,000.

    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 18, 2009.

                                                       Volumes       Price
    Term                                                 MWh       CDN$/MWh
    -------------------------------------------------------------------------
    January 1, 2009 - December 31, 2009                    4.0       $74.50
    January 1, 2009 - December 31, 2010                    4.0        77.50
    -------------------------------------------------------------------------

    Currency Risk
    -------------

    The Fund is exposed to currency risk in relation to its U.S. dollar cash
    balances and U.S. dollar denominated senior unsecured notes. The Fund
    generally maintains a minimal amount of U.S. dollar cash and manages the
    currency risk relating to the senior unsecured notes through the currency
    derivative instruments that are detailed below.

    Cross Currency Interest Rate Swap ("CCIRS")

    Concurrent with the issuance of the US$175,000,000 senior 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%.

    Foreign Exchange Swaps

    In September 2007 the Fund entered into foreign exchange swaps on
    US$54,000,000 of notional debt at an average CDN/US foreign exchange rate
    of 0.98. 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 following sensitivities show the impact to after-tax net income of
    the respective changes in the period end and applicable forward foreign
    exchange rates as at December 31, 2008, with all other variables held
    constant:

                                                       Increase/(decrease)
                                                     to after-tax net income
                                                  ---------------------------
                                                  25% decrease  25% increase
                                                      in $CDN       in $CDN
                                                     relative      relative
    ($ thousands)                                      to $US        to $US
    -------------------------------------------------------------------------
    Translation of US$54 million senior notes       $ (11,582)    $  11,582
    Translation of US$175 million senior notes        (38,099)       38,099
    -------------------------------------------------------------------------
    Total                                           $ (49,681)    $  49,681


                                                      Increase/(decrease)
                                                    to after-tax net income
                                                  ---------------------------
                                                  25% decrease  25% increase
                                                      in $CDN       in $CDN
                                                     relative      relative
    ($ thousands)                                      to $US        to $US
    -------------------------------------------------------------------------
    Foreign exchange swaps                          $    9,513    $   (9,840)
    Cross currency interest rate swap(1)                34,183       (34,186)
    -------------------------------------------------------------------------
    Total                                           $   43,696    $  (44,026)
    (1) Represents change due to foreign exchange rates only

    Interest Rate Risk
    ------------------

    The Fund's cash flows are impacted by fluctuations in interest rates as
    its outstanding bank debt carries floating interest rates and payments
    made under the CCIRS are based on floating interest rates. To manage a
    portion of interest rate risk relating to the bank debt, the Fund has
    entered into interest rate swaps on $120,000,000 of notional debt at
    rates varying from 3.70% to 4.61% that mature between June 2011 and
    July 2013.

    If interest rates change by 1%, either lower or higher, on our variable
    rate debt outstanding at December 31, 2008 with all other variables held
    constant, the Fund's after-tax net income for a quarter would change by
    $927,000.

    The following sensitivities show the impact to after-tax net income of
    the respective changes in the applicable forward interest rates as at
    December 31, 2008, with all other variables held constant:

                                                      Increase/(decrease)
                                                    to after-tax net income
                                                  ---------------------------
                                                  25% decrease  25% increase
                                                   in forward    in forward
                                                     interest      interest
    ($ thousands)                                       rates         rates
    -------------------------------------------------------------------------
    Interest rate swaps                             $     (990)   $      990
    Cross currency interest rate swap(1)                 3,451        (3,451)
                                                  ---------------------------
    Total                                           $    2,461    $   (2,461)
    (1)   Represents change due to interest rates only

    ii. Credit Risk

    Credit risk represents the financial loss the Fund would experience due
    to the potential non-performance of counterparties to our financial
    instruments. The Fund is exposed to credit risk mainly through its joint
    venture, marketing and financial counterparty receivables.

    The Fund mitigates credit risk through credit management techniques,
    including conducting financial assessments to establish and monitor a
    counterparty's credit worthiness, setting exposure limits, monitoring
    exposures against these limits and obtaining financial assurances such as
    letters of credit, parental guarantees, or third party credit insurance
    where warranted. The Fund monitors and manages its concentration of
    counterparty credit risk on an ongoing basis.

    The Fund's maximum credit exposure at the balance sheet date consists of
    the carrying amount of its non-derivative financial assets as well as the
    fair value of its derivative financial assets. At December 31, 2008
    approximately 95% of our marketing receivables were with companies
    considered investment grade or just below investment grade. This level of
    credit concentration is typical of oil and gas companies of our size
    producing in similar regions.

    At December 31, 2008 approximately $7,453,000 or 5% of our total accounts
    receivable are aged over 120 days and considered past due. The majority
    of these accounts are due from various joint venture partners. The Fund
    actively monitors past due accounts and takes the necessary actions to
    expedite collection, which can include withholding production or net
    paying when the accounts are with joint venture partners. Should the Fund
    determine that the ultimate collection of a receivable is in doubt, it
    will provide the necessary provision in its allowance for doubtful
    accounts with a corresponding charge to earnings. If the Fund
    subsequently determines an account is uncollectible the account is
    written off with a corresponding charge to the allowance account. The
    Fund's allowance for doubtful accounts balance at December 31, 2008 is
    $5,352,000 which includes a $2,500,000 provision made during during the
    year. There were no accounts written off during the year.

    iii. Liquidity Risk & Capital Management

    Liquidity risk represents the risk that the Fund will be unable to meet
    its financial obligations as they become due. The Fund mitigates
    liquidity risk through actively managing its capital, which it defines as
    long-term debt (net of cash) and unitholders' capital. Enerplus'
    objective is to provide adequate short and longer term liquidity while
    maintaining a flexible capital structure to sustain the future
    development of the business. The Fund strives to balance the portion of
    debt and equity in its capital structure given its current oil and gas
    assets and planned investment opportunities.

    Management monitors a number of key variables with respect to its capital
    structure, including debt levels, capital spending plans, distributions
    to unitholders, access to capital markets, as well as acquisition and
    divestment activity.

    Debt Levels
    -----------

    The Fund commonly measures its debt levels relative to its "debt-to-cash
    flow ratio" which is defined as long-term debt (net of cash) divided by
    the trailing twelve month cash flow from operating activities. The debt
    to-cash flow ratio represents the time period, expressed in years, it
    would take to pay off the debt if no further capital investments were
    made or distributions paid and if cash flow from operating activities
    remained constant.

    At December 31, 2008 the debt to cash flow ratio was 0.5x (December 31,
    2007 - 0.8x).  Enerplus' bank credit facilities and senior debenture
    covenants carry a maximum debt-to-cash flow ratio of 3.0x including cash
    flow from acquisitions on a pro-forma basis.  Traditionally Enerplus has
    managed its debt levels such that the debt-to-cash flow ratio has been
    below 1.5x, which has provided flexibility in pursuing acquisitions and
    capital projects. Enerplus' five-year history of debt to cash flow is
    illustrated below:

                                        2008    2007    2006    2005    2004
                                   ------------------------------------------
    Debt-to-Cash Flow Ratio             0.5x    0.8x    0.8x    0.8x    1.1x

    At December 31, 2008 Enerplus had additional borrowing capacity of
    $1,019,112,000 under its $1,400,000,000 bank credit facility. Enerplus
    does not have any subordinated or convertible debt outstanding at this
    time.

    Capital Spending Plans
    ----------------------

    In 2009 Enerplus expects to spend approximately $300,000,000 on
    development capital activities. A portion of this capital spending is
    considered discretionary. There are limitations to changing the capital
    spending plans during a year as long project lead times, economies of
    scale, logistical considerations and partner commitments reduce the
    ability to adjust or down-size the capital program. Alternatively, the
    ability to rapidly increase spending may be limited by staff capacity,
    availability of services and equipment, access to sites, and regulatory
    approvals.

    Distributions to Unitholders
    ----------------------------

    Enerplus distributes a portion of its cash flow to its unitholders every
    month. These distributions are not guaranteed and the board of directors
    can change the amount at any time. During periods of sustained commodity
    price declines, distributions have been reduced. Similarly, in periods of
    sustained higher commodity prices, distributions have increased. To the
    extent that cash flow exceeds distributions additional funds are
    available to reduce debt, invest in capital development programs or
    finance acquisitions. The less cash required to finance these activities
    typically means more cash available for distributions and vice versa.

    By paying distributions, we effectively earn a tax deduction against the
    corporate taxes in our underlying subsidiaries and pass along the
    Canadian tax liability to our unitholders. If distributions are lowered
    and too much cash flow is retained within the structure there is a risk
    that tax obligations in the operating entities may be created thereby
    eroding the flow-through advantage of the trust structure.

    Access to Capital Markets
    -------------------------

    Enerplus relies on both the debt and equity markets to manage its cost of
    capital and fund future opportunities. There are times when the cost and
    access to these markets will vary. For example, the ability to issue new
    equity at a reasonable cost is strongly influenced by the equity market's
    perceptions of energy prices, macroeconomic factors, and Enerplus' future
    prospects. Similarly, the ability to increase bank credit or issue
    debentures is dependent on the overall state of the credit markets, as
    well as creditors' perceptions of the energy sector and Enerplus' credit
    quality. We intend to manage our distribution levels and capital spending
    in order to minimize increases in our debt levels and preserve our
    balance sheet strength for future acquisitions.

    Enerplus currently has an NAIC2 rating on the senior unsecured notes in
    the U.S. private debt markets.

    Acquisition & Divestment Activity
    ---------------------------------

    In periods of market uncertainty and volatility, it is important to have
    a conservative balance sheet and access to capital markets to take
    advantage of acquisition opportunities as they arise. The Fund attempts
    to manage its capital in a manner that reflects the likelihood and
    magnitude of potential acquisitions and/or opportunities to dispose of
    non-core assets.

    Enerplus was successful in disposing of its Joslyn interest during the
    third quarter of 2008. The net proceeds of $502.0 million were used to
    repay debt, reinforcing Enerplus' borrowing capacity and enhancing the
    ability to fund future capital spending and acquisition activity.

    Liability Maturity Analysis
    ---------------------------

    It is Enerplus' intention to renew the bank credit facility before or as
    it comes due. Similarly, Enerplus expects that the senior unsecured notes
    will be replaced with new notes or bank debt as they become due. Enerplus
    cannot currently predict with any certainty the terms or rates at which
    senior unsecured notes or bank debt will be obtained but we expect such
    terms and rates may be less favourable than current terms. Over the
    long-term, Enerplus expects to balance short-term credit requirements
    with bank debt and to look to the term debt markets for longer-term
    credit support.

    13. COMMITMENTS AND CONTINGENCIES

    (a) Pipeline Transportation

    Enerplus has contracted to transport 143 MMcf/day of natural gas on the
    TransCanada system in Alberta, 70 MMcf/day on TransGas in Saskatchewan,
    48 MMcf/day in B.C.via Spectra, as well as 9 MMcf/day on the Alliance
    pipeline to the U.S. midwest.

    In addition, Enerplus 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.

    (b) Office Lease

    Enerplus has office lease commitments for both its Canadian and U.S.
    operations that expire in 2014 and 2011 respectively. Annual costs of
    these lease commitments include rent and operating fees.

    (c) 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 the
    Fund's principal maturity analysis for the Fund's non-derivative
    financial liabilities at December 31, 2008:

                            Minimum Annual Commitment Each Year
    ($ thousands)           -----------------------------------
                        Total       2009      2010     2011
    --------------------------------------------------------------
    Accounts
     Payable(1)     $  272,818  $272,818  $      -  $     -
    Distributions
     payable to
     unit-
     holders(2)         41,397   41,397          -        -
    Bank credit
     facility          380,888        -    380,888        -
    Senior
     unsecured
     notes(3)          323,210        -     53,666   64,642
    Pipeline
     commitments        62,747    18,850    11,782    9,091
    Processing
     commitments        25,568     7,578     7,677    7,307
    Office leases       69,586     8,730    11,736   12,478
    --------------------------------------------------------------
    Total
     commitments    $1,176,214  $349,373  $465,749  $93,518
    --------------------------------------------------------------
    --------------------------------------------------------------

                 Minimum Annual Commitment Each Year     Total
    ($ thousands) ---------------------------------- Committed
                                2012     2013       after 2013
    -----------------------------------------------------------
    Accounts
     Payable(1)             $      -  $     -      $        -
    Distributions
     payable to
     unit-
     holders(2)                   -        -               -
    Bank credit
     facility                     -        -               -
    Senior
     unsecured
     notes(3)                64,642    64,642         75,618
    Pipeline
     commitments              6,751    5,369          10,904
    Processing
     commitments              3,006        -               -
    Office leases            12,563   12,563          11,516
    ----------------------------------------------------------
    Total
     commitments           $ 86,962  $82,574         $98,038
    --------------------------------------------------------------
    --------------------------------------------------------------
    (1) Accounts payable are generally settled between 30 and 90 days from
        the balance sheet date.
    (2) Distributions payable to unitholders are paid on the 20th day of the
        month following the balance sheet date.
    (3) 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.

    14. GEOGRAPHICAL INFORMATION

    As at December 31, 2008
    ($ thousands)                           Canada         U.S.        Total
    -------------------------------------------------------------------------
    Oil and gas revenue               $  1,968,865  $  363,019  $  2,331,884
    Capital assets                       4,552,482     694,515     5,246,998
    Goodwill                               451,120     182,903       634,023
    -------------------------------------------------------------------------

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


    5 YEAR DETAILED STATISTICAL REVIEW

    ($ thousands,
     except per
     unit amounts)      2008        2007        2006        2005        2004
    -------------------------------------------------------------------------
    Financial
    Oil and gas
     sales(1)     $2,370,668  $1,464,214  $1,569,487  $1,413,734  $  989,266
    Cash flow
     from
     operating
     activities    1,262,782     868,548     863,696     774,633     555,060
    Cash
     distributions
     to unitholders  786,138     646,835     614,340     498,205     423,311
      Per unit          4.89        5.04        5.04        4.47        4.20
    Cash withheld
     for
     acquisitions
     and Capital
     Expenditures    476,644     221,713     249,356     276,428     113,248
    Development
     capital
     spending        577,739     387,165     491,226     368,689     206,874
    Acquisitions   1,772,826     274,244      51,313     704,028     636,326
    Divestments      504,859       9,572      21,127      66,511      31,742
    Total net
     capital
     expenditures  1,856,305     658,327     526,387   1,010,549     813,636
    Total assets   6,230,132   4,303,130   4,203,804   4,130,623   3,180,748
    Long-term debt,
     net of cash     657,421     724,975     679,650     649,825     584,991
    Payout ratio(2)       62%         74%         71%         64%         76%
    -------------------------------------------------------------------------
    Net debt/cash
     flow ratio          0.5x        0.8x        0.8x        0.8x        1.1x
    -------------------------------------------------------------------------

    Trust Unit Trading
     Information
    Toronto Stock
     Exchange trading
     summary
      Close           $23.96      $39.87      $50.68      $55.86      $43.60
      Volume         127.679      96,898      82,120      62,278      52,821
    New York Stock
     Exchange trading
     summary
      Close           $19.58      $40.05      $43.61      $47.98      $36.31
      Volume          97.164      54.192      81,677      70,454      67,570
    Weighted average
     number of units
     outstanding
     (basic)         160,589     127,691     121,588     109,083      99,273
    Number of units
     outstanding at
     December 31     165,590     129,813     123,151     117,539     104,124
    -------------------------------------------------------------------------

    -------------------------------------------------------------------------
    Average
     Benchmark
     Pricing
    AECO natural gas
     (per Mcf)         $8.13       $6.61       $6.99       $8.48       $6.79
    NYMEX natural gas
     (US$ per Mcf)      8.93        6.92        7.26        8.55        6.09
    WTI crude oil
     (US$ per bbl)     99.65       72.34       66.22       56.56       41.40
    CDN$/US$
     exchange rate      0.94        0.93        0.88        0.83        0.77
    -------------------------------------------------------------------------
    ($ per BOE except
     percentage data)
    -------------------------------------------------------------------------
    Oil and Gas
     Economics
    Net royalty
     rate                 19%         19%         19%         19%         21%
    Weighted average
     price(3)         $65.79      $50.48      $50.23      $52.36      $40.90
    Hedging(4)         (2.94)       0.45       (1.10)      (4.90)      (3.50)
    -------------------------------------------------------------------------
    Weighted average
     price(1)          62.85       50.93       49.13       47.46       37.40
    Net royalty
     expense           12.27        9.49        9.36       10.21        8.40
    Operating
     expense (4)        9.51        9.11        8.02        7.45        7.14
    -------------------------------------------------------------------------
    Operating netback  41.07       32.33       31.75       29.80       21.86
    General and
     administrative
     expense(4)         1.68        1.98        1.71        1.28        1.06
    Management fee         -           -           -           -           -
    Interest expense,
     net of interest
     and other
     income (4)         0.91        1.37        0.95        0.51        0.68
    Foreign exchange(4) 0.68        0.06       (0.02)       0.13       (0.01)
    Taxes               0.65        0.77        0.70        0.31        0.24
    Restoration and
     abandonment
     cash costs         0.52        0.54        0.37        0.27        0.25
    -------------------------------------------------------------------------
    Cash flow before
     changes in
     non-cash working
     capital          $36.63       $27.61     $28.04      $27.30      $19.64
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    (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.

                     2008(1)     2007(1)     2006(1)     2005(1)     2004(1)
    -------------------------------------------------------------------------
    Daily
     Production
    Oil Sands            n/a         n/a         n/a         n/a         n/a
    Crude Oil
     (bbls/day)       35,434      34,506      36,134      29,315      25,550
    NGLs (bbls/day)    4,529       4,104       4,483       4,689       4,398
    Natural Gas
     (Mcf/day)       346,439     262,254     270,972     274,336     271,091
    -------------------------------------------------------------------------
    BOE per day       97,702      82,319      85,779      79,727      75,130

    Drilling Activity
     (net wells)         643         252         361         393         367

    Success Rate          99%         99%         99%         99%         99%

    Production
     Replacement          78%         90%         82%        247%        384%

    Proved Reserves(2)
    Oil Sands              -       8,568       8,730       9,453         n/a
    Crude Oil (Mbls) 127,692     125,238     125,048     129,745     104,408
    NGLs (Mbbls)      13,052      11,785      12,690      13,084      12,776
    Natural Gas
     (MMcf)        1,066,534     866,077     920,061     965,776     971,598
    -------------------------------------------------------------------------
    MBOE             318,500     289,937     299,812     313,245     279,117
    -------------------------------------------------------------------------

    Probable
     Reserves(2)
    Oil Sands              -      54,930      47,998      43,700      47,747
    Crude Oil (Mbls)  38,931      35,504      34,421      31,567      26,783
    NGLs (Mbbls)       4,765       3,827       3,777       3,539       3,292
    Natural Gas
     (MMcf)          421,134     336,214     344,025     342,518     295,698
    -------------------------------------------------------------------------
    MBOE             113,885     150,297     143,533     135,892     127,105
    -------------------------------------------------------------------------

    Proved Plus
     Probable
     Reserves(2)
    Oil Sands              -      63,498      56,728      53,153      47,747
    Crude Oil
     (Mbls)          166,623     160,742     159,469     161,312     131,191
    NGLs (Mbbls)      17,817      15,612      16,467      16,623      16,068
    Natural Gas
     (MMcf)        1,487,668   1,202,291   1,264,086   1,308,294   1,267,296
    -------------------------------------------------------------------------
    MBOE             432,385     440,234     443,345     449,137     406,222
    -------------------------------------------------------------------------

    Reserve
     Life
     Index(3)
    Without Oil
     Sands:
    Proved (years)       9.4        10.0         9.8         9.6        10.1
    Proved Plus
     Probable (years)   12.1        12.8        12.2        12.0        12.4
    -------------------------------------------------------------------------

    With Oil Sands:
    Proved (years)       9.4        10.3        10.1         9.9        10.1
    Proved Plus
     Probable (years)   12.1        14.8        14.0        13.5        14.0
    -------------------------------------------------------------------------

    (1) Reserve information reflects NI 51-101 reporting methodology.
    (2) Company interest reserves consist of gross revenues (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.

    PRODUCTION AND RESERVES PER TRUST UNIT

    Production and reserves per unit are one measure of sustainability
    however they do not differentiate between the various commodity types
    and the quality of the reserves. 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. Our 2008 metrics have been impacted by the
    acquisition of Focus Energy Trust, the divestment of our Joslyn oil
    sands lease and negative reserve revisions.

    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.

    In 2008, our production per debt and distribution-adjusted unit declined
    by 6% due to the units issued as compared to the production added as a
    result of the Focus acquisition.

    Production per Debt and
     Distribution-Adjusted Trust Unit           2008        2007        2006
    -------------------------------------------------------------------------
    Average daily production                  95,687      82,319      85,779
    Debt-adjusted weighted average
     trust units (000's)                     182,401     142,666     132,208
    Production per debt-adjusted
     trust unit (BOE/unit)                     0.192       0.211       0.237
    Production per debt and distribution
     adjusted trust unit (BOE/unit)            0.368       0.392       0.390
    -------------------------------------------------------------------------

    Reserves per debt-adjusted trust unit are 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.

    During 2008 our reserves per debt and distribution-adjusted unit
    declined 25% compared to the prior year.  This was a significant change
    compared to historic performance.  Approximately 10% of the decline was
    directly attributable to the methodology associated with using a lower
    unit price at year end to convert debt to units.  As a result,
    additional notional trust units were required to replace long term debt,
    which negatively affects the debt and distribution-adjusted
    calculation.  A further 7% of the decrease was a result of fewer net
    reserve additions associated with our capital development program.  Our
    Focus acquisition and Joslyn disposition also reduced our debt and
    distribution-adjusted reserves per unit by 5% and 3% respectively.
    Focus was a strategic acquisition with significant development
    opportunity. Although Joslyn decreased our reserves per debt and
    distribution-adjusted unit, these reserves were lower quality bitumen
    which would have required significant future capital.  Furthermore, the
    Joslyn disposition increased our net asset value and balance sheet
    strength.

    Reserves per Debt and
     Distribution-Adjusted Trust Unit           2008        2007        2006
    -------------------------------------------------------------------------
    Year-end proved plus probable reserves   432,385     440,234     443,345
    Debt-adjusted trust units outstanding
     at year end (000's)                     193,029     147,997     136,562
    Reserves per debt-adjusted trust unit
     (BOE/unit)                                 2.24        2.97        3.25
    Reserves per debt and distribution
     adjusted trust unit (BOE/unit)             4.09        5.43        5.32
    -------------------------------------------------------------------------



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

SOURCES 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, 2008, 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 about March 16, 2009 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 a 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 prevailing commodity price environment, 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 project will proceed as described in this news release, although readers should consider the described uncertainties regarding SAGD expansion as described herein. However, there are a number of inherent risks and contingencies associated with the development of the Kirby project, 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 and Analysis section of this news release and under "Risk Factors" in the Fund's Annual Information Form (and corresponding Form 40-F) dated March 13, 2008, 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 2009. 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") currently 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 currently 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. 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", "guidance", "objective", "ongoing", "may", "will", "project", "should", "believe", "plans", "intends", "budget", "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 and capital resources; 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 lease; future acquisitions and dispositions; asset retirement obligations, 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 future trust or corporate structure of the Fund and its subsidiaries; 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 or, where applicable, assumed 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/or equity financing and cash flow to fund its capital and operating requirements as needed; 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, increased debt levels or debt service requirements; inaccurate estimation of the Fund's 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; reliance on industry partners; 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 and Form 40-F described above). 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 Enerplus Resources Fund %CIK: 0001126874

For further information:

For further information: Investor Relations at 1-800-319-6462 or email
investorrelations@enerplus.com


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